6.2.3 Hydraulic Oil System

6.2.3 Hydraulic Oil System
6.2.3.1 General
The Gas Turbine Combined Hydraulic and Lift Oil system functions to provide fluid power required for operating control components and to provide lift at the Gas Turbine and Generator bearings. The control components include the Gas Valves (hydraulically actuated servo valves) and the Inlet Guide Vanes-IGV’s (positioned by a hydraulic cylinder located on the turbine base), and on Dual Fuel Gas Turbine units.

The Liquid Fuel Valve (hydraulically actuated servo valve). The major components of the system include the pumps and motors, accumulator, filters, and valves contained in the manifold assembly as shown in Figure (6.5). This document will describe how the system normally operates.

6.2.3.2 Pump Inlet and Discharge

Pressure regulated, filtered, and cooled lubrication oil from the main lube oil header in the A160 is used as the hydraulic/lift oil, high-pressure fluid. The system is designed with two redundant parallel flow paths. Under normal operation, only one circuit on the system is in use. Isolation valves are used to isolate either of the circuits so that maintenance can be performed on or off line.
 On the inlet to the system, pressure switches (63HQ-6A, 63HQ-6B) signal an alarm, which prevents the hydraulic/lift pump motors (88HQ-1, 88HQ-2) from starting should there be insufficient inlet pressure. This feature will prevent the pumps from cavitations. High-pressure fluid is then pumped to the supply manifold by one of the two pressure-compensated, variable displacement pumps (PH1-1, PH2-1).

 Each pump is driven by its own AC electric motor. The turbine operator controls the lead-lag sequence on the pumps. The pumps are constant pressure, variable positive displacement axial piston pumps with built in dual pressure compensators (VPR3-1, VPR3-2). The compensators act by varying the stroke of the pistons to maintain a set pump discharge. Each pump has a high and low-pressure compensator setting. The high-pressure setting is used when lift oil supply to the rotor bearings is needed. The low pressure setting is used when actuation of the gas valves and IGV’s is required.

 Each pump/motor contains a heater, (23HQ-1, 23HQ-2), which prevents condensation and freezing while the motors are not running. Air bleed valves are located immediately downstream of the pump discharge to ensure rapid pressurization of the supply fluid. Each circuit contains an oil filter (FH2-1, FH2-2) with integral differential pressure switches (63HF-1, 63HF-2). Hydraulic/lift oil supply pressure relief valves (VR21-1, VR22-1) provide pressure relief in order to prevent component failure due to over-pressurization, in the event that one of the pressure compensators fail or are inadvertently set wrong.

 6.2.3.3 Lift Oil Supply
Bearing lift oil is used to raise the turbine-generator rotor onto a thin, static oil film at each journal bearing to minimize rotation friction losses the gas turbine starting means or turning   gear must overcome. Lift oil supply isolation valve (20QB-1) is a solenoid-operated valve. When energized, high-pressure oil is allowed to flow to each of the turbine-generator bearings. Each bearing is equipped with a flow-regulating valve to keep lift oil supply flow rate constant.

In addition, the lift oil supply lines at the bearings contain check valves to prevent bearing feed oil from back flowing into lift oil supply lines. 20QB-1 has a manual override to be used if the solenoid fails. There is also a sensing line connected from downstream of the solenoid to the compensator block.

When the solenoid is open, the sensing line is pressurized, thus selecting the high-pressure setting. Bearing Lift Oil Supply Pressure Switch (63QB-1) provides an alarm in the turbine control system if lift oil supply pressure is low, and will prevent the turning gear motor from starting should there be insufficient pressure.

 6.2.3.4 Hydraulic Oil Supply
 Hydraulic Supply pressure is required to actuate the gas valves, IGV’s, and liquid fuel valve (for Dual Fuel units only). Each pump circuit contains a Hydraulic Oil Supply Pressure Regulating Valve (VPR4-3, VPR4-4). These pressure-regulating valves maintain hydraulic pressure to hydraulic actuated components during normal operation, regardless of whether the pump is operating at lift pressure or hydraulic pressure.

 Hydraulic Discharge Oil Supply Pressure Switches (63HQ-1A, 63HQ-1B) are used to indicate if the lead pump is not supplying enough pressure to the system. Should this be the case, the lag pump will be activated. Hydraulic Supply Low Pressure Relief Valve (VR23-2) is provided to prevent over-pressurization of hydraulic supply components in the event pressure regulating valves fail or are set incorrectly.

 Off of the hydraulic oil supply header is a single Accumulator (AH1-1) that stores hydraulic fluid for use in transient's condition (e.g. valve actuation). The accumulator is in-service regardless of which pump is in operation. The accumulator contains an isolation valve and flow control valve to control recharge rate as shown in Figure (6.6). A Manual Bypass Valve allows the operator to quickly depressurize and drain hydraulic oil supply header. This is useful when resetting pump compensators, relief valves, or pressure regulators. The bypass valve also serves as an accumulator drain valve.

6.2.2.2 Heat Exchanger and Filters

6.2.2.2 Heat Exchanger and Filters
The lubricant oil heat exchangers (LOHX-1 and LOHX-2) connect to the parallel lubricant filters (LF3-1 and LF3-2). This design is provided so that filters not in service can be changed (or heat exchangers cleaned) without taking the turbine out of service. Filter housings and heat exchangers are self-venting. A sight glass is located in the vent line from the filter and heat exchanger.

When the heat exchanger and filter housing are full, oil will be visible in this sight glass. By means of the manually-operated three-way transfer valve, one filter can be put into service as the Second is taken out, without interrupting the oil flow to the main lube oil header. The transfer of operation from one filter to the other should be accomplished as follows:
1. Open the filler valve and fill the standby filter until a solid oil flow can be seen in the flow sight in the filter vent pipe. This will indicate a “filled” condition.
2. Operate the transfer valve to bring the standby filter into service.
3. Close the filler valve. This procedure simultaneously brings the reserve heat exchanger into service.

6.2.2.3 Pressure Protection Devices
Two pressure switches (63QA-1A and -1B) mounted on the main pump discharge header sense lube oil pressure. If either of these senses low lubricant oil pressure, an alarm is sounded and the lag pump is automatically started. Pressure switches 63QT-2A and -2B in combination with alarm switches 63QA-1A and 63QA-1B trip the unit and start the emergency DC motor-driven pump (88QE-1) when they sense low pressure.

This will occur if AC power is lost. For a trip, one of the two 63QT switches and one of the two 63QA switches must signal. This voting logic prevents a trip due to a false signal. The DC Emergency Pump is designed to provide adequate lube oil circulation for coast down following a trip. Once the unit is at rest, the DC pump should only operate a few minutes per hour, in order to remove heat, but conserve battery life. If the bearing metal temperature is above 250F, the DC pump is run.

Continuously, the emergency pump is sized to clear the trip pressure switches (63QT-2A, - 2B), but will not clear the alarm pressure level (63QA-1A, -1B). On dual fuel units with a single atomizing air compressor pressure switch (63QA-3) is provided at the oil supply to the air compressor gearbox. Two Pressure switches (63QA-3 and 4) are provided on dual fuel units with two atomizing air compressors. These pressure switches will alarm if low pressure is sensed at those points but they will not start the Lag pump.

The operation of the 63QA and 63QT switches can be verified by shutting off the normally open valve between the switch and the oil system. When the normally closed valve to the oil drain is opened, the Oil in the switch lines will drain, the proper warning signal will annunciate and proper lag/emergency pump start-up should occur.

6.2.2 Functional Description

6.2.2 Functional Description
6.2.2.1 Lubricant Reservoir and Piping
The oil reservoir is a 2600 gallon (9843 liter) tank which is integral with the module. The interior of the tank is coated with an oil resistant protective coating. The top of the tank is the base on which components such as the pumps, and heat exchangers are mounted. Under normal operating conditions oil is provided to the system by one of two main AC motor driven centrifugal pumps (PQ1-1 and PQ1-2). The selection of lead and lag pumps is made by the operator through the turbine control system prior to startup.

By alternating the lead/lag pump selection, the operating hours can be equalized. Each AC motor includes a motor space heater (23QA-1 and -2) to prevent condensation in the motor. All pumps have a check valve on the discharge line so that oil does not flow into the tank through a pump, which is not in service. Two pressure switches (63QA-1A and -1B) are mounted in the common header just downstream of the main pumps to ensure proper pump operation. If either of these senses low pressure, an alarm is sounded and the lag pump is automatically started.

If this occurs, the operator must manually shut off one pump and check that system pressure is stable. The oil is first pumped through one of the two parallel proper bearing header temperatures. The maximum allowable bearing header temperature under normal operating conditions is 160F (71.1̊C). The oil then flows through one of the two full flow parallel filters (LF3-1 and LF3-2). A three-way transfer valve controls selection of which set of heat exchanger/filter is in use. The lubricant oil filters have removable filter elements.

A differential pressure gauge provides visual indication of the dP over the filter. Pressure switches (63QQ-21, -22) provide a high differential pressure alarm signal across each filter. Filter elements should be replaced near or at the alarm set point as shown in Figure (6.4). Taps (OS), (OR-1) and (OLT-1), which are located downstream of the filters, supply lube oil to the generator bearing seals,hydraulic/lift oil system and trip oil system respectively. Pressure regulating valve (VPR2-1) then controls the oil pressure to the turbine and generator bearings and the turning gear.

The system is ventilated through a mist eliminator mounted on top of the lube oil reservoir. A slight negative pressure is maintained in the system by redundant motor driven fans (88QV-1A and 88QV-1B) pulling air through the mist eliminator. This negative pressure draws sealing air through the gas turbine bearing seals.

Each AC motor includes a motor space heater (23QV-2A and 23QV-2B) to prevent condensation in the motor. The motor driven fans have no DC backup motors and are not required to run in the emergency situation, when the DC pumps has taken over. The fans are set up to run in a lead/lag configuration and are designed to run one at a time.

The selection of lead and lag fans is made by the operator through the turbine control system prior to startup. The lag fan takes over whenever the lead fan has failed to run, has been overloaded or if there is insufficient vacuum in the lube oil reservoir. If the lag fan is started automatically by the control system due to insufficient tank vacuum level, the lead fan will be automatically shut off. Pressure switch (63QV-1) provides a low differential pressure alarm signal when there is insufficient vacuum in the lube oil reservoir. A regulating valve is downstream of each fan, and is adjusted to regulate tank vacuum level.

A level alarm device (float operated) is mounted on the top or side of the lube reservoir. The float mechanism operates two level switches (71QH-1 and 71QL-1). The switches are connected into the alarm circuit of the turbine control panel to initiate an alarm if the liquid level rises above, or fall below, the levels shown on the Schematic Piping Diagram. The oil level is visually indicated by a gauge on the side of the tank. An oil drain connection is located on the side of the accessory module to drain the reservoir.

6.2 LUBRICATION SYSTEM

6.2 LUBRICATION SYSTEM
6.2.1 Lube Oil System
The lubricating and hydraulic oil requirements for the gas turbine power plant are furnished by a separate, enclosed, forced-feed lubrication module. This lubrication module, complete with tank, pumps, coolers, filters, valves and various control and protection devices, furnishes oil to the gas turbine bearings, generator bearings (absorbing the heat rejection load), starting means, load gear and on dual fuel units the atomizing air/purge compressors as shown in Figure. (6.2) and Figure. (6.3). This module is also used to supply oil for the lift oil system, trip oil system and the hydrogen seals on the generator.

Additionally, a portion of the pressurized fluid is diverted and filtered again for use by hydraulic control devices as control fluid. Refer to “Lubricating Oil Recommendations for Gas Turbines with Bearing Ambient above 500F (260C)” in the fluid specifications section of this manual for the lubricating oil requirements. The lubrication system is designed to supply filtered lubricant at the proper temperature and pressure for operation of the turbine and its associated equipment. Refer to the Lube Oil Schematic Piping Diagram in this section. Major system components include:

1. Lubricant oil reservoir which serves as a base for the accessory module.
2. Two centrifugal pumps (PQ1-1 and PQ1-2) each driven by an AC electrical motor (88QA-1 and 88QA-2). Each AC motor includes a motor space heater (23QA-1 and -2) to prevent condensation in the motor.
3. Emergency oil pump (PQ2-1) with DC motor (88QE-1)
4. Main Seal oil pump (PQ3-1) driven by AC motor (88QS-1). AC motor includes motor space heater (23QS-1).
5. Emergency seal oil pump driven by DC motor (88ES-1). Note, in most instances PQ3-1 is a “piggy-back” AC/DC motor driving one pump. If the Customer has opted to purchase separate AC and DC seal oil pumps, the separate DC pump will be named PQ3-2.
6. Dual lubricating oil heat exchangers in parallel (LOHX-1 and LOHX-2).
7. Two full flow lubricating oil filters in parallel (LF3-1 and LF3-2).
8. Bearing header pressure regulator (VPR2-1).
9. Mist eliminator with redundant fan/motor (88QV-1A and 88QV-1B) and motor space heaters (23QV-2A and 23QV-2B).
10. Pressure Protection Switches (63QA-1A, 63QA-1B, 63QE-1, 63QT-2A and 63QT-2B and on units with liquid fuel 63QA-3).
11. Tank temperature switches (26QL-1, 26QN-1) or tank temperature thermocouples (LT-OT-4A, LT-OT-5A) for pump start permissive and immersion heater control.
12. Lube oil header thermocouples (LT-TH-1A, 1B, 2A, 2B, 3A, 3B).
13. Lube oil drain thermocouples (LT-B1D-1A/1B, LT-B2D-1A/1B, LT-G1D-1A/1B and LT-B2D-1A/1B). Note that LT-B1D-1A/1B and LT-B2D–1A/1B may be single thermocouples named LT-B1D-1 and LT-B2D-1 on some units. The lube oil is circulated by a redundant set of AC pumps. A DC pump is provided in case AC power to the site is interrupted. These pumps are the first of the auxiliary equipment to be energized during a startup.

Sequence. Following shutdown of the unit, these pumps continue to run throughout the extensive cool down period and are the last of the auxiliary equipment to be stopped. The lube oil system is self-contained. After Lubricating and removing heat from the rotating equipment, oil is returned to the lube oil tank. It is cooled by oil-to-water heat exchangers as it is pumped from the tank and re-circulated. Various sensing devices are Included in the design to ensure adequate oil level in the tank, oil pressure, and oil temperature.

All pumps have a check valve on the pump discharge line so that oil does not flow into the tank through a pump, which is not in service. Oil tank temperature is indicated by a thermometer on the side of the tank. Thermocouples connected to the control panel indicate lube oil temperature in the bearing header. Thermocouples in the bearing drains are also wired to the turbine control panel for monitoring. A bearing header oil sampling port is located upstream of VPR2-1.

For turbine starting, a maximum oil viscosity of 800 SUS (173 centistokes) is specified for reliable operation of the control system and for bearing lubrication. Temperature switch 26QN-1 or LT-OT-4A prevents turbine startup if the temperature of the lubricant decreases to a point where oil viscosity exceeds 800 SUS (173 centistokes).

6.1.3 Purge Air System

As stated above, the bypass valve is open and atomizing air is recalculating. After a short time delay, to allow the pressure ratio (regulated by valve YPR54) of the atomizing air system to reach a lower level, solenoid valve 20PL-l is energized. The system then starts operating to purge the oil passages in the oil fuel nozzles during gas fuel operation. The purge air system is necessary to prevent of oil fuel in the nozzle oil passages, during gas fuel operation, and in of the nozzles as a result of oil fuel cooking. The purge system minimizes such fouling, and keeps the oil fuel nozzle clean and ready for operation when oil fuel operation is resumed.

The small flow of air through the atomizing air passages of the oil fuel nozzle also prevents entry of any combustion products that could foul this section of the oil fuel nozzle. When solenoid valve 20PL-1 is energized, operating air (from the turbine compressor discharge) is admitted to the diaphragm of purge air valve VA19 which opens, allowing purge air (atomized) to flow into the purge air manifold on the turbine. A porous filter (FA3) is installed in the purge air check valves, one for each nozzle, are connected into the oil feed lines to the nozzles.

These purge air check valves prevent oil fuel from entering the purge air system when the machine is operating on oil fuel. Similarly, the oil fuel check valves installed in the oil piping to the oil fuel, it will drain out of the purge air manifold through the normally open port of the three-way purge air valve. “Tell-Tale” leak-off piping connected to the purge valve vent port provides a visual means for determining the general condition of the check valves. There should not be any leakage.

6.1.4 Water Wash Provisions
When water washing the gas turbine’s compressor section and turbine sections it is important to keep water out of the atomizing air system. To keep water out of the atomizing air system, the system inlet and discharge are equipped with vent valves and an isolation valve or full area spacers. The vent valves are used to avoid completely throttling or deadening the compressors, and the drain valves to remove any leakage past the isolation valves.

During normal operation of the gas turbine, the vent and drain valves must be closed and the isolation valves or spacers must be opened. Before initiating water wash, the isolation valve must be closed or blank area spacers installed to keep water out of the atomizing air system. The vent valves must be opened to allow air to pass through the atomizing air compressors.

CHAPTER 6 AUXILIARY SYSTEM AND LUBRICATION SYSTEM OF GAS TURBINE UNIT

6.1AUXILIARY SYSTEM
6.1.1 Atomizing Air System
Atomizing air systems provide sufficient pressure in the air atomizing chamber of the fuel nozzle body to maintain the ratio of atomizing air pressure to compressor discharge pressure at approximately 60% speed or greater over the full operating range of the turbine. Since the output of the main atomizing air compressor, driven by the accessory gear, is low at turbine firing speed, a starting atomizing air compressor provides a similar pressure ratio during the firing and warm-up period of the starting cycle, and during operation of the accelerating cycle.

Major system components include the main atomizing air compressor, starting atomizing air compressor and atomizing air heat exchanger. Refer to the Atomizing Air Schematic Piping Diagram in the Reference Drawings section of the Inspection and Maintenance volume as shown in Figure (6.1).

6.1.2 Functional Description
When liquid fuel oil is sprayed into the turbine combustion chambers it forms large droplets as it leaves the fuel nozzles. The droplets will not burn completely in the chambers and many could go out of the exhaust stack in this state. A low pressure atomizing air system is used to provide atomizing air through supplementary orifices in the fuel nozzle which directs the air to impinge upon the fuel jet discharging from each nozzle.

This stream of atomizing air breaks the fuel jet up into a fine mist, permitting ignition and combustion with significantly increased efficiency and a decrease of combustion particles discharging through the exhaust into the atmosphere. It is necessary, therefore, that the air atomizing system be operative from the time of ignition firing through acceleration, and through operation of the turbine.

Air taken from the atomizing air extraction manifold of the compressor discharge casing passes through the air-to water heat exchanger (pre cooler) HXl to reduce the temperature of the air sufficiently to maintain a uniform air inlet temperature to the atomizing air compressor.
The atomizing air pre cooler heat exchanger Located in the turbine base under the inlet plenum uses water from the turbine cooling water system as the cooling medium to dissipate the heat. Switch 26AA:"1 is an adjustable heat sensitive thermo switch provided to sound an alarm when the temperature of the air from the atomizing air pre cooler entering the main atomizing air compressor is excessive.

When the atomizing air reaches the temperature setting of this switch, the alarm is activated. Improper control of the temperature may be due to failure of the sensor, the pre cooler or insufficient cooling water flow. Continued operation above 275 F should not be permitted for any significant length of time since it may result in failure of the main atomizing air compressor or in insufficient atomizing air to provide proper combustion Compressor discharge air, now cleaned and cooled reaches the main atomizing air compressor. This is a single stage, flange mounted, centrifugal compressor driven by an inboard shaft of the turbine accessory gear.

It contains a single impeller mounted on the pinion shaft of the integral input speed-increasing gearbox driven directly by the accessory gear. Output of the main compressor provides sufficient air for atomizing and combustion when the turbine is at approximately 60-percent speed.

Differential pressure switch 63AD-1, located in a bypass around the compressor, monitors the air pressure and annunciates an alarm if the pressure rise across the compressor should drop to a level inadequate for proper atomization of the fuel. Air, now identified as atomizing air, valves the compressor and is piped to the atomizing air manifold with “pigtail” piping providing equal pressure distribution of atomizing air to the 10 individual fuel nozzles.
When the turbine is first fired, the accessory gear is not rotating at full speed and the main atomizing air compressor is not outputting sufficient air for proper fuel atomization. During this period, the starting (booster) atomizing air
compressor, driven by an electric motor is in operation supplying the necessary atomizing air. The starting atomizing air compressor at this time has a high-pressure ratio and is discharging through the main atomizing air compressor, which has a low-pressure ratio.

The main atomizing air compressor pressure ratio increases with increasing turbine speed and at approximately 60% speed the flow demand of the main atomizing air compressor approximates the maximum flow capability of the starting atomizing air compressor. The check valve in the air input line to the main compressor begins to open allowing air to be supplied to the main compressor simultaneously from both the main airline and the starting air compressor.

The pressure ratio of the starting atomizing air compressor decreases one, and when the turbine becomes self sustaining, the starting compressor is shut down at approximately 95 percent speed 4HS pickup. Now all of the air being supplied to the main compressor is directly from the pre cooler through the check valve, bypassing the starting air compressor completely. At this time the (20AB) solenoid is energized and the isolation valve (VA22) is closed preventing any air getting to the booster compressor.

5.4 FIRED SHUTDOWN

A normal shutdown is initiated by clicking on the “STOP” target (L1STOP) and “EXECUTE”; this will produce the L94X signal. If the generator breaker is closed when the stop signal is initiated, the Turbine Speed Reference (TNR) counts down to reduce load at the normal loading rate until the reverse power relay operates to open the generator breaker; TNR then continues to count down to reduce speed. When the STOP signal is given, shutdown Fuel Stroke Reference FSRSD is set equal to FSR.

When the generator breaker opens, FSRSD ramps from existing FSR down to a value equal to FSRMIN, the minimum fuel required to keep the turbine fired. FSRSD latches onto FSRMIN and de-creases with corrected speed. When turbine speed drops below a defined there's a hold (Control Constant K60RB) FSRSD ramp to a blowout of one flame detector.

The sequencing logic remembers which flame detectors were functional when the breaker opened. When any of the functional flame detectors senses a loss of flame, FSRMIN/FSRSD decreases at a higher rate until flame–out occurs, after which fuel flow is stopped. Fired shut down is an improvement over the former fuel shut off at L14HS drop out. By maintaining flame down to a lower speed there is significant reduction in the strain developed on the hot gas path parts at the time of fuel shut off.

5.5 SPEED CONTROL
The Speed Control System controls the speed and load of the gas turbine generator in response to the actual turbine speed signal and the called–for speed reference. While on speed control the control mode message “SPEED CTRL” will be displayed.

5.5.1 Speed Signal
Three magnetic sensors are used to measure the speed of the turbine. These magnetic pickup sensors (77NH–1,–2,–3) are high output devices consisting of a permanent magnet surrounded by a hermetically sealed case. The pickups are mounted in a ring around a 60–toothed wheel on the gas turbine compressor rotor. With the 60–tooth wheel, the frequency of the voltage output in Hertz is exactly equal to the speed of the turbine in revolutions per minute.

The voltage output is affected by the clearance between the teeth of the wheel and the tip of the magnetic pickup. Clearance between the outside diameter of the toothed wheel and the tip of the magnetic pickup should be kept within the limits specified in the Control Specifications (approx. 0.05 inch or 1.27 mm). If the clearance is not maintained within the specified limits, the pulse signal can be distorted. Turbine speed control would then operate in response to the incorrect speed feedback signal. The signal from the magnetic pickups is brought into the Mark VI panel, one mag pickup to each controller <RST>, where it is monitored by the speed control software.

5.5.2 Speed/Load Reference

speed control software will change FSR in proportion to the difference between the actual turbine–generator speed (TNH) and the called–for speed reference (TNR). The called–for–speed, TNR, determines the load of the turbine. The range for generator drive turbines is normally from 95% (min.) to 107% (max.) speed. The start–up speed reference is 100.3% and is preset when a “START” signal is given.

The turbine follows to 100.3% TNH for synchronization. At this point the operator can raise or lower TNR, in turn raising or lowering TNH, via the 70R4CS switch on the generator control panel or by clicking on the targets on the <HMI>, if required. Refer to Figure (5.4). Once the generator breaker is closed onto the power grid, the speed is held constant by the grid frequency. Fuel flow in excess of that necessary to maintain full speed no load will result in increased power produced by the generator. Thus the speed control loop becomes a load control loop and the speed reference is a convenient control of the desired amount of load to be applied to the turbine–generator unit.

Droop speed control is a proportional control, changing FSR in proportion to the difference between actual turbine speed and the speed reference. Any change in actual speed (grid frequency) will cause a proportional change in unit load. This proportionality is adjustable to the desired regulation or “Droop”. The speed vs. FSR relationship is shown on Figure (5.5). If the entire grid system tends to be overloaded, grid frequency (or speed) will decrease and cause an FSR increase in proportion to the droop setting. If all units have the same droop, all will share a load increase equally. Load sharing and system stability are the main advantages of this method of speed control.

Normally 4% droop is selected and the set point is calibrated such that 104% set point will generate a speed reference which will produce an FSR resulting in base load at design ambient temperature. When operating on droop control, the full–speed–no–load FSR setting calls for a fuel flow which is sufficient to maintain full speed with no generator load. By closing the generator breaker and raising TNR via raise/lower, the error between speed and reference is increased. This error is multiplied by a gain constant dependent on the desired droop setting and added to the FSNL FSR setting to produce the required FSR to take more load and thus assist in holding the system frequency. Refer to Figures (5.5) and (5.6).


The minimum FSR limit (FSRMIN) in the SPEEDTRONIC Mark VI system prevents the speed control circuits from driving the FSR below the value which would cause flameout during a transient condition. For example, with a sudden rejection of load on the turbine, the speed control system loop would want to drive the FSR signal to zero, but the minimum FSR setting establishes the minimum fuel level that prevents a flameout. Temperature and/or start–up control can drive FSR to zero and are not influenced by FSRMIN.

 5.6 ACCELERATION CONTROL
 Acceleration control compares the present value of the speed signal with the value at the last sample time. The difference between these two numbers is a measure of the acceleration. If the actual acceleration is greater than the acceleration reference, FSRACC is reduced, which will reduce FSR, and consequently the fuel to the gas turbine. During start–up the acceleration reference is a function of turbine speed; acceleration control usually takes over from speed control shortly after the warm–up period and brings the unit to speed. At “Complete Sequence”, which is normally 14HS pick–up, the acceleration reference is a Control Constant, normally 1% speed/second. After the unit has reached 100% TNH, acceleration control usually serves only to contain the unit‟s speed if the generator breaker should open while under load.

5.3 START–UP CONTROL

The start–up control operates as an open loop control using preset levels of the fuel command signal FSR. The levels are: “ZERO”, “FIRE”, “WARM–UP”, “ACCELERATE” and “MAX”. The Control Specifications provide proper settings calculated for the fuel anticipated at the site. The FSR levels are set as Control Constants in the SPEEDTRONIC Mark VI start–up control. Start–up control FSR signals operate through the minimum value gate to ensure that other control functions can limit FSR as required.

The fuel command signals are generated by the SPEEDTRONIC control start–up software. In addition to the three active start–up levels, the software sets maximum and minimum FSR and provides for manual control of FSR. Clicking on the targets for “MAN FSR CONTROL” and “FSR GAG RAISE OR LOWER” allows manual adjustment of FSR setting between FSRMIN and FSRMAX.

While the turbine is at rest, electronic checks are made of the fuel system stop and control valves, the accessories, and the voltage supplies. At this time, “SHUTDOWN STATUS” will be displayed on the <HMI>. Activating the Master Operation Switch (L43) from “OFF” to an operating mode will activate the ready circuit. If all protective circuits and trip latches are reset, the “STARTUP STATUS” and “READY TO START” messages will be displayed, indicating that the turbine will accept a start signal. Clicking on the “START” Master Control Switch (L1S) and “EXECUTE” will introduce the start signal to the logic sequence.
The start signal energizes the Master Control and Protection circuit (the “L4” circuit) and starts the necessary auxiliary equipment. The “L4” circuit permits pressurization of the trip oil system. With the “L4” circuit permissive and starting clutch automatically engaged, the starting device starts turning. Startup status message “STARTING” will be displayed on the <HMI>. See point “A” on the Typical Start–up Curve Figure (5.4). The starting clutch is a positive tooth type overrunning clutch which is self–engaging in the breakaway mode and overruns whenever the turbine rotor exceeds the turning gear speed.

When the turbine „breaks away‟ the turning gear will rotate the turbine rotor from 5 to 7 rpm. As the static starter begins its sequence, and accelerates the rotor the starting clutch will automatically disengage the turning gear from the turbine rotor. The turbine speed relay L14HM indicates that the turbine is turning at the speed required for proper purging and ignition in the combustors. Gas fired units that have exhaust configurations which can trap gas leakage (i.e., boilers) have a purge timer, L2TV, which is initiated with the L14HM signal.

The purge time is set to allow three to four changes of air through the unit to ensure that any combustible mixture has been purged from the system. The starting means will hold speed until L2TV has completed its cycle. Units which do not have extensive exhaust systems may not have a purge timer, but rely on the starting cycle and natural draft to purge the system.

The L14HM signal or completion of the purge cycle (L2TVX) „enables‟ fuel flow, ignition, sets firing level FSR, and initiates the firing timer L2F. See point “B” on Figure (5.4). When the flame detector output signals indicate flame has been established in the combustors (L28FD), the warm–up timer L2W starts and the fuel command signal is reduced to the “WARM–UP” FSR level. The warm–up time is provided to minimize the thermal stresses of the hot gas path parts during the initial part of the start–up.

If flame is not established by the time the L2F timer times out, typically 60 seconds, fuel flow is halted. The unit can be given another start signal, but firing will be delayed by the L2TV timer to avoid fuel accumulation in successive attempts. This sequence occurs even on units not requiring initial L2TV purge. At the completion of the warm–up period (L2WX), the start–up control ramps FSR at a predetermined rate to the setting for “ACCELERATE LIMIT”. The start–up cycle has been designed to moderate the highest firing temperature produced during acceleration. This is done by programming a slow rise in FSR. See point “C” on Figure (5.4).

As fuel is increased, the turbine begins the acceleration phase of start–up. The clutch is held in as long as the turning gear provides torque to the gas turbine. When the turbine overruns the turning gear, the clutch will disengage, shutting down the turning gear. Speed relay L14HA indicates the turbine is accelerating.

start–up phase ends when the unit attains full–speed–no–load (see point “D” on Figure (5.4). FSR is then controlled by the speed loop and the auxiliary systems are automatically shut down. The start–up control software establishes the maximum allowable levels of FSR signals during start–up. As stated before, other control circuits are able to reduce and modulate FSR to perform their control functions. In the acceleration phase of the start–up, FSR control usually passes to acceleration control, which monitors the rate of rotor acceleration. It is possible, but not normal, to reach the temperature control limit. The <HMI> display will show which parameter is limiting or controlling FSR.

CHAPTER 5 FUNDAMENTALS OF SPEEDTRONIC MARK VI CONTROL SYSTEM

5.1 GENERAL
Speedtronic Mark VI Control contains a number of control, protection and sequencing systems designed for reliable and safe operation of the gas turbine. It is the objective of this chapter to describe how the gas turbine control requirements are met, using simplified block diagrams as shown in Figure (5.1) and one–line diagrams of the SPEEDTRONIC Mark VI control, protection, and sequencing systems. A generator drive gas turbine is used as the reference.

5.2 CONTROL SYSTEM
5.2.1 Basic Design
Control of the gas turbine is done by the startup, acceleration, speed, temperature, shutdown, and manual control functions illustrated in Figure (5.1). Sensors monitor turbine speed, exhaust temperature, compressor discharge pressure, and other parameters to determine the operating conditions of the unit. When it is necessary to alter the turbine operating conditions because of changes in load or ambient conditions, the control modulates the flow of fuel to the gas turbine. For example, if the exhaust temperature tends to exceed its allowable value for a given operating condition, the temperature control system reduces the fuel supplied to the turbine and thereby limits the exhaust temperature.

Operating conditions of the turbine are sensed and utilized as feedback signals to the speedtronic control system. There are three major control loops – startup, speed, and temperature – which may be in control during turbine operation. The output of these control loops is connected to a minimum value gate circuit as shown in Figure (5.2). The secondary control modes of acceleration, manual FSR, and shutdown operate in a similar manner.

Fuel Stroke Reference (FSR) is the command signal for fuel flow. The minimum value select gate connects the output signals of the six control modes to the FSR controller; the lowest FSR output of the six control loops is allowed to pass through the gate to the fuel control system as the controlling FSR. The controlling 
FSR will establish the fuel input to the turbine at the rate required by the system which is in control. Only one control loop will be in control at any particular time and the control loop which is controlling FSR will be displayed on the <HMI>. Figure (5.3) shows a more detailed schematic of the control loops. This can be referenced during the explanation of each loop to show the interfacing.

5.2.2 Start–up/Shutdown Sequence and Control
Start–up control brings the gas turbine from zero speed up to operating speed safely by providing proper fuel to establish flame, accelerate the turbine, and to do it in such a manner as to minimize the low cycle fatigue of the hot gas path parts during the sequence. This involves proper sequencing of command signals to the accessories, starting device and fuel control system. Since a safe and successful start–up depends on proper functioning of the gas turbine equipment, it is important to verify the state of selected devices in the sequence.
Much of the control logic circuitry is associated not only with actuating control devices, but enabling protective circuits and obtaining permissive conditions before proceeding. The gas turbine uses a static start system whereby the generator serves as a starting motor. A turning gear is used for rotor breakaway General values for control settings are given in this description to help in the understanding of the operating system. Actual values for control settings are given in the Control Specifications for a particular machine.

5.2.3 Speed Detectors
5.2.3 Speed Detectors
An important part of the start–up/shutdown sequence control of the gas turbine is proper speed sensing. Turbine speed is measured by magnetic pickups and will be discussed under speed control. The following speed detectors and speed relays are typically used:
–L14HR Zero–Speed (approx. 0% speed)
–L14HM Minimum Speed (approx. 16% speeds)
–L14HA Accelerating Speed (approx. 50% speeds)
–L14HS Operating Speed (approx. 95% speed)
The zero–speed detector, L14HR, provides the signal when the turbine shaft starts or stops rotating. When the shaft speed is below 14HR, or at zero–speed, L14HR picks–up (fail safe) and the permissive logic initiates turning gear or slow–roll operation during the automatic start–up sequence of the turbine.
The minimum speed detector L14HM indicates that the turbine has reached the minimum firing speed and initiates the purge cycle prior to the introduction of fuel and ignition. The dropout of the L14HM minimum speed relay provides several permissive functions in the restarting of the gas turbine after shutdown.

The accelerating speed relay L14HA pickup indicates when the turbine has reached approximately 50 percent speeds; this indicates that turbine start–up is progressing and keys certain protective features. The high–speed sensor L14HS pickup indicates when the turbine is at speed and that the accelerating sequence is almost complete. This signal provides the logic for various control sequences such as stopping auxiliary lube oil pumps and starting turbine shell/exhaust frame blowers.

Should the turbine and generator slow during an under-frequency situation; L14HS will drop out at the under–frequency speed setting. After L14HS drops out the generator breaker will trip open and the Turbine Speed Reference (TNR) will be reset to 100.3%. As the turbine accelerates, L14HS will again pick up; the turbine will then require another start signal before the generator will attempt to auto–synchronize to the system again. The actual settings of the speed relays are listed in the Control Specification and are programmed in the <RST> processors as EEPROM control constants.

4.3 STEAM TURBO GENERATOR

4.3 STEAM TURBO GENERATOR
4.3.1 Turbo Generator
The purpose of the generator shown in Figure (4.14) is to convert the mechanical power delivered from the turbine to the rotor coupling into electrical power, in the form of voltage and current, at the main generator terminals. The generator is built to withstand a wide range of abnormal operating conditions including e.g. negative sequence loads and sudden short circuits.
The design described is of a two pole, full speed turbo-generator with hydrogen gas cooling of all internal components. The stator casing is firmly anchored to the foundation and carries the stator core and the stator winding. The casing has hydrogen-gas coolers arranged vertically in each corner. The stator end-shields close the stator casing and carry the shaft seals.
The rotor is rigidly coupled to the turbine, carries two single stage axial-flow fans for circulating the hydrogen-gas coolant inside the machine. The rotor runs on three separate pedestal bearings, which are rigidly fixed to the foundation and effectively decouple rotor and stator vibrations.
The electrical power is taken out at the main terminals of the generator. Each end of each phase is brought out. Access to the generator for inspection and service is provided via the cooler housings once the coolers are withdrawn. The pedestal bearings and the seals are readily accessible, not requiring any special tools for dismantling.

At major revisions the rotor can be withdrawn without taking off the end shields. Due to its simple design the whole rotor including the winding gas passages can be inspected. The two non-driven-end bearings are double-insulated to allow easy checking of the insulation during operation. The brushes can be changed during operation.

4.3.2 Cooling Of Turbo Generator

The generator is entirely cooled by hydrogen as primary coolant in a closed circuit. The heat is then transferred to the water circuit (secondary coolant) via the hydrogen/water coolers. The hydrogen is circulated by two axial fans mounted to the shaft. The hydrogen cooling system consists of two parallel cooling circuits symmetrical to the generator mid plane.

4.2.6 Condensate System

4.2.6 Condensate System
4.2.6.1 Description of the Condensate System
 The object of the condensate system is to condense the steam, and circulate the water back to the HRSG.
From the last stage of the steam turbine the steam is led to a condenser where it is condensed to water. From the condenser the condensate is pumped to the HRSG, passing the gland steam condenser.
Make-up water is added to compensate for any water losses. Condensate then flows through the condensate preheater (normal situation). Part of the water from the preheater outlet is recirculated to the condensate preheater inlet. By this way the minimum inlet temperature of the preheater is controlled above the water dew point of the flue gas. From the preheater, the condensate is lead to the deaerator.

4.2.6.2 Condensate Pumps
A total of two condensate pumps are installed. The pumps extract water from the condenser hot well and pressurize it. The pumps are equipped with a minimum flow line. During normal operation one pump will be in operation and the other will be standby. However when both IP bypass stations are in operation, both condensate pumps shall be in operation.

4.2.6.3 Condensate Preheater
The objective of the condensate preheater system is to heat condensate by means of heat from the gas turbine exhaust gas flow in the HRSG. Condensate from the condenser is supplied to per-heater.
Part of the water from the preheated outlet is recirculated to the condensate preheated inlet to maintain a minimum preheated inlet temperature. When the GT is running on solar oil, the preheater will be completely bypassed using the three way valve.

4.2.2 Reheat in Steam Turbine

4.2.2 Reheat in Steam Turbine
The steam turbine forms part of the steam-water circuit of a power plant. Thus, the turbine rating is mainly influenced by the steam conditions. As an example, a steam-water circuit is described by means of heat balance diagram as shown in Figure (4.12).

The live steam, coming from the boiler superheater, with a pressure of 120 bar and temperature of 560 oC expands in the HP turbine to an HP exhaust pressure of approx. 40 bar at 250 oC and is then led to the boiler re-heater, where it is heated-up again to approx. 540 oC. Re-heating of steam improves substantially the generation of water drops is shifted to lower pressures which results in minimizing the phenomenon of erosion in the turbine.

The hot re-heat steam is led from the re-heater to the IP turbine which can be of single or double flow design, depending on the turbine size. After being expanded in the IP turbine, the steam is led through cross over pipes to the LP turbine. For units larger than 200 MW, the LP turbines are of double flow design. Cold cooling water and, consequently, low exhaust steam pressures result in large volume flows and, therefore, two or three double Flow LP turbines are arranged at the shaft train.

After being expanded in the LP turbine, the steam is condensed in the condenser. The condensate is then pumped through the LP feed water heaters into the deaerator/feed water storage tank. Boiler feeds pumps pump the feed water through the LP feed water heaters back to the boiler. LP and HP feed water heaters improve the thermal efficiency of the steam cycle.

4.2.3 Lube Oil System for Steam Turbines
 During normal operation, the lube oil system is supplied by a gear type main oil pump, which is driven via a gear train from the turbine rotor. It is located in the front bearing pedestal. This self-priming pump has normally a maximal suction head of 5.5 m and takes the oil from the oil tank on an intermediate floor. Before being pumped to the bearings, the oil passes through the oil coolers. Valve on the oil and water-side allow the coolers to be changed over without interrupting the oil flow by regulating the oil flow through the coolers, the required bearing inlet oil temperature is maintained. Downstream of the coolers, two 100% capacity oil filters fitted in parallel are installed. Constant pressure valve controls the oil pressure upstream of the bearings. During start-up, shut down and turning gear operation, an auxiliary centrifugal pump Driven by an A/C. motor supplies oil. This pump will automatically be started when the oil Pressure drops below 60% of its design value or the turbine speed is below 90% of rated Speed. If the normal oil supply fails, an emergency centrifugal oil pump driven by a D/C motor.

Even if the auxiliary and emergency oil pumps should fail simultaneously, the danger of bearing damage due to lack of oil is extremely low, since the main oil pump which works in accordance with the positive displacement principle will continue to supply oil virtually until the rotor comes to rest. The oil vapor exhauster maintains a vacuum in the oil tank, the oil drain pipes and bearing pedestals. This not only effectively remotes the oil vapor from the tank, but also prevents oil from leaking past the bearing pedestal oil baffles.

4.2.4 Gland Steam System for Steam Turbines
The task of the gland steam can be summarized as follows it has to prevent:  that air is sucked into those turbine parts, which are under vacuum
 that steam from the turbine glands is blown into the enclosure
that gland steam temperature is kept within allowable limits

4.2.5 Condenser of Steam Turbine
The primary purpose of the condenser is to condensate the exhaust steam from low pressure turbine and thus recovers the high quality feed water for reuse in the cycle. If the circulating cooling water temperature is low enough it creates a low back pressure (vacuum) for the turbine to exhaust, this pressure is equal to the saturation pressure that corresponds to condensing steam temperature, which in turn is a function of cooling water temperature. There are primary two types of condensers: direct contact and surface contact which used in Cairo north power station as shown in Figure (4.13).

4.2.5.1 Large Surface Condensers

Large surface condensers are shell-and-tube heat exchangers of modular design, in which the primary heat transfer mechanisms are the condensing of saturated steam on the outside of the tubes and the forced convection heating of the circulating water inside the tubes. A Number of tube bundles, each resembling a church window in shape, are built into mostly a single housing. The bundle was configured on the basic of comprehensive tests with analogue models.

4.2 STEAM TURBINE

4.2.1 Steam Turbine Description
 Steam turbine takes the steam from HRSG and converts its energy (thermal and kinetic) into rotational mechanical energy. The steam turbine consist of high pressure turbine, intermediate pressure turbine and low pressure turbine .the condenser condensate the steam from LPT and the turbine shaft connected with generator to produce electric energy as shown in Fig.(4.10)
The exhaust rejected from the exhaust stack is at high temperature around 600 oC, so we use the combined cycle that is generally defined as one or more gas turbines with heat recovery steam generators in the exhaust, producing steam for a steam turbine generator, so the efficiency will be increased up to 60% and the exhaust rejected from the HRSG stack is at low temperature around 110 oC as shown in Figure (4.11).
The mean purpose of the HRSG is to extract the heat losses of the exhaust and convert the feed water to superheated steam at pressure of 120 bar and temperature of 560 oC which is the specifications required for the operation of the steam turbine. The HRSG system consists of Economizer, Evaporator, Superheater, Steam drums (LP drum, IP drum and HP drum) and Deaerator.
Preheated is receiving condensate water from the condenser, heating up this water. Then water is fed to the deaerator dome, where de-aeration of the non-condensable gases from the water occurs before arriving into the feed water tank. Feed water for LP, IP and HP system is taken from the feed water tank to the drums.
Superheated (SH) steam from the outlet of the HP stage of the steam turbine is fed from the HRSG through the main steam (MS) line and is supplied to the steam turbine and the deaerator. The cold reheat steam flow from the outlet of the HP stage of the steam turbine is mixed with the superheated steam from IP system.
The total steam amount is superheated in the reheater and is expanded through IP turbine. Then the outlet of IP turbine is mixed with the LP superheated (LP SH) steam from LP superheater and is expanded through LP turbine.
The steam is let from the IP turbine to the LP turbine. Before entering the LP turbine LP steam is added via stop and control flap MAC31AA001/011. From the LP turbine the steam is fed to the condenser. During normal operation the whole steam generated in the HRSG flows through the HP/IP/LP steam turbine. The steam is condensed in the condenser.
The bypass stations are installed in parallel to the turbine. Their task is to control the HP and re-heater steam pressure and reduce the steam to conditions suitable for the re-heater (HP bypass) and the condenser (HRH-bypass). They are used for starting and shut down of the steam turbine and in cases when steam turbine is tripped.

4.1.9 Feed Water System

4.1.9 Feed Water System
The objective of the system is to de-aerate the condensate and supply all pressure levels with feed water. The deaerator/feed water tank is part of the feed water system. From the outlet of the preheater the condensate is supplied to the deaerator dome. The amount of condensate is controlled by the preheater control valve, located downstream the preheater. Pegging steam is added to the feed water tank and/or deaerator dome to de-aerate the water and maintain a minimum pressure (and temperature).
During normal operation pegging steam is coming from the LP SH steam line (pegging into the feed water tank). If LP steam is not sufficient or the GT is running on solar oil, cold reheat steam is added (pegging into the dome). From the feed water tank LP pumps and combined HP/IP pumps supply the feed water to the HRSG. The pumps are equipped with minimum flow lines.

4.1.9.1 Deaerator/Feed Water Tank
The deaerator is integrated with the feed water tank. The working principle of the deaerator is based on the thermal de-aeration. This means that at increased temperature and/or pressure less gas can be dissolved in water. Thus increasing the heat and the pressure of the water will force the dissolved gases to evaporate from the water as shown in Figure (4.8). The water and the steam flow counter current through the deaerator. The water to be de-aerated enters the deaerator/feedwater tank at the top in the so-called deaerator dome. The steam required for heating up the water phase enters the deaerator/ feed water tank, through the steam distributor tank.
In the deaerator dome the water is sprayed into small droplets, thus creating a large contact area between the water and the gas phase. This is beneficial for the de-aeration process as both the heat transfer from steam to water and the diffusion time of the non-condensable gases (oxygen, carbon dioxide) to the surface area is shorter.
The non-condensable gases leave the deaerator with some steam through the deaerator vent. The de-aerated water is collected in the feed water tank and is fed to IP and HP economizer systems and the LP drum by means of the respective feed water pumps.

4.1.9.2 Feed water Pumps
  A total of three combined IP/HP feed water pumps and three LP feed water pumps are installed. The pumps extract water from the feed water tank through three separate lines. The water is pressurized and supplied to a common HP, IP or LP feed water line. During normal operation there is a pump in operation for each HRSG in operation. When both HRSGs are in operation the third pump is on standby. The pumps are equipped with a minimum flow line which returns the water to the deaerator in case no water is required by the HRSG or if the flow is below the minimum flow. The minimum flow line supplies the water to the deaerator dome as shown in Fig. (4.9)

continue ch.4

4.1.4 Piping
Routing and supporting of the pipelines has been determined based on stress and process calculations. Routing and pipe hangers form a calculated, integral and balanced system. Changing part of this system will cause an altered load distribution, stresses and expansion, which may result in failure or damage.

4.1.5 Safety (Relief) Valves
 The purpose of safety (relief) valves is protection of personnel, plant and production. It is a pressure-relieving device for any installation requiring pressure protection; that is, it protects a pressure vessel (or pressure parts) against a pressure in excess of its design strength. The safety (relief) valves relieve the pressure by discharging steam or water when the set pressure is exceeded. Safety (relief) valves are installed on the:
 Condensate and feed water system (including deaerator).
 Closed cooling water system.  HRSG such as, IP economizers, steam drums, super heaters, repeaters.

4.1.6 Steam Silencers
 The steam may be released from either low pressure (LP steam vent silencer) of high pressure (HP steam vent silencer) as part of boiler start up system, a bypass vent or a safety relief valve vent system, So it reduce the noise of the expanding steam from the safety (relief) valves and start-up vent valves.

4.1.7 Attemperator
In drum style and once through designs, this is caused by such things as burner orientation and fuel to air ratios. In combined cycle plants, varying gas turbine exhaust temperatures and in the inclusion of duct firing can dramatically affect steam temperatures. In order to ensure the optimum operating heat rate and to protect the steam turbine, the steam temperature in the superheat and reheat sections of the boiler must be controlled. The purpose of the attemperator is cooling the steam, to limit the steam temperature.Fig.(4.7) shows the attemperator location.

4.1.8 Steam Bypass Station
 Steam from the outlet of the HP superheater, Re-heater and LP superheater is led to the steam turbine. When the steam turbine is not available the steam is bypassed using a HP bypass station and IP bypass station. HP steam is bypassed to the cold reheat line using the HP bypass station. Reheat steam is bypassed to the condenser using the IP bypass station. If the condenser cannot accept the steam from the IP bypass station, the hot reheat (HRH) steam is dumped to atmosphere using the common HRH blow off. LP steam is not bypassed but will be dumped to the atmosphere using the LP steam blow off if necessary. The bypass stations are equipped with a bypass line for heating the downstream piping preventing thermo-shock.

4.1.3 HRSG Components

The Heat Recovery Steam Generator, or HRSG, is configured in various shapes, designs, configurations, arrangements, and so on. To streamline our dialogue herein, we shall 1st say that the kind of HRSG we are now reviewing is what may perhaps be referred to as a water tube(as opposed to a fire tube) sort heat recovery unit. This refers to the process fluid, i.e., the steam or water being on the inside of the tubing with the products of combustion being external of the tube. The products of combustion are typically at or about atmospheric pressure, therefore, the shell side is normally not regarded as to be a pressure vessel.

In the style of any HRSG, the 1st step generally is always to perform a theoretical heat balance which is able to provide us with the correlation of the tube side and shell side process. Before we can calculate this heat balance, one needs to determine the water side components which will make up your HRSG unit. Despite the fact that these elements may perhaps consist of other heat exchange components, right now we will primarily take into consideration the 3 major coil varieties that may be present, i.e., Evaporator, Superheater, and Economizer. Whenever I allude to an Evaporator Section, this encompasses all the evaporator coils making up the complete evaporator for the Pressure System. A pressure circuit consists of all of the components incorporated within the many streams associated with that pressure level.

4.1.3.1 Preheater
Condensate from the condenser is heated in the preheater to a temperature close to the saturation temperature of the deaerator. The preheater inlet temperature is controlled using condensate recirculation. The preheated water is fed to the deaerator/feed water tank.

4.1.3.2 Economizers
The Economizer Section, often known as a preheater or preheat coil, is utilized to preheat the feed water being introduced towards the system to replace the steam (vapor) becoming removed from the method via the superheater or steam outlet and the water loss via blow down. It can be normally located inside the colder gas downstream in the evaporator. Because the evaporator intake and outlet temperature conditions are both near to the saturated steam temperature for the HRSG pressure, the quantity of heat that could be removed from the flue gas is limited on account of the approach to the evaporator, known as the pinch which is explained later, while the economizer inlet temperature is actually low, allowing the exhaust gas temperature to be reduced lower.

The feed water pumps pump feed water from the feed water tank to the IP and HP economizers. In the respective economizers the water is heated close the saturation temperature and fed to the IP or HP drums.

4.1.3.3 Evaporators
The most essential component would, certainly, be the Evaporator Section, given that without this component (or coils), the unit would not be an HRSG. an evaporator section might consist of 1 or more coils. In these coils, the water/steam flowing through the tubing is heated to near the steam saturation point for the operating pressure it can be at. The HRSG contains three evaporator systems, one for each pressure level. Fig. (4.5) shows HRSG water circulation methods.

4.1.3.4 Superheaters
The Superheater Section of the HRSG is utilized to dry the saturated vapor becoming separated within the steam drum. In some units it may perhaps only be heated to small above the saturation point where in other units it may well be superheated to a substantial temperature for additional energy storage. The Superheater Section is commonly situated in the hotter gas stream, in front of the evaporator. Saturated steam from the drum is fed to the superheaters where it is superheated. The HP superheated steam temperature is controlled by an inter-stage attemperator. The attemperator is located in between two superheater sections. The HP steam is fed to the steam turbine. The IP steam is mixed with the cold reheat steam and fed to the reheater. The LP superheated steam is fed to the deaerator/feed water tank and to the LP section of the ST.

4.1.3.5 Reheaters Cold reheat steam returning from the outlet of the HP stage of the steam turbine is mixed with the IP superheated steam and fed to the reheater where additional heat is added increasing the temperature before it is fed to the IP part of the steam turbine. The outlet temperature is controlled by an inter-stage attemperator.

4.1.3.6 Lp, Ip & Hp Steam Drum
Economizer water is fed to the drum through a feed water distribution pipe, which distributes the feed water evenly over the length of the drum, below the water level. The drum water is fed to the evaporator through the down comers.
The steam/water mixture coming from the evaporator enters the drum in the primary steam separator (baffle type), where water and steam are separated. Before leaving the drum, the steam passes the secondary separator (wire mesh type) and leaves the drum through the saturated steam line, and prevents water droplets to be carried over to the superheater under normal operating conditions. The drum as shown in Figure (4.6) is designed with a storage volume of water to produce steam for a certain time during failure of feed water supply. This so called hold-up time is (minimum values as calculated): • 3.0 minutes for HP • 8.3 minutes for IP • 11.4 minutes for LP

CHAPTER 4 HEAT RECOVERY STEAM GENERATOR AND STEAM TURBINE

4.1 INTRODUCTION
A heat recovery steam generator (HRSG) is a heat exchanger or series of heat exchangers that recovers heat from a hot gas stream and uses that heat to produce steam for driving steam turbines or as process steam in industrial facilities or as steam for district heating as shown in Fig.(4.1)
The Cairo North Power Station combined cycle consists of four gas turbines (with associated generator), four HRSGs and two steam turbine (with associated generator).The Power Station HRSGs are a triple pressure level HRSGs with a reheat system.

4.1.1 HRSG Process
 Exhaust gas from Gas Turbine enters the HRSG, heats water/steam, and leaves the HRSG through the stack. An isolating damper system (also called a bypass damper) with seal air fans is required in these units to ensure that hot gases do not leak to the fan when the gas turbine is running and that maintenance can be performed on the gas turbine when the fresh air fan is operating. Bypass dampers are also used in some units to ensure that the gas flow to the HRSG can be modulated in order to match steam generation with steam demand.

Different types of tube bundles:
1. Economizer: Water is heated up to almost saturation temperature.
2. Evaporator and Drum: Slightly sub cooled water enters the drum. Then it is circulated to the evaporator, where it is heated and transformed into a water/steam mixture. This mixture is returned to the drum, where water and steam are separated.
3. Superheater: Saturated steam leaving the drum reaches the maximum heat exchange temperature with the hottest exhaust gas leaving the gas turbine. From the last stage of the steam turbine the steam is led to a condenser where it is condensed to water. From the condenser the condensate is pumped to the HRSG, passing the gland steam condenser. Make-up water is added to compensate for any water losses. Condensate then flows through the condensate preheater (normal situation) and is fed to the deaerator/feed water tank.
From the deaerator/feed water tank, water is pumped to the LP drum using the LP feed water pump. From the deaerator the combined IP/HP feed water pumps bring the feed water to the IP and HP drum, passing the respective economizer before the water is fed to the drum. From the drum boiler water circulates through the evaporator system by means of natural circulation. In the evaporator a part of the water is evaporated. The steam/water mixture returns from the evaporator to the drum where steam and water are separated. Saturated steam flows from the drum to the superheaters. Superheated steam leaves the HRSG via the main stream line and is supplied to the steam turbine as well as to the feed water tank/deaerator. Cold reheat steam from the outlet of the HP stage of the steam turbine returns to the reheater of the HRSG in operation. The cold reheat flow is mixed with superheated IP steam and passes through the reheater, in which the temperature of the steam is increased. The hot reheated steam leaves the HRSG via the hot reheat steam line. The HRSGs of the Cairo North Power Station II operates at three pressure levels. Figure (4.2) shows a triple pressure system with 3(economizer, drum, evaporator and superheater).

4.1.2 T-Q Diagram
Figure (4.3) shows the most useful representation of the combined cycle heat transfer, a TQ diagram. It shows the decreasing exhaust gas temperature and the increasing water/steam temperatures of a single pressure system in relation to the amount of heat transferred. The process data is represented as a set of energy flows, or streams, as a function of heat load (kW) against temperature (deg C). These data are combined for all the streams in the plant to give composite curves, one for all hot streams (releasing heat) and one for all cold streams (requiring heat). The point of closest approach between the hot and cold composite curves is the pinch point (or just pinch) with a hot stream pinch temperature and a cold stream pinch temperature
.
Pinch Point Temperature
 Difference between steam outlet temperature and exhaust gas outlet temperature in the evaporator.
Lower pinch point = More heating surface, more steam generated and more energy taken from exhaust gases.
  Normal values between 8 and 15 ºC

Approach Temperature
 Difference between saturation temperature in the drum and water temperature at the economizer outlet.
 Lower approach = More heating surface more steam generated and higher risk of evaporation in economizer (problem known as “steaming”)
Normal values between 5 and 12 ºC.

.

3.2.4 Turbine Section

3.2.4.1General
The three-stage turbine section is the area in which energy in the form of high temperature pressurized gas, produced by the compressor and combustion sections, is converted to mechanical energy. Gas turbine hardware includes the turbine rotor, turbine casing, exhaust frame, exhaust diffuser, nozzles and shrouds.

3.2.4.2 Main Components of the Turbines
1 .Turbine Base and Support
The base that supports the gas turbine is structural steel fabrication of welded steel beams. And plate its prime function is to provide a support up on which to mount the gas turbine is mounted to its base by vertical supports at three location. The forward support at the lower half-vertical flange of the forward compressor casing and the two on either side of the turbine exhaust frame.

2. Turbine Rotor
The turbine rotor assembly consists of the forward and turbine wheel shafts and the first, second and third stage turbine wheel assemblies with spacers and turbine buckets. Concentricity control is achieved with mating rabbets on the turbine wheels, wheel shafts, and spacers. The wheels are held together with through bolts mating up with bolting flanges on the wheel shafts and spacers.

Selective positioning of rotor members is performed to minimize balance corrections as shown in Fig. (3.34) and Fig. (3.35).

 Wheel Shafts
The turbine rotor distance piece extends from the first-stage turbine wheel to the flange of the compressor rotor assembly. The turbine rotor shaft includes the No. 2 bearing journal

 Wheel Assemblies
Spacers between the first and second, and between the second and third -stage turbine wheels determine the axial position of the individual wheels. These spacers carry the diaphragm sealing lands. The 1-2 spacer forward and aft faces include radial slots for cooling air passages. Turbine buckets are assembled in the wheels with fir-tree-shaped dovetails that fit into matching cut-outs in the turbine wheel rims. All three turbine stages have precision investment-cast, long shank buckets. The long-shank bucket design effectively shields the wheel rims and bucket root

fastenings from the high temperatures in the hot gas path while providing mechanical damping of bucket vibrations.
As a further aid in vibration damping, the stage-two and stage-three buckets have interlocking shrouds at the bucket tips. These shrouds also increase the turbine efficiency. By minimizing tip leakage. Radial teeth on the bucket shrouds combine with stepped surfaces on the stator to provide a labyrinth seal against gas leakage past the bucket tips. Figure (3.33) shows typical first-, second-, and third-stage turbine buckets for the MS9001FA. The increase in the size of the buckets from the first to the third stage is necessitated by the pressure Reduction resulting from energy conversion in each stage, requiring an increased annulus area to accommodate the gas flow.

3. Turbine Stator
The turbine casing and the exhaust frame constitute the major portion of the turbine gas turbine stator structure. The turbine nozzles, shrouds, and turbine exhaust diffuser are internally supported from these components.

4. Turbine Casing
The turbine casing controls the axial and radial positions of the shrouds and nozzles. It determines turbine clearances and the relative positions of the nozzles to the turbine buckets. This positioning is critical to gas turbine performance. Hot gases contained by the turbine casing are a source of heat flow into the casing. To control the casing diameter, it is important to reduce the heat flow into the casing and to limit its temperature.
Heat flow limitations incorporate insulation, cooling, and multi-layered structures. 13th stage extraction air is piped into the turbine casing annular spaces around the 2nd and 3rd stage nozzles. From there the air is ported through the nozzle partitions and into the wheel spaces. Structurally, the turbine casing forward flange is bolted to the bulkhead flange at the aft end of the compressor discharge casing. The turbine casing aft flange is bolted to the forward flange of the exhaust frame.

Figure (3.36) shows typical first-, second, and third-stage turbine Element. The increase in the size of the buckets from the first to the third stage is necessitated by the pressure reduction resulting from Energy conversion in each stage, requiring an increased annulus area to accommodate the gas flow.

 5. Nozzles
In the turbine section there are three stages of stationary nozzles which direct the high-velocity flow of the expanded hot combustion gas against the turbine buckets causing the turbine rotor to rotate. Because of the high pressure drop across these nozzles, there are seals at both the inside and the outside diameters to prevent loss of system energy by leakage. Since these Nozzles operate in the hot combustion gas flow; they are subjected to thermal stresses in addition to gas pressure loadings as shown in Fig.(3.37)

First-Stage Nozzle
The first-stage nozzle receives the hot combustion gases from the combustion system via the transition pieces. The transition pieces are sealed to both the outer and inner sidewalls on the entrance side of the nozzle; this minimizes leakage of compressor discharge air into the nozzles. The gas turbine first-stage nozzle contains a forward and aft cavity in the vane and is cooled by a combination of film, impingement and convection techniques in both the vane and sidewall regions. The nozzle segments, each with two partitions or airfoils, are contained by a horizontally split retaining ring which is centerline supported to the turbine casing on lugs at the sides and guided by pins at the top and bottom vertical centerlines. This permits radial growth of the retaining ring, resulting from changes in temperature, while the ring remains centered in the casing.
The aft outer diameter of the retaining ring is loaded against the forward face of the first-stage turbine shroud and acts as the air seal to prevent leakage of compressor discharge air between the nozzle and turbine casing. On the inner sidewall, the nozzle is sealed by a flange cast on the inner diameter of the sidewall that rests against a mating face on the first-stage nozzle support ring. Circumferential rotation of the segment inner sidewall is prevented by an eccentric bushing and a locating dowel that engages lug on the inner sidewall. The nozzle is prevented from moving forward by the lugs welded to the aft outside diameter of the retaining ring at 45 degrees from vertical and horizontal centerlines. These lugs fit in groove machined in the turbine shell just forward of the first-stage shroud T hook. By moving the horizontal joint support block and the bottom centerline guide pin and then removing the inner sidewall locating dowels, the lower half of the nozzle can be rolled out with the turbine rotor in place.


 Second-Stage Nozzle
Combustion air exiting from the first stage buckets is again expanded and redirected against the second- stage turbine buckets by the second-stage nozzle. This nozzle is made of cast segments, each with two partitions or airfoils. The male hooks on the entrance and exit sides of the outer sidewall fit into female grooves on the aft side of the first-stage shrouds and on the forward side of the second-stage shrouds to maintain the nozzle concentric with the turbine shell and rotor. This close fitting tongue-and-groove fit between nozzle and shrouds acts as an outside diameter air seal. The nozzle segments are held in a circumferential position by radial pins from the shell into axial slots in the nozzle outer sidewall as shown in Fig. (3.38)

 Third-Stage Nozzle
The third-stage nozzle receives the hot gas as it leaves the second stage buckets, ithird-stage buckets. The nozzle consists of cast segments, each with three partitions or airfoils. It is held at the outer sidewall forward and aft sides in grooves in the turbine shrouds in a manner similar to that used on the second stage nozzle. The third-stage nozzle is circumferentially positioned by radial pins from the shell.13th stage extraction air flows through the nozzle partitions for nozzle convection cooling and for augmenting wheel space cooling air flow as shown in Fig. (3.38).

Diaphragm
Attached to the inside diameters of both the second and third-stage nozzle segments are the nozzle diaphragms. These diaphragms prevent air leakage past the inner sidewall of the nozzles and the turbine rotor. The high/low, labyrinth seal teeth are machined into the inside diameter of the diaphragm. They mate with opposing sealing lands on the turbine rotor. Minimal radial clearance between stationary parts (diaphragm and nozzles) and the moving rotor are essential for maintaining low inter stage leakage; this results in higher turbine efficiency.

6. Shrouds
Unlike the compressor blading, the turbine bucket tips do not run directly against an integral machined surface of the casing but against annular curved segments called turbine shrouds. The shrouds’ primary function is to provide a cylindrical surface for minimizing bucket tip clearance leakage. The turbine shrouds’ secondary function is to provide a high thermal resistance between the hot gases and the comparatively cool turbine casing. By accomplishing this function, the turbine casing cooling load is drastically reduced, the turbine casing diameter is controlled, the turbine casing roundness is maintained, and important turbine clearances are assured.
The first and second-stage stationary shroud segments are in two pieces; the gas-side inner shroud is separated from the supporting outer shroud to allow for expansion and contraction, and thereby improve low-cycle fatigue life. The first-stage shroud is cooled by impingement, film, and convection. The shroud segments are maintained in the circumferential position by radial pins from the turbine casing. Joints between shroud segments are sealed by interconnecting tongues and grooves.

7. Exhaust Frame
The exhaust frame is bolted to the aft flange of the turbine casing. Structurally, the frame consists of an outer cylinder and an inner cylinder interconnected by the radial struts. The No. 2 bearing is supported from the inner cylinder. The exhaust diffuser located at the aft end of the turbine is bolted to the exhaust frame. Gases exhausted from the third turbine stage enter the diffuser where velocity is reduced by diffusion and pressure is recovered. At the exit of the diffuser, the gases are directed into the exhaust plenum. Exhaust frame radial struts cross the exhaust gas stream. These struts position the inner cylinder relation to the outer casing of the gas turbine.
The struts must be maintained at a constant temperature in order to control the center position of the rotor in relation to the stator. This temperature stabilization is accomplished by protecting the struts fro fairing that forms an air space around each strut and provides a rotated, combined airfoil shape. Off through the space between the struts and the wrapper to maintain uniform temperature of the struts. This air is then directed to the third wheel space. Trunnions on the sides of the exhaust frame are used with similar trunnions on the forward compressor casing to lift the gas turbine when it is separated from its base. Figure (3.39) shows the exhaust duct which included silencers and a flange of the turbine casing.

8. Bleed valve
During starting the surge phenomenon must be avoided to prevent axial play to the rotor which destroy the engine. To protect the engine, a bleed air valve is used to bleed a part of air from the compressor delivery to the exhaust during starting to control the air flow rate or pressure ratio at specified value for each speed In GE there are four bleed valves, two from the stage 13 from the compressor and two from the stage 9 from the compressor as shown in Fig. (3.40)

9. Silencers
The disclosed silencer has noise gas duct in parallel with but with as to define gas passage means and noise duct. The noise-absorbing space means is closed by noise at inlet and outlet ends of the duct. A plurality of gas chambers aligned along the line of gas flow through the duct are formed in said noise absorbing space means by disposing noise therein as shown in Figure (3.41) Silencers noise -
absorbing partitions disposed in a spacing from outer walls of the duct, so noise -absorbing space means in the noising noise-shielding sectional walls Figure (3.41) shielding plates noise-shielding.

3.2.3.4 Gas Fuel System

The gas fuel system consists of the gas fuel auxiliary stop valve, gas fuel stop/ratio valve, diffusion gas control valve, PM4 gas control valve, and PM1 gas control valve. Refer to Fig. (3.30)
The stop/ratio valve (SRV) is designed to maintain a predetermined pressure (P=18 bar) at the control valve inlet. The diffusion, PM4 and PM1 gas control valves (GCVs) regulate the desired gas fuel flow delivered to the turbine in response to the command signal FSR from the SPEEDTRONIC™ panel. The dry low NOx mode of operation will determine how the control valves stage fuel to the multi-nozzle combustion system. The stop ratio valve and gas control valves are monitored for their ability to track the command set point.
The valve command set point differs from the actual valve position by a prescribed amount for a period of time; an alarm will annunciate to warn the operator. If the condition persists for an extended amount of time, the turbine will be tripped and another alarm will annunciate the trip.

3.2.3.5 Gas Fuel Operation
There are three basic modes of distributing gas fuel to the DLN-2 combustor.
These modes are described below:
1. Diffusion Mode
In this mode, all the gas fuel directed to the 5 diffusion (D5) tips in each of the combustors. At this time, the pre-mix passages PM4 and PM1are purged with compressor discharge (CPD) air. Diffusion is in the normal mode of operation from ignition to a combustion reference temperature of 2000oF (1093 oC) loading and unloading from 1950 oF till flame out and speed of 2835 rpm (95% of speed).
2. Piloted Pre-Mix
In this mode the fuel is split between the three gas control valvesPM1, PM4and D5. To fire an even premix split, the split between PM1 GCV and PM4 GCV, which feed the PM1 and PM4 manifolds respectively should be 20/80. It is normal to run the pre-mix burners slightly off even split to optimize combustion dynamics at the expense of emissions.

Piloted premix is the combustion mode between combustion reference temperature 2000 F and 2270 oF loading and 2220 oF unloading and power reach to 140 MW loading.

3. Pre-Mix.
In pre-mix, all the fuel is directed to the PM1 and PM4GCVswhich feed the pre-mix nozzles. Pre-mix mode combustion occurs above 2270 oF loading and 2220 oF unloading but D5 is purged with air. The diagrams in Figure (3.31) and Figure (3.32) show how fuel flow is controlled while transferring between the various combustion modes.

3.2.3.6 Atomizing Air System.
The Atomizing Air system for the MS7001FA and MS9001FA gas turbine provides compressed air for atomization of liquid fuel in the combustion system. The Atomizing Air is introduced through supplementary orifices in the fuel nozzles. The discharge from these nozzles impinges directly upon the liquid fuel oil spray as it enters the combustion chambers. The high velocity Atomizing Air stream shears the droplets of fuel into very small pieces, yielding a fine mist. The fine mist of fuel burns more completely in the combustion chamber, yielding significantly higher combustion efficiency and lower levels of combustion particles discharging to atmosphere through the exhaust. In addition to supplying air for atomization of liquid fuel, the Atomizing Air system also supplies purge air to the liquid fuel and water injection nozzles when the gas turbine is operating on gas fuel to prevent fuel accumulation and combustion back-flow. Immediately following shut down, the Atomizing Air Compressor can be run to purge and cool the Atomizing Air, Water Injection and Liquid Fuel nozzles. Provisions can also be made to use the Atomizing Air module to purge the Atomizing Air and Liquid Fuel piping during off-line water washes.

3.2.3.7 Atomizing Air System Components
The major Atomizing Air System components are as follows:
1. Atomizing Air Compressor/Motor assembly.
2. Inlet Air Heat Exchanger or Pre-cooler.
3. Cooling Water Control Valve and Electro-pneumatic Temperature Controller arrangement.
4. Cooling Water Electro-pneumatic Temperature Controller Thermocouple.
5. Dual Inlet Air Temperature Switches.
6. Moisture Separators.
7. Air Filter and Air Filter Differential Pressure Switch.
8. Motor Actuated Atomizing Air Compressor Bypass Valve with Limit Switches.
9. Motor Actuated Atomizing Air D/S Throttling Valve with Limit Switches.
10. Motor Actuated Atomizing Air Scavenging Valve with Limit Switches.
11. Compressor Differential Pressure Switches.
12. Compressor Discharge Temperature Switch.
13. CDP - Atomizing Air Manifold Differential Pressure Transmitters.
14. Cooling Water Bypass Solenoid, Control Valve and Limit Switches.
Exhaust gases generated from burning fuel in the combustion chambers flows through the impingement cooled transition pieces to the turbine.

3.2.3.3 Combustion Chamber Components

1. Outer Combustion Chambers and Flow Sleeves
The outer combustion chambers act as the pressure shells for the combustors. They also provide flanges for the fuel nozzle-end cover assemblies, crossfire tube flanges, spark plugs, flame detectors and false start drains as shown in figure (3.19). The flow sleeves form an annular space around the cap and liner assemblies that directs the combustion and cooling air flows into the reaction region.

2. Crossfire Tubes
All combustion chambers are interconnected by means of crossfire tubes. The outer chambers are connected with an outer crossfire tube and the combustion liner primary zones are connected by the inner crossfire tubes as shown in Fig.(3.20)

3. Fuel Nozzle End Covers
There are five fuel nozzle assemblies in each combustor. Fuel nozzle has five tube as liquid fuel tube, water tube, atomizing air tube, diffusion gas tube and premix gas tube as shown in Figure (3.21).
The nozzle shown is for the dual fuel option and shows the passages for diffusion gas, premixed gas, liquid fuel, atomizing air and water. When mounted on the end cover as shown in Figure (3.23). the diffusion passages of the five fuel nozzles are fed from a common manifold, called the primary that is built into the end cover. The premixed passages of the same four nozzles are fed from another internal manifold called the secondary. The premixed passages of the remaining nozzle are supplied by the tertiary fuel system. The diffusion passage of that nozzle is always purged with compressor discharge air and passes no fuel when operate at gas fuel.

4. Liner and Cap Assemblies
The combustion liner shows in Figure (3.24). Figure (3.25) shows combustion liner use external ridges and conventional cooling slots for cooling. Interior surfaces of the liner and the cap are thermal barrier coated to reduce metal temperatures and thermal gradients.
The cap shows in Figure (3.26) has five premier tubes that engage each of the five fuel nozzle. It is cooled by a combination of film cooling and impingement cooling and has thermal barrier coating on the inner surfaces.

5. Spark Plugs
Combustion is initiated by means of the discharge from spark plugs which are bolted to flanges on the combustion cans and centered within the liner and flow sleeve in adjacent combustion chambers 2 and 3. A typical spark plug arrangement is shown in Figures(3.27) and (3.28) .These plugs receive their energy from high energy-capacitor discharge power supplies. At the time of firing, a spark at one or more of these plugs ignites the gases in a chamber. The remaining chambers are ignited by crossfire through the tubes that interconnect the reaction zone of the remaining chambers
.
6. Ultraviolet Flame Detectors
During the starting sequence, it is essential that an indication of the presence or absence of flame be transmitted to the control system. For this reason aflame monitoring system is used consisting of multiple flame detectors located at combustors 15, 16,17and 18 as shown on Figure (3.29). Have water cooled jackets to maintain acceptable temperatures. The ultraviolet flame sensor contains a gas filled detector. The gas within this detector is sensitive to the presence of ultraviolet radiation which is emitted by a hydrocarbon flame. A DC voltage, supplied by the amplifier, is impressed across the detector terminals. If flame is present, the ionization of the gas in the detector allows conduction in the circuit which activates the electronics to give an output indicating flame. Conversely, the absence of flame will generate an output indicating no flame. The signals from the four flame detectors are sent to the control system which uses an internal logic system to determine whether a flame or loss of flame condition exists.

7. DLN 2 System Operation.
General DLN-2 control system regulates the distribution of fuel delivered to a multi-nozzle combustor arrangement. The fuel flow distribution to each combustion chamber fuel nozzle assembly is a function of combustion reference temperature and IGV temperature control mode. Diffusion, piloted premix and premix flame are established by changing the fuel flow distribution in the combustor. By a combination of fuel staging and shifting of burning modes from diffusion at ignition through full premix at high load, dramatically lower NOx emissions can be achieved above firing temperatures of 2270 oF.

3.2.3 Combustion System

3.2.3.1 Combustion System Description
The combustion system is of the reverse-flow type with the 18 combustion chambers arranged around the periphery of the compressor discharge casing as shown on Figure (3.15). Combustion chambers are numbered counterclockwise when viewed looking downstream and starting from the top left of the machine.

This system also includes the fuel nozzles, a spark plug ignition system, flame detectors and cross fire tubes as shown in figure(3.1

Hot gases generated from burning fuel in the combustion chambers flows through the impingement cooled transition pieces to the turbine as shown in figure (3.17).

High pressure air from the compressor discharge is directed around the transition pieces. Some of the air enters the holes in the impingement sleeve to cool the transition pieces and flows into the flow sleeve. The rest enters the annulus between the flow sleeve and the combustion liner through holes in the downstream end of the flow sleeve as shown in figure (3.18). This air enters the combustion zone through the cap assembly for proper fuel combustion. Fuel is supplied to each combustion chamber through five nozzles designed to disperse and mix the fuel with the proper amount of combustion air.

3.2.3.2 Combustion System Options
Dual fuel combustion system is a single stage, dual mode combustor capable of operation on both gaseous and liquid fuel. Gas Fuel only-On gas the combustor operates in a diffusion mode at low loads (<50% load) and a pre-mixed mode at high loads (>50% load). While the combustor is capable of operating in the diffusion mode across the load range. Diluents injection would be required for NOx abatement. Liquid fuel only- On oil operation, this combustor is in the diffusion mode across the entire load range, with diluents injection used for Nox abatement.

3.2.2 Compressor Section

3.2.2.1 Introduction
The axial-flow compressor section consists of the compressor rotor and the compressor casing as showing in Fig. (3.8). Within The compressor casings are the variable inlet guide vanes, the various stages of rotor and stator balding, and the exit guide vanes. In the compressor, air is confined to the space between the rotor and stator where it is compressed in stages by a series of alternate rotating (rotor) and stationary (stator) airfoil-shaped blades.


The rotor blades supply the force needed to compress the air in each stage and the stator blades guide the air So that it enters the following rotor stage at the proper angle. The compressed air exits through the compressor discharge casing to the combustion chambers. Air is extracted from the compressor for turbine cooling and for pulsation control during startup.

3.2.2.2 Compressor Components
1. Inlet Guide Vanes
Inlet guide vanes used at compressor inlet to ensure the air enters the first stage rotor as desired angle .in addition to the stators, another diffuser at the exit of compressor further diffuse the fluids and controls its velocity entering the combustor, Variable inlet guide vanes are located at the aft end of the inlet casing and are mechanically positioned, by a control ring and pinion gear arrangement connected to a hydraulic actuator drive and linkage arm assembly. The position of these vanes has an effect on the quantity of compressor inlet air flow as shown in Figure (3.9)
2. Rotor
The compressor portion of the gas turbine rotor is an assembly of wheels; a speed ring, tie bolts, the compressor rotor blades, and a forward stub shaft (see Figure (3.10). Each wheel has slots broached around its periphery. The rotor blades and spacers are inserted into these slots and held in axial position by staking at each end of the slot. The wheels are assembled to each other with mating rabbets for concentricity control and are held together with tie bolts. Selective positioning of the wheels is made during assembly to reduce balance correction.
After assembly, the rotor is dynamically balanced. The forward stub shaft is machined to provide the thrust collar, which carries the forward and aft thrust loads. The stub shaft also provides the journal for the No. 1 bearing, the sealing surface for the No. 1 bearing oil seals and the compressor low-pressure air seal. The stage 17 wheel carries the rotor blades and also provides the sealing surface for the high-pressure air seal and the compressor-to-turbine marriage flange.

3. Stator
The casing area of the compressor section is composed of three major sections:
a. Inlet casing
b. Compressor casing
c. Compressor discharge casing
These casings, in conjunction with the turbine casing, form the primary
structure of the gas turbine. They support the rotor at the bearing points and
constitute the outer wall of the gas-path Annulus. All of these casings are split
horizontally to facilitate servicing.

4. Inlet Casing
The inlet casing (Figure 3.12) is located at the forward end of the gas turbine. Its prime function is to uniformly direct air into the compressor. The inlet casing also supports the No. 1 bearing assembly. The No. 1 bearing lower half housing is integrally cast with the inner bell mouth. The upper half bearing housing is a separate casting, flanged and bolted to the lower half. The inner bell mouth is positioned to the outer bell mouth by nine airfoil-shaped radial struts. The struts are cast into the bell mouth walls.
They also transfer the structural loads from the adjoining casing to the forward support which is bolted and doweled to this inlet casing. Variable inlet guide vanes are located at the aft end of the inlet casing and are mechanically positioned, by a control ring and pinion gear arrangement connected to a hydraulic actuator drive and linkage arm assembly. The position of these vanes has an effect on the quantity of compressor inlet air flow

5. Compressor Casing
The forward compressor casing contains the stage 0 through stage 4 compressor stator stages. The compressor casing lower half is equipped with two large integrally cast reunions which are used to lift the gas turbine when it is separated from its base. The aft compressor casing contains stage 5 through stage 12 compressor stator stages. Extraction ports in aft casing permit removal of 13th-stage compressor air. This air is used for cooling functions and is also used for pulsation control during startup and shutdown
.
6. Compressor Discharge Casing
The compressor discharge casing is the final portion of the compressor section as shown in fig(3.13). It is the longest single casting, is situated at midpoint - between the forward and aft supports - and is, in effect, the keystone of the gas turbine structure. The compressor discharge casing contains the final compressor stages, forms both the inner and outer walls of the compressor diffuser, and joins the compressor and turbine casings. The discharge casing also provides support for the combustion outer casings and the inner support of the first-stage turbine nozzle. The compressor discharge casing consists of two cylinders, one being a continuation of the compressor casing and the other being an inner cylinder that surrounds the compressor rotor. The two Cylinders are concentrically positioned by fourteen radial struts. A diffuser is formed by the tapered annulus between the outer cylinder and inner cylinder of the discharge casing. The diffuser converts some of the compressor exit velocity into added static pressure for the combustion air supply.

7. Bleeding
The compressor rotor and stator blades are airfoil shaped and designed to compress air efficiently at high blade tip velocities. The blades are attached to the compressor wheels by dovetail arrangements. The dovetail is very precise in size and position to maintain each blade in the desired position and location on the
wheel. The compressor stators blades are airfoil shaped and are mounted by similar dovetails into ring segments in the first five stages. The ring segments are inserted into circumferential grooves in the casing and are held in place with locking keys. The stator blades of the remaining stages have a square base dovetail and are inserted directly into circumferential grooves in the casing. Locking keys hold them in place.