Gas Turbine Performance Based On Inlet A

gas turbine performance based on inlet air cooling systems: A technical review
Contents
part Part name , pages
A- Gas Turbine Overview – Technical overview
* The Basic Cycle.

* The Compressor.
* The Combustion System.
* The Turbine Section.
* The Accessory Section.
* Assembly and Construction.
* Compressor Maintenance.
* Gears, Couplings, and Bearings.
B- Main Gas Turbine Auxiliary Systems

Part (1) * Lube Oil System. 1 - 67
* Variable Inlet Guide Vane System.
* Oil Fuel System.

* Sales Gas Conditioning Skid.
* Generator Description.
* Operation sequences.
C- Gas Turbine Maintenance

* Types of Inspections.
Part(2) Advanced Brayton Cycles. 68 - 74
Improvement of gas turbine performance based

Part(3) 75 - 84
on inlet air cooling systems: A technical review.
1
PART (1) : GAS TURBINE OVERVIEW
2
The Basic Cycle
The Gas Turbine like any other heat engine is a device for converting part of a fuel's
chemical energy into useful available mechanical power.
It does this in a manner similar in many ways to the system used by a 4 stroke cycle
reciprocating internal combustion engine. The main apparent difference is that work is
accomplished in an intermittent manner in the reciprocating engine, whereas the turbine
power process is continuous throughout. The figure below Fig. 1-2 illustrates the
similarities between the two.
Fig. 1-2. Similarities in gas turbine and 4 stroke cycle.
As indicated by this illustration, air is drawn into the compressor, usually through an air
filter situated in a "filter house" to remove any harmful solid particles from the air
stream. This air is then compressed to a designed figure by a multi-stage axial
compressor. The hot, compressed air is then fed to the Combustion System where it
mixes with injected fuel. Here the fuel burns and add its energy to the air.
The combustion process rises the air temperature to a flame zone valve of between
2,500◦F and 3,200◦F. This is immediately reduced to usable values by the mixing of
secondary air that enters the combustion chamber through properly placed holes. The hot,
high pressure gas mixture is then ducted down to exhaust temperature. In the expansion
process, enough energy is removed from the gas to drive the compressor, the unit driven
auxiliaries such as the accessory gear box, fuel pump, cooling water pumps, lube oil
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pumps, etc. and the load which may be an alternator-with a gear box or a compressor or a
pump etc.
The used gas is then allowed to flow to the exhaust stack system. Since there is still much
heat energy in this gas, it can be put to use in a variety of ways, such as air or water
heating process drying or as hot air feed supply to a separately fired boiler, waste heat
recovery boiler. Any of these heat recovery methods helps to increase the overall thermal
efficiency of their turbine cycle.
The Compressor
Several types of compressors are available for gas turbine applications. They are
centrifugal, axial flow and the inter-meshing lobe types. All have been used by different
manufacturers. The manufacturer company uses the Axial flow type for all of its main
compressors, and was chosen primarily for its ability to pump large volumes of air at
better efficiency levels than either the centrifugal or lobe types. Axial flow compressors
are so designed that the air moves axially through the blading with essentially no radial
travel.
This type of compressor is made up of rows of air-foiled shaped blades with each set of
rotating blades followed by a set of similar stationary blades. Manufacturer commercial
compressors are designed to divide the pressure rise about equally between rotor and
stator.
The Combustion System
The combustion zone of a turbine is the space required for the actual burning of the fuel
and the subsequent dilution by secondary air from flame temperatures of 3,000◦F down to
usable values (1,650/1,750◦F).
This is normally done for manufacturer. Units in a group of combustion chambers which
may be inside the machine package (F.S.5). The combustion zone comprises an outer
casing an inner casing (or "liner") and the necessary air and gas passages (see Fig. 1-3).
Fig. 1-3. Combustion zone.
4
Simplified Outline of Combustion System
As shown in Figure 1-3 combustion takes place inside the inner casing. The walls of the
casing are cooled by streams of air, which are made to flow through louvres punched in
the wall material. This air stream flows close to the wall and thus keeps the material cool,
and so reduces thermal stress.
The Turbine Section
It is within the turbine section of a gas turbine that part of the thermal energy contained
in the hot gas provided by the combustion system is converted into mechanical energy.
Sufficient mechanical energy must be taken out of the gas stream to supply the power
necessary to drive the axial-flow Main Compressor, the Turbine Unit Driven Auxiliaries,
such as lube oil and fuel pumps as well as provide for bearing frictional losses and have
enough excess power to do a reasonable amount of external work such as drive a
generator, load compressor or some other type of load equipment (See Figure 1-4 for
typical values).
Fig. 1-4. G. T. Arrangement showing energy values.
Two main types of turbine designs are used for energy conversion. They are called Re-
action and Impulse designs. In the re-action type, the hot gas is allowed to expand in both
the rotating and stationary blading this is an efficient method of extracting work from a
gas stream, but since not much pressure drop can be used per stage, many stages are
required. In the Impulse type, which is used by manufacturer, most of the pressure drop
occurs in the stationary elements with only a small percentage taking place in the rotating
parts. This type has the advantage of being able to do more work per stage (hence fewer
stages) than the reaction type. It also permits larger pressure and temperature drops to
occur in the stationary parts than in the more highly stressed and difficult to cool rotating
elements.
The hot gas is delivered to the turbine from the combustion chambers at a temperature
and flow required by the load (1,000◦F to 1,700◦F). During its flow through nozzles and
buckets (turbine blades) the gas loses both heat and pressure until it is discharged from
the final stage at exhaust stack pressure and temperature. In the meantime it has given up
enough energy to the turbine rotor to provide the necessary mechanical power. So far,
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discussions and descriptions of the turbine cycle have primarily been for a single shaft
non regenerative unit. While this type of machine is simple, powerful and reasonably
good on thermal efficiency, some applications require more flexibility of operation and
thermal efficiencies than this basic machine configuration is capable of providing.
For this reason the two shaft machine was developed. This type has the load turbine and
the compressor turbine on separate shafts with a controllable angle nozzle in between.
The "angle" nozzle is effectively a variable area orifice of the advantages of this type of
construction are:
(a) Better part load thermal efficiency.

(b) Ability to run compressor and load shafts at different speeds so that the best result
can be achieved.
(c) Lower starting power required.
With wide open nozzles the AP over the high pressure turbine is maximised. Thus the
turbine develops more power in starting, which reduces starting power required. Higher
overall thermal efficiencies may be achieved by the addition of a regenerator. In this
component, turbine exhaust gas is allowed to give up some of its heat to compressor
discharge air in this way, heat that would otherwise be wasted is returned to the cycle,
thereby reducing fuel required and increasing the power output.
The Accessory Section
This section of the machine includes the starting means (diesel engine, expansion gas
turbine, or electric motor) a tank containing the requisite amount of lube oil (1,700
gallons for F.S.5) auxiliary gearbox which drives fuel pump, gear lube oil pump, gear
hydraulic oil pump, atomizing air compressor and water pump. Hydraulic ratchet for cool
down purposes particularly - electro mechanical stop Valves, lube oil and fuel oil filters.
Pressure gauges and switches, and emergency and cool down electrically driven lube oil
pumps. The auxiliary gearbox is initially driven by the starting means but in normal
operation the gas turbine itself supplies the motivating power.
General Observation
To avoid confusion, the "gas" in gas turbine refers to the products of combustion when
liquid or gaseous fuels are burnt in pressurized air in a closed chamber. The Gas is at a
high temperature, and pressure which when channeled through fixed nozzles impinges on
buckets mounted on the circumference of a rotor, causing the rotor to rotate.
In the description, which follows, references to the forward and aft ends and/or right and
left sides of the various components of the unit will be made. The inlet casing of the gas
turbine is considered to be forward end while the exhaust hood is considered to be aft
end. Each component assembly of the unit may be considered as having a forward and aft
end. These directions are determined in the manner as for the complete unit when the part
is in its installed position. The right and left sides of the unit, as well as any of its parts,
are determined when looking in an aft direction.
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Fig. 1-8. Gas and generator-simplified schematic.
Fig. 1-9. Unit configuration.
7
Assembly and Construction
Turbine Base and Supports Base (Fig 1-10)
The base upon which the gas turbine is mounted is a structural-steel fabrication.
A lube oil storage tank within the forward end supplies the lube oil for the gas turbine
and its associated equipment.
An oil drain channel is constructed along the web of the left longitudinal I-beam. The
channel, extending from the oil tank to the fabricated box at the aft end of the base
provides a passage for the lube oil header.
The lube oil header carries lube oil to the No. 2 bearing, load coupling and driven
equipment. The lube oil feed and drain connections for these parts are made at the box.
Finished pads on the bottom of the base facilitate its mounting on the foundation.
Fig. 1-10. Final Machining of Base.
Fig. 1-10. Final Machining of Base. Continued.
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Supports (Fig 1-11)
The forward end of the gas turbine is supported by a flexible plate that is welded to the
base and bolted and dowelled to the air inlet casing.
The leg-type supports maintain the axial location of the turbine while the gib key
maintains the lateral, location.
Fig. 1-11. Flexible support plate.

Gib Key and Guide Block (Fig 1-12)
A gib key is machined on the lower half of the turbine shell. The key fits into a guide
block which is welded to the turbine base. The key is bolted securely into the guide block
and prevents lateral or rotational movement of the turbine.
The key and block arrangement permits axial movement due to thermal expansion.
Fig. 1-12. Gib block and key before welding.
9
Compressor Maintenance
Compressor Rotor (Fig 1-13)
The axial-flow compressor rotor assembly consists of 16 blade and wheel assemblies and
one blade and stub shaft assembly. The blade and stub shaft assembly and the blade and
wheel assemblies are rabbeted and bolted together concentrically around the rotor axis.
The bolt holes are countersunk in the stub shaft, this machining keeps the bolt heads and
nuts flush with the wheel face and reduces windage loss. The stub shaft is machined, to
provide the forward and aft thrust faces and the journal for the No. 1 bearing assembly
and the sealing surface for the No. 1 bearing oil seals, and the compressor low pressure
air seal.
The compressor rotor assembly is dynamically balanced before it is assembled to the pre-
balanced turbine rotor assembly. This completed assembly is then dynamically balanced.
The balance corrections are carefully and properly distributed so as to compensate for
internal bending moments in the complete assembly.
Fig. 1-13. Rotor positioned in casings.
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Compressor Casing (Fig 1-14)
The compressor casing encloses the compressor portion of the rotor and is divided into
four sections: inlet, forward, aft, and discharge. All of these sections are split horizontally
to facilitate servicing.
The inlet section directs the flow of outside air from the air inlet equipment into the
compressor blading. This section contains the variable inlet guide vane assembly. The
No. 1 bearing assembly and the low pressure air seals. The forward section of the
compressor casing is downstream of the inlet section. It contains the stator blading for
stages 0 through 3. Bleed air from the 4th rotor stage (between the 3rd and 4th stator
stages) can be extracted through four ports which are located about the aft section of the
compressor casing.
Fig. 1-14. Turbine casings complete.
The aft section, downstream of the forward section, contains the stator blading for stages
4 through 9. Bleed air from the 10th rotor stage (between the 9th and 10th stator stages)
can be extracted through four ports which are located in radial alignment with the ports
used for 4th stage air extraction. The discharge section of the compressor casing,
downstream of the aft section, contains the stator blading for stages 10 through 16, and
exhaust guide vane stages 1 and 2. A radially enlarged (bulkhead) portion of this section
provides the mounting surface for the combustion chambers. Ten air foil shaped support
struts are secured equidistantly about the aft surface of the bulkhead and angle inward to
support the inner case assembly (inner barrel). The space, between the forward portion of
the inner barrel and the discharge section outer shell, forms an annular air path that the
high pressure air passes through to enter the combustion section. This area is designed to
decelerate the air flow and increase the static pressure of the combustion air supply.
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Blading
The stator blades have dovetail-shaped bases that fit into dovetail shaped openings in the
two-piece, semi-circular ring. The ring fits into a groove of the same shape machined in
the compressor casing wall. Locking keys prevent the rotating of the blade rings. The
rotor blades also have dovetailed bases of a wide angle design which of into the matching
dovetail openings in the wheels. The rotor blades are peened in place.
Variable Inlet Guide Vanes (Fig 1-15)
The variable inlet guide vanes (in conjunction with the 4th and 10th stage air extraction)
permit fast smooth acceleration of the turbine without compressor surge (pulsation). A
hydraulic cylinder, mounted on a base cross member, actuates the inlet guide vanes
through a large ring gear and multiple small pinion gears. At start-up, the vanes are set at
44◦ and when the turbine accelerates to 95% speed, the vanes are rotated to the 80 ◦
position. When the turbine is tripped, the vanes are immediately rotated to the 44 ◦
position. (They do not wait until turbine speed drops below 95%).
Note: The 34◦ and 84◦ angles are measured between the chord line of the vane and a line
perpendicular to the centre line of the turbine.
Fig. 1-15. Variable inlet guide vanes.

Combustion Section
General
The combustion section consists of combustion chambers, fuel nozzles, flame detection
equipment, spark plugs, and transition pieces. The combustion chambers are arranged
concentrically around the axial-flow compressor and are bolted to the compressor
discharge section bulkhead. Air for combustion is supplied directly from the axial-flow
compressor to the combustion chambers. Fuel is fed into the chambers through fuel
nozzles that extend into each chamber's liner cap.
As a protective measure on oil-fired units, a false start drain valve is installed in the drain
line piping at the bottom side of the No. 5 combustion chamber, (the chamber at the
lowest point of the concentrical arrangement), This normally open air-operated valve
prevents the accumulation of fuel oil in the combustion and turbine sections when a start
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signal is given and the turbine fails to start. The valve is automatically closed by
compressor discharge pressure as the turbine accelerates. The valve diaphragm is
protected against excessive air pressure by a pressure regulating valve installed in the air
piping to the valve operating mechanism.
Combustions Chambers (Fig 1-16 to 19)
The high pressure air flow from the compressor discharges into the annular space created
by the aft end of the discharge casing and frame assembly and the forward section of the
turbine shell. Up to this point, the air flow has been in an aft direction; now the air flow
reverses. The air enters the combustion chambers and flows forward, entering the liner
through holes and louvres in the liner wall. The air flow through the combustion
chambers has three functions, to oxidize the fuel, to cool the metal parts, and to adjust the
extremely hot combustion products to the desired turbine inlet temperature Combustion
chambers with the Turbulator System are designed to eliminate exhaust smoke air
pollution during the operation of the gas turbine after the start sequence. Lean primary
combustion followed by a "thermal soaking" assures that all soot is burned during
combustion.
Fig. 1-16. Multiple combustion chambers.
The Turbulator System accomplishes this aerodynamically by stabilizing the lean

combustion zone with a vortex generated by an air nozzle surrounding the fuel nozzle.
Dilution of the combustion products to turbine inlet temperature is delayed to allow
consumption of any soot that was not burned in the combustion zone.
The burning of this soot is accomplished by not injecting any air into the liner until the
air reaches the downstream end of the combustion chamber.
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Fig. 1-17. Annual combustion chambers.
The combustion chamber liners and casings are no! all identical in design nor
interchangeable on different model series of gas turbines. This is due to the false start
drain being present in Chamber No. 5, the provision of spark plugs and flame detectors in
chambers 2, 3, 7 and 8. The combustion chamber casings have machined pads for
mounting the spark plugs and flame detectors.
The casing liners have holes through which the spark plugs and flame detector body
projects. The bolted on casing covers which support the fuel nozzle utilize two oversize
bolts in the bolt circle to facilitate re-positioning of the fuel nozzle when the fuel piping
is installed.
Flame Detectors
Two are fitted, one on No. 7 combustion chamber and one on No. 8 chamber. They are
the ultra violet detector type energized by power from a flame detector unit within the
speedtronic panel.
The establishment of flame is an essential feature of the start up cycle; failure to detect
flame on both detectors will inhibit further progress of the sequence. Should one of the
detectors fail to sense flame, during run-up or when running, an alarm will be
annunciated in the turbine control panel.
If both detectors fail to see flame, the turbine will trip.
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Fig. 1-19. Flame stabilizing and general airflow pattern.
Transition Pieces (Fig 1-20)
The transition pieces (fishtails) are the hot gas path link between the combustion
chambers and the first stage nozzle. They are clamped to the forward side of the nozzle
assembly. The nozzle assembly is sealed at both its outer and inner periphery to prevent
leakage of hot gases. On the outer periphery of the nozzle, the transition space is sealed
by the turbine wheel shrouds, to which the nozzle assembly is clamped. On the inner
periphery of the nozzle, the transition space is sealed by seal segments installed between
the nozzle inner sidewall and the first-stage nozzle support assembly. The nozzle
assembly and its support arrangement hold the assembly in proper alignment in the gas
path and makes allowances for the effects of thermal growth.
Fig. 1-20. Fitting transition pieces.
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Spark Plugs
Combustion of the fuel and air mixture is initiated by retracting electrode type spark
plugs. The spark plugs, installed in two of the combustion chambers, receive their power
from the ignition transformers. The chambers without spark plugs are fired with flame
from the fired chambers through interconnecting cross-fire tubes.
The Turbine Section
General
The turbine section is where the high temperature gases from the combustion section are
converted to shaft horsepower. The power required to drive the load package and the
compressor is provided by the two-stage turbine rotor.
Fig. 1-21. First and second

stages turbine nozzles and buckets.
The first-stage, or high pressure wheel and the second-stage, or low pressure wheel are
bolted together to make up a single unit through which the first and second stage nozzles
direct the flow of combustion gases, These components, with associated air seals and
deflectors, are contained within the turbine shell. (Fig 1-21).
The forward section of the turbine shell forms the casing for the aft end of the
compressor discharge and combustion sections. The aft section of the turbine shell forms
the casing for the first and second-stage nozzles and the shrouds for the first and
second-stage turbine rotors. Compressor fourth-stage extraction air is piped to cool the
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shell and then discharged at the aft end of the shell to cool the aft surface of the second
stage turbine wheel.
First-Stage Nozzle
The first-stage nozzle assembly consists of airfoil-shaped partitions between an inner and
outer sidewall. The nozzle assembly is divided into segments, with the segments fixed in
a retaining ring assembly sustained in the turbine shell by a clamping ring. The nozzle
ring and partitions are cooled by compressor discharge air which is bled from the
combustion chamber transition space. The nozzle partitions are hollow with bleed holes
drilled in the trailing edge for cooling. The cooling air circulates about the sidewalls of
the retaining ring into the hollow nozzle partitions and out the bleed holes into the gas
path. The design of the nozzle supporting arrangement permits removal of the lower half
of the nozzle assembly without removing the rotor assembly.
Second-Stage Nozzle and Diaphragm
The second-stage nozzle and diaphragm assembly is located between the first and
second-stage turbine wheels. It is supported by a clamping arrangement in the turbine
shell. The assembly has air foil-shaped partitions between the inner and outer sidewall
which direct the gas flow into the second-stage turbine buckets. Insulating pipes are
installed in the drilled partition holes to minimize the heat exchange between the nozzle
partitions and the air flow to the turbine wheels paces.
The diaphragm assembly extends inboard from the nozzle assembly to the turbine rotor
and divides the space between the two wheels into the high and low pressure turbine
areas. The diaphragm assembly contains the wheel cooling air deflectors and packing
ring that provide the inner seal between the first and second-stage wheelspaces. The
nozzle assembly and the diaphragm are both split into separate halves at their horizontal
centreline for ease of maintenance. The lower half of the diaphragm assembly is located
and supported on three radial dowel pins in the lower of the two assemblies are handled
as one during installation and removal, while the top halves are handled separately. The
lower half of the nozzle and diaphragm assembly can be removed from the turbine shell
without removing the rotor assembly.
The second-stage nozzle and diaphragm assembly is positioned laterally in the turbine
shell by eccentric pins installed in the top and bottom halves of the shell. The eccentric
pins are concealed under the flange connection for the shell cooling air piping. The
vertical position of the assembly is fixed by a set of ground clamps at the horizontal joint
on each side of the turbine shell. To prevent movement of the nozzle assembly during
moving and installation, four retaining pins are installed through the turbine shell. The
retaining pins are positioned to fit into machined cut outs on the aft outer sidewall ring of
the nozzle. The pins two in each half of the shell are located at about 44 degrees to the
right and left side of the vertical centreline of the turbine shell assembly. The seal ring
restricts air leakage and directs high velocity cooling air at the dovetail area of the
second-stage wheel. The high velocity is developed when the air passes through the small
holes drilled in the seal ring which is positioned opposite the dovetails.
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Turbine Rotor Assembly
The turbine rotor assembly consists of the turbine-to-compressor distance piece and the
first and second-stage turbine wheels and buckets. The turbine wheels are forged of high
temperature alloy steel. The second-stage wheel is forged with a stub shaft on which the
journal and sealing surface is machined for the No. 2 bearing and its oil seal. At the stub
shaft end is a flange to couple the shaft to the driven device.
The buckets have “pine tree”, axial-type dovetails and are assembled on the rim of the
wheel in matching “pine tree” slots. The individual components of the rotor assembly are
pre-balanced and assembled so that the complete rotor assembly will require a minimum
of correction. The rotor assembly is dynamically balanced with any required corrections
carefully distributed to compensate for internal bending moments. The turbine rotor
assembly is bolted to the pre-balanced compressor rotor assembly. This complete rotor
assembly is again dynamically balanced with any required corrections carefully
distributed to compensate for internal bending moments.
Fig. 1-22.
Fig. 1-23.
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Gears, Couplings, and Bearings
Accessory Gear (Fig 1-24 & 1-25)
The accessory drive gear, located at the compressor end of the gas turbine, is a gearing
assembly coupled directly through a flexible coupling to the turbine rotor. Its function is
to drive each gas turbine accessory at its proper speed and to connect and disconnect the
turbine from its starting device. In addition it contains the system main lube oil pump and
the turbine over speed trip bolt and mechanism. Contained within the gear casing are the
gear trains, which provide the proper gear reductions to drive the accessory devices at the
required speed, with the correct torque values. The starting clutch assembly is mounted
forward on the horizontal joint of the main gear shaft and is used to connect the starting
device to the gas turbine.
Accessories driven by the gear include: the main tube oil pump, the main hydraulic
supply pump and the liquid fuel pump, the water pump, and the main atomizing air
compressor. Lubrication of the gear is from the turbine's pressurized bearing header
supply. A high-pressure turbine overspeed trip capable of mechanically dumping the oil
in the trip circuits is mounted on the exterior casing of the gear. This device can shut the
turbine down when the speed exceeds the design speed. The overspeed bolt which
actuates the trip overspeed is installed in the main shaft. The gear consists of four parallel
axis, interconnected shafts arranged in a casing which provides for the various driven
accessories. With the exception of the tube oil pump and hydraulic supply pump shaft, all
the shaft centrelines are located on the horizontal joint of the accessory drive casing.
Numbers are assigned to the various shafts and the r.p.m. of each shaft and the load
horsepower are shown in the Design Data Table.
The gear casing is made of cast iron and split at the horizontal joint to facilitate
assembly. The lower-half casing, which houses the main lube oil pump, has a closed
bottom with openings for lube oil pump suction and discharge lines and casing drain line.
All of the shafts are connected together by single helical gears, which are shrunk to the
shafts after the teeth are cut. It is possible, in some instances, to remove individual gears,
which may have been damaged in service, and to replace them with new gears. This
operation, however, should be performed at the factory so that the required precision may
be maintained.
All of the shafts located on the horizontal joint are contained in babbitt-lined
steel-backed journal bearings with integral thrust faces which are split on the horizontal
joint of the casing. The thrust faces of the bearings maintain the shafts in their proper
axial location and the necessary thrust clearance is preset at the factory. The shafts which
are not on the horizontal joint are contained in babbitt-lined, steel-backed, non-split
bushings with integral thrust faces. Their thrust clearance is likewise preset at the factory.
The main lubricating oil pump is located on the inboard wall of the lower-half casing of
the accessory drive gear this pump is a positive displacement type gear pump that is shaft
driven directly by the lower drive gear of the accessory drive. The pump gears are driven
by Shaft No. 4, a splined quill shaft from the lower drive gear. The gears are contained in
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Babbitt-lined cast-iron bushings which are located at the ends of the pump cavity. The
pump suction and discharge passages are cored to openings on the bottom surface of the
casing. A starting clutch assembly is located at the outboard end of the main gear shaft
on the horizontal joint of the casing and is used to connect the starting device to the gas
turbine input shaft. The clutch automatically becomes disengaged when the gas turbine
reaches a speed at which it is self-sustaining.
Fig. 1-24. Accessory gear box mounted on turbine base.
DESIGN DATA – TABLE
Location of Shaft Driven Accessory RPM Approximate Load
No. 1 Outboard Clutch 5100 --------
No. 1 Inboard Turbine Coupling 5100 --------
No. 2 Outboard Water Pump 3583 35 hp
No. 2 Inboard (Machined to Accept Brake) 3583 --------
No. 3a Outboard Fuel Pump 1814 108 hp
No. 3b Inboard Atomizing Air Compressor 6003 380 hp
No. 4 Outboard Hydraulic Supply Pump 1415 9hp
No. 4 Inboard Lube Oil Pump (Shaft Covered) 1415 31 hp
20
Fig. 1-25. Accessory gear box split on horizontal plane.
Gearwheel and Quill-Shaft (Fig 1-26)
The gear wheel rotor is a solid forging in EN. 9- "55" carbon steel with integrally
hobbled and shaved teeth, hollow-bored over the entire length and having an integral
coupling flange at the turbine end. The quill-shaft is a solid forging in En. 19 1% CR-MO
steel with an integral coupling flange at the generator end and a taper machined portion
at the turbine end.
Fig. 1-26. Quill shaft fitted to load gearwheel.
The quill shaft coupling hub is assembled on the quill shaft in contact with the
appropriate face of the output member of the drive clutch. The input member of the
clutch is connected to the gear wheel output flange.
Gear case
The gear case is of cast construction and comprises a lower, intermediate and upper
section, respectively bolted together in the horizontal wheel and pinion centre line planes.
Bearing seating’s and keeps are integral with the appropriate gearcase sections. Four
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openings with quick-release covers are provided in the intermediate section of the gear
case to facilitate inspection of gear elements and gear meshes.
Journal Bearings
The four fully cylindrical journal bearings are of the medium steel shell, thin white
metalled type. They are located in the bearing seating’s and are prevented from rotating
by retaining discs which project into suitably shaped pockets machined into the outer
surfaces of the bearing shells. These retaining discs also ensure that each bearing can
only be fitted in its correct angular position relative to the gear case.
Each journal bearing is lubricated from a common ring main via two rectangular supply
openings machined through the bearing shells, on at each of the two butt joints and each
discharging into an axial distributing groove extending over almost the full width of the
bearing shells on their inner surfaces. These grooves together with their associated
wash-ways ensure an even distribution of lubricant over all journal and bearing surfaces.
Thrust Bearings
The pinion is held central in the gear case and prevented from oscillating axially by a
double action thrust bearing located at its generator end. This bearing also takes any
thrust loads on the pinion, which might arise from the action of the output coupling and
serves as the means for axially locating the low-speed gear through the double helical
intermesh between pinion and wheel.
The thrust bearing is of the steel backed and white metalled, tilting pad type. Oil is fed,
under pressure, into the thrust recess in the pinion shaft from the stationary casing and
then forced to flow outwards across the thrust bearing surfaces.
Flexible Couplings (Fig 1-27)

The basic functions of flexible couplings are (1) to couple together two rotating shafts for
efficient transmission of torque from one shaft to the other (2) compensate for all types
of misalignment without imposing high loads on the coupled equipment and (3)
compensate for axial movement of the coupled shafts so that neither shaft exerts
excessive thrust on the other. Almost all types of couplings, when properly sized and
maintained, perform the torque transmission functions, therefore, misalignment and axial
motion capabilities determine the type of coupling used for any particular application.
Misalignment and axial movement between a gas turbine and a driven machine are
usually the result of differences in thermal expansions.
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Fig. 1-27. Types of flexible coupling misalignment.
There are three types of misalignment which a flexible coupling must accommodate.
Figure 1-27a shows a parallel offset misalignment which occurs when the axes of the
two connected shafts are parallel but not in the same straight line. Figure 1-27b shows
angular misalignment, which occurs when the axes of two connected shafts intersect.
Figure 1-27c shows combined angular offset, which occurs when the axes of the
connected shafts do not intersect and are not parallel. Axial movement is the
displacement of one or both of the coupled shafts along their axes.
Gear couplings utilize component parts that slide rather than flex. This type of coupling
consists of two hubs of male teeth and two sleeves of female teeth. The teeth of the
sleeves mesh with the hub teeth to transmit the torque. The working action of a gear
coupling is that of a spline rather than a gear.
Manufacturer gas turbines may use this type of coupling for driving the load equipment,
starting the turbine, and driving the accessory gear.
Being aware of the design criteria applied to gas turbine flexible couplings may be of
some help in maintenance thinking. Although a coupling is a relatively small cost item in
a gas turbine driven train, it can be a high cost item in terms of downtime and damage to
other components. Therefore, some overdesign seems justified, and this is the
philosophy.
To protect against unanticipated transient torques such as generator electrical faults or

load compressor surge, couplings are designed to withstand torques much higher than the
23
steady-states design load before reaching the shear yield strength of the power
transmission components. The flanges are designed to carry these are same torques in
face friction thus avoiding the restrictions of body-bound bolting and bolt hole location
tolerances when coupling up pieces of equipment from different manufacturers or
making field changes.
Centering of the spacer is by means of tight clearances between the outside diameter of
the male teeth and the root diameter of the female teeth. This tight clearance (0.001 to
0.002 inch diametral) is located in the areas of the teeth that experience relatively little
wear. When tight backlash tolerances are used for centering the coupling loosens up with
operation due to the wear of the working surfaces.
In addition to the spacer centering control to minimize coupling unbalance tight

tolerances are imposed upon concentricities runouts and rabbet f its. Matchmaking of the
coupling assembly is an important feature for extending coupling life, It assures
end-for-end and angular position repeatability of parts so that the teeth only experience
the accelerated wear rate of "running in" once and maintain the slow wear rate of "run in"
parts for the remainder of the life of the coupling.
The crowned tooth which is used in manufacturer gas turbine couplings minimizes
compressive stresses for increased life and decreased resistance to axial motion. This
form provides heavier tooth section, minimizes backlash, and eliminates gouging of the
sleeve teeth.
Gear Couplings
There are three common lubrication methods used in manufacturer, gas turbine gear
couplings. Grease-packed, continuous lube and oil-filled.
Grease-Packed
Grease-lubricated couplings are used to drive the accessory gear from the front end of the
gas turbine shaft, often in applications where regular lubrication can be applied, such as a
peaking power plant. Every 4000 hours of operation a grease-packed coupling should be
disassembled, cleaned, inspected, and repacked with clean grease. The purpose in
cleaning is to get the soap binder of the old grease out of the teeth. When oil separates
from the soap in the grease the centrifuging action results in the soap being deposited on
the teeth.
Oil-Filled
Oil-filled couplings are used for the same applications as continuously lubricated
couplings. Lubrication is accomplished by sealing into the coupling a quantity of
high-viscosity gear lubricant conforming to MIL L-2105B. These couplings have a three-
year lubrication and inspection cycle. Their limitation is that they cannot be applied in a
very hot environment where excessive outside heat might be absorbed.
24
The major components of the oil-filled accessory gear coupling consist of sleeves, hubs,
and a floating shaft. The coupling sleeves include flanges, which interface with the
accessory gearbox and the turbine rotor. Internal gear teeth machined within the coupling
sleeve mesh with the external crowned teeth of the hubs. These hubs are splined onto the
floating shaft, and the resultant pivoting action of the sleeves and the hubs compensate
for a nominal misalignment of the accessory gearbox and the turbine rotor. The sliding
action between the hubs and the sleeves permits axial movement of the turbine relative to
the accessory gearbox. The O-ring seals, recessed in the face of the coupling flanges and
located between the sleeves and hubs, are used to contain the lubricant within the
coupling.
Continuous Lubrication
This method uses the oil from the main bearing lubrication system, which is discharged
into the coupling teeth through nozzles. This oil is continuously circulated back through
the lube system. Continuously lubricated couplings are used as output, helper turbine,
and accessory gear couplings. These couplings are limited to one year to three-year
continuous operation, depending upon filtration level. If they are lubricated through the
normal lube system with five micron filtration, it is recommended that they be
disassembled, cleaned, and inspected annually (8,000 hours). However, this cycle can be
increased to three years by the use of in-line, one half micron filters ahead of the
coupling feeds. The problem is that of centrifuging solid particles out of the oil in the
coupling. These particles form a hard substance, which is deposited on the coupling
teeth, thus limiting their action.
Bearings
Bearings Represent connecting interfaces between a gas turbine's rotating parts and its
stationary components. Bearings used on heavy duty gas turbines can be broadly
categorized into two types. These are journal or sleeve bearings, and thrust bearings.
Journal Bearings
A journal bearing consists of a cylindrical shaft section (or journal) and a mating
stationary shell or liner as shown in Figure 1-28. Journal bearings are used to support
radial loads directed perpendicular to the axis of shaft rotation. As such, they support the
rotor weight as well as such dynamic forces as rotor unbalance and gear tooth reactions.
These bearings are classified as hydrodynamic in operation, which means that their load
supporting capability is derived from a thin oil film wedge as shown in Figure 1-29. This
wedge is generated as a result of the relative motion between the journal and liner. The
viscous nature of the lubricating oil causes it to adhere to the journal where it is
"dragged" into the converging clearance space between the journal and liner. This
converging or wedging action results in a substantial increase in the oil film pressure,
which, in turn, supports the bearing load. The oil film pressure profile developed in a
typical journal bearing is shown in Figure 1-30. It can be seen from Figures 1-29 and 1-
30 that the journal will be displaced from the centre of the liner bore during operation.
25
This displacement is defined by two bearing parameters, namely, the attitude angle (a)
and the minimum oil film thickness (n).
The lubrication scheme employed for journal bearings is essentially the same for all
units. Lubricating oil is brought in at the bottom centerline of each bearing housing and
passed into an annulus, which circumscribes the outside diameter of the bearing liner.
The liner has oil inlet ports at its horizontal joints, which conduct the lubricant into the
clearance space between the journal and the babbitt surface. Some liners have additional
inlet ports at other locations on their periphery.
Fig. 1-28. Journal bearings.
After the oil reaches the journal surface, it is forced out the ends of the bearing where it
is collected and returned to a drain line. Each journal bearing is provided with an orificed
passage, which serves to control the oil flow to the bearings.
Fig. 1-29. Journal bearing oil wedges.
26
This orificed passage is located in the lower half of the bearing housing in some designs,
and in the liner feed portion in other designs. In addition to providing the bearing with its
proper oil flow, the orifice serves to limit the flow in the event of a wipe. This prevents
oil starvation from occurring at the other bearings in the machine.
Fig. 1-30. Journal bearing pressure profile.
The journal bearings fall in three categories. These are elliptical or two-lobe bearings,
three-lobe bearings, and tilting-pad bearings. There are numerous modifications made to
these three basic types. The addition of axial grooves and/or overshot dams are two such
modifications.
Thrust Bearings
A thrust bearing consists of a collar or thrust runner rotating against a mating stationary
plate surface, or bearing as shown in Figure 1-31. Thrust bearings are used to support
loads directed parallel to the rotor axis. These loads include aerodynamic thrust forces
generated within the compressor, bucket reaction forces, and pressure forces against
wheel and shaft surfaces. These bearings are hydrodynamic in operation, which means
that they derive their load supporting capability from thin oil wedges, just as in the case
of journal bearings.
Fig. 1-31. Thrust bearing.

27
Fig. 1-32. Thrust bearing oil wedge.
The oil wedge geometry, which occurs in a thrust bearing is shown in Figure 1-32. It can
be seen that this geometry differs slightly from that shown in Figure 1-30 for a journal
bearing, but the principle of operation remains the same. The oil pressure profile
associated with a thrust bearing is shown in Figure 1-33. It is apparent that the minimum
of oil film, and, therefore, the maximum Babbitt temperature developed in a thrust
bearing, occurs near the trailing edge of the bearing surface. This can also be seen in
Figure 1-33.
Fig. 1-33. Thrust bearing pressure profile.
The lubrication scheme employed for thrust bearings is similar in many respects to that
used a for journal bearings. Lubricating oil is brought in at the bottom centreline of each
bearing housing and passed into an annulus, which circumscribes the outside diameter of
the thrust bearing. The oil passes from this annulus through radial slots on the rear face
of the thrust bearing to the inside diameter of the bearing. The oil continues through the
cylindrical space between the bearing inside diameter and the rotating shaft to the thrust
28
runner. The oil is then carried out radially between the rotating thrust face and the
stationary bearing surface into a large annulus where it is collected and returned to the
drain line. Just as in the case of journal bearings, an orificed passage is placed in the oil
feed line of each thrust bearing. This orifice is located in the bearing housing
immediately upstream of the feed annulus.
The thrust bearings used fall into four categories. These are tilting pad self-equalizing
bearings, tilting pad non-self-equalizing bearings, tapered land bearings, and flat land
bearings. There are numerous modifications made to these basic bearing types, such as
the addition of oil control dams.
PART (1- B): MAIN GAS TURBINE AUXILIARY SYSTEMS

Lube Oil System
General
The lube oil requirements for the turbine, generator, reduction gear, accessory gear, and
other related equipment are furnished by a common lube oil system which includes the
following:
(a) Oil reservoir in the accessory compartment base

(b) Main lube oil pump-shaft driven from the accessory gear
(c) Auxiliary lube oil pump-a.c. motor drive
(d) Emergency lube oil pump-d.c. motor drive
(e) Pressure relief valve (VR-1) in the main pump discharge
(f) Double lube oil coolers with U-tube construction
(g) Double full-flow filters with replaceable cartridge
(h) Bearing header pressure regulator (VPR-2)
29
Lubrication of the gas turbine power plant is accomplished with a forced feed lube oil
system complete with tank, pumps, coolers, filters, valves and miscellaneous control and
protective devices. The lube oil is circulated to the two main bearings of the gas turbine,
various turbine accessories, flexible coupling(s) and load equipment. A portion of the oil
is diverted, and filtered for use by the various hydraulic control devices and functions as
hydraulic control oil. For starting, a reasonable viscosity is needed for reliable operation
of the control system and for lubrication of the bearings. Maximum viscosity at starting
should not exceed 800 SSU.
The lube oil pumps take their suction from the oil tank and the control oil pumps take
their suction from a bearing header. It is necessary that the oil be regulated to the proper
predetermined pressure in order to meet the requirements of the main bearings and the
accessory lube oil system as well as the hydraulic control trip oil circuit. All lubricating
oil is filtered and cooled before being piped to the bearing header with 5 micron
filtration.
The nominal capacities and ratings of the pumps, the estimated oil flow to the various
components, and the approximate ratings, sizes, or settings of the various orifices and
control devices are shown on the Schematic Piping Diagram.
Lube Oil Tank and Piping
The main lube oil tank is fabricated as an integral part of the turbine base under the
accessory compartment. Oil draining from the load equipment is piped to a common
drain header within the confines of the generator base. This drain oil flows forward to the
main tank, through piping which interconnects the generator base to a drain channel
fabricated in the turbine base. The tank is under a slight pressure from the seal air that
flows into the bearing seals and down into the tank. The complete lube oil system is
vented to atmosphere.
All of the lube oil piping is contained within the perimeter of the base. Wherever possible
the bearing lube oil feed pipes are contained inside the drain headers or channel. The lube
oil piping is seamless steel piping with welded joints. Installed in the tank and mounted
on its cover are the lube oil pump, filters, cooler(s) and various control devices. Provision
is made for access to the tank interior through a manhole, having a bolted-on cover,
which is located in the top of the tank.
An oil tank fill is provided in the side of the tank near the top and oil tank drains are
provided on either side of the base near the bottom. The capacity of the lube oil system is
approximately 1,700 gallons (6,440 litres) (6.44m3).
During standby periods, the lube oil is kept at the viscosity required for turbine start up
by heaters (23QT) installed in the main lube tank. Temperature switches (26QM) and
(26QL) sense tank oil temperature and control the heaters to maintain the correct oil
temperature to achieve allowable viscosity. Another temperature switch (26QN) also
senses tank oil temperature and will not permit the turbine to be started if the oil is below
the temperature required for correct viscosity for start-up.
30
Lube Oil Pumps
The lube oil system has five lube oil pumps:

1. The main pump is a positive displacement type pump, mounted in and driven by the
accessory gear
2. A lube oil auxiliary pump, driven by vertical a.c, (88QA) motor.
3. A lube oil emergency pump, vertical d.c. (88QE) motor.
4. Main hydraulic supply pump, shaft driven from necessary gear.
5. Ratchet pump, motor driven.
Main Oil Pump
The main lubricating oil pump is built into the inboard wall of the lower half casing of
the accessory gear. it is driven by a splined quill shaft from the lower drive gear. The
output pressure to the lube oil system is limited by a back pressure valve (VR-1) to 65
psig (450 kPag).
Auxiliary and Emergency Pumps
The auxiliary and emergency pumps are mounted on the oil tank cover. They are
submerged centrifugal type pumps, which provide lube oil pressure during start-up and
shutdown of the gas turbine.
A.C. Pump (Fig 2-1)
When a.c. power is available for the turbine starting and stopping sequence, the system
lube oil pressure is supplied by the a.c. auxiliary pump (88φA) during the time that the
main shaft driven pump is at too low a speed to develop sufficient pressure. At turbine
start-up, this pump starts to run when the master control switch on the turbine control
panel is turned to the START position. The a.c. pump continues to run until the turbine
reaches approximately 95 percent speed, at which point the pump will shutdown, and the
system will be supplied by the main shaft-driven pump. On turbine shutdown, the a.c.
pump starts with the closure of 14HSX relay contact when the turbine speed drops to a
value of between 75 and 90 percent. The pump continues to run throughout the shutdown
and the cool down period and until the operator gives a second stop signal by turning the
master control switch on the turbine control panel to STOP a second time.
The gas turbines are equipped with the immersion heaters (23QT) the a.c. pump will start
automatically whenever the heaters are on (to circulate the system lube oil). For this
function, the a.c. pump is controlled by the immersion heater contactor (52QT) which, in
turn, is controlled by temperature switches (26QL) and (26QM). The pump and heaters
are turned on by one lube oil temperature switch (26QL) and are turned off by another
lube oil temperature switch (26QM).
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Fig. 2-1. AC Oil pump out with the turbine base.
D.C. Pump (Fig 2-2)
When a.c. power is not available, the d.c. pump provides backup for the a.c. pump, as
follows:
At turbine start up, the d. c. pump starts automatically when the master control switch on
the turbine control panel is turned to the START position. The pump will run until the
turbine reaches approximately 40 percent speed. The pump will continue to run after 40
percent turbine speed if the system pressure has not reached the setting of pressure switch
(63QN).
The test valve and pressure switches are installed after an orifice in the pressure switch
piping, which is connected into the bearing lube oil header. The test valve is normally
closed and holds the lube system pressure on the switches. When performing a test, the
test valve should be opened gradually to lower the lube oil system pressure in the switch
piping. This oil pressure is indicated on a gauge, which is connected into the pressure
line. The gauge provides a means of checking the pressure points at which the switches
operate to indicate a condition of low lube oil pressure on the annunciator and to start the
emergency pump running.
32
Fig. 2-2. DC lube oil pump mounted in the turbine base.
When the oil pressure falls to the setting of pressure switch (63QA), the condition of low
lube oil pressure should be indicated on the annunciator. Further opening of the test valve
will reduce the pressure in the test line to the setting of pressure switch (63QL), which
should start the emergency pump running. Note that the annunciator drop indicates either
the condition of low oil pressure or, that the emergency pump is running. The indication
of low lube oil pressure should occur before the pump starts. When the test valve is
closed and the oil pressure is returned to normal, the emergency pump should stop by
restoration of pressure on pressure switch (63QN). The manual operation of the lube oil
pumps may be tested by operation of the control switches (43QE) and (43QC) at the
motor control centre. When tests are completed, the annunciator should be reset.
Pressure and Temperature Devices
Low lube oil pressure is detected by a simple pressure switch, which opens on decrease
of pressure to a specified value and trips the unit. Pressure switches (63QA) and (63QT)
are installed in the lube oil feed piping to provide an alarm and shut down the gas turbine
if the lube oil pressure should drop to an undesirable value. Likewise, temperature
switches (26QA) and (26QT) are installed in the piping to sound an alarm and trip the
unit should the temperature of the lube oil to the bearings exceed preset limits. The
settings of the switches are such that the alarm (26QA) is sounded before the turbine is
tripped by (26QT).
Provision is made for checking oil flow to the main machine bearings by oil sights,
thermocouples and thermometers. In addition, thermometers are provided to indicate the
temperatures in the tank and downstream from the lube oil cooler. Two regulating valves
33
are used to control the pressures in the system. A back pressure valve (VR-1) limits the
positive displacement main pump discharge header pressure and relieves to the lube oil
tank. The bearing feed header is maintained at design pressure by a diaphragm-operated
regulating valve (VPR-2) installed upstream from the lube oil coolers. It receives a
pressure signal from the bearing header and, when the header pressure exceeds the
control setting of the valve, the valve opens to dump oil to the lube tank.
Miscellaneous Lube Oil Devices (Fig 2-3)
Filters
Filters are used in the lube oil piping system to assure a clean supply of oil to the
bearings, couplings, accessories and load equipment. The main lube oil filter, mounted
on the lube tank cover, provides anomina15 micron filtration for the bearing and
accessory feed header. Oil, which is used for the hydraulic trip circuit is also filtered to a
nominal 5 microns while oil used for fuel gas control is filtered to a nominal ½ micron.
Five-micron, resin-impregnated, pleated paper elements are used for reasons of economy,
high dirt-holding capacity, low pressure drop and a small change in pressure drop with
variation in viscosity.
Oil Level Gauge and Alarm
The oil level gauge and alarm device is a hermetically sealed, float-arm-operated device,
which is mounted in the side of the lube oil tank above the maximum expected level of
the lube oil supply. The float mechanism operates a dial gauge and two electric switches
(71QH) and (71 QL) which are a part of the device. The switches are connected into the
annunciator circuit of the turbine control panel and operate an annunciator drop and an
audible alarm if the liquid level should rise above, or fall below, the levels shown on the
Lube Oil Schematic Piping Diagram.
Fig. 2-3. Lube oil filters out with the turbine.
34
Note:
The oil level gauge will indicate 'F' (Full) or 'E' (Empty), before the annunciator alarm is
given.
Oil Coolers (Heat Exchangers) (Fig 2-4)

Oil coolers of the extended surface type with "U" tube construction are installed in the
side of the lube oil tank.
Fig. 2-4. Lube oil tube bundles with header removed.
The oil is cooled with water from the cooling water system. Cooling water flow is
adjusted by a regulator (VTR-1), which automatically controls the flow of water through
its valve by responding to temperature changes which affect the sensing bulb.
35
Fig. 2-5. Gas turbine lube-oil system.
Fig. 2-6. Generator lube-oil system.
36
Variable Inlet Guide Vane Actuating System (Fig. 2-8)
In order to prevent possible pulsation in the gas turbine during acceleration and
deceleration, variable inlet guide vanes are installed in the aft end of the turbine's inlet
casing. The variable vanes, in conjunction with control of the tenth-stage compressor
bleed air (see Air Systems), permit rapid and smooth turbine starts and shutdowns
without compressor surge. The variable inlet guide vane actuating system is as stated
above comprised of the main hydraulic pump, hydraulic manifold assembly, hydraulic oil
filter, low hydraulic pressure alarm switch (63HQ), inlet guide vane solenoid valve
(20TV), guide vane limit switch (33TV), and hydraulic actuating cylinder. The rotable
shaft of each individual inlet guide vane extends through the compressor casing and is
geared to a circumferential inlet guide vane control ring on the compressor. Rotation of
this control ring varies the chord angle of each individual inlet guide vane in the
compressor. Thus, the inlet air flow of the turbine changes as a function of the inlet guide
vane angle position. A linear electro-hydraulic actuator is connected to the control ring
through a connecting link.
The start-up and shutdown logic sequence control requires that the inlet guide vane
control ring be at the closed position before the turbine is fired and remain in this closed
position until the turbine is at speed. The pickup of the high-speed relay (14HS)
energizes the turbine compressor inlet guide vane solenoid valve (20TV), which actuates
a hydraulic cylinder to open the vanes to their normal operating position for loading.
Similarly, the shutdown and trip logic sequence requires that the inlet guide vanes be
returned to their closed position when the turbine is stopped or tripped. A limit switch
(33TV) is installed on the inlet guide vane control ring to indicate through the turbine
control panel when the guide vanes are in a closed position. Thus, the inlet guide vanes
are operated with the same permissive sequence as the tenth-stage compressor bleed
valves, which are also required for pulsation protection of the turbine.
Fig. 2-8. Flow control, FCV and inlet guide vane solenoid 20TV.
Cooling Water System (Fig 2-11)
37
The cooling water system accommodates the heat-dissipation requirements of:
1. The Lube Oil System.

2. The Atomizing Air System.
Oil Fuel System
The Fuel Oil System delivers distillate fuel of appropriate quality from the customer’s
fuel forwarding station to the engine nozzle ports designed for the intended liquid fuel.
Fuel at low pressure is filtered and pressurized by a fuel oil pump. Pressure is modulated
by a Discharge valve system that bypasses excess fuel. High-pressure fuel is then filtered
again, throttled by control valves and metered to the individual nozzles by a flow divider.
System Components
The components of this system and their function in the system.
Duplex Filter Vessels, Low Pressure
The main pump suction filter is a set of 2 vertical filter vessels. The filters provide
additional protection against solid contaminants in the fuel oil supply. One filter is
always active. The filters are located on the Auxiliary Lube Oil skid. The vessels each
have inlet ports on the 3 m, incoming line, and outlet ports for the 3 in. line going to the
main fuel oil pump. The vessels contain banks of filter cartridge elements, 5-micron
pleated paper full flow type. The vessel can be opened for inspection after the oil is
drained. A manual transfer mechanism allows the active filter to be swapped online,
which protects the main pump from mechanical wear by filtering out foreign materials at
the pump inlet. The filter system includes:
Equalizing Hand Valve (normally closed). When temporarily opened, it provides a path
for pressure to build equally on both sides of the Transfer Switch. This allows for easier
movement of the Transfer Hand switch when system is running. Drain Valves (normally
closed) Hand operated at low tap points on each vessel. Used to drain oil from an
inactive vessel prior to maintenance inspection.
Vent Valves normally closed). Hand operated at high tap points on each vessel. Used to
assist in draining, or refilling after inspections are complete. Fuel Oil Filter Pressure
Differential Switch requires attention. Provides indication that active filler.
Fuel Oil Filter Pressure Gauge. Provides local indication of pressure inside the active
filter. Main Fuel Oil Pump Suction Pressure Switch Provides indication of insufficient
pressure in the 3 in. fuel pipe feeding the suction side of the main fuel pump, and
prevents starting in a cavitation situation.
Fuel Oil Supply Temperature Thermocouple Provides indication of oil temperature and
protection against over temperature. Tapped in a thennowell in the 3” fuel pipe before the
38
Main Fuel Oil pump. Fuel Oil Pump Pressure Relief Valve Provides a bypass around the
suction and discharge sides of the main fuel oil pump in case of excess discharge
pressure.
Gass Fuel System Combustion Turbine (Fig 2-16 & 2-17)
The gas fuel is supplied from the customer’s Sales Gas supply system to a Sales Gas
Conditioning Skid before advancing to the turbine Fuel Gas system.
System Components
The components of this system and their function in the system control schematic binder
(White Tab 5) and described below.
Sales Gas Conditioning Skid
Gas Knockout Drum
The knockout drum is a pressure vessel that provides additional protection against
condensates in the Sales gas reaching the engine. Vessel has 8 in. inlet and 10 in. outlet
ports for Sales Gas. A 2 in. port at a low point in the vessel allows for drain of
condensates to a customer Maintenance Drain connection. The drain system includes
manual and automatic drains. The inlet port includes provision for laying a nitrogen
blanket from a customer purge supply. Upper and lower sight glass chambers tap into the
vessel for visual and instrument readings of liquids. Instruments on the level chambers
each have isolation hand valves for maintenance, and test ports. Instruments include:


Analog Level Transmitter

Level indicator Gauge

Pressure Indicator

Level Switch, High Level

Level Switch, X High Level

Level Switch, Low Level

Automatic Drain Solenoid
Automatic Drain Valve (1 in.) (air to open). Also includes instrument air regulator
 Manual Drain Valve (2 in.)

isolation hand valves and 2 normally closed test port:
The gas regulator is a pneumatic valve that regulates the gas supply pressure to a
constant pressure. The 3 in. valve includes a pressure regulator for the instrument air,
hand vales (6 in.), and two test ports (normally closed).
Dual Fuel System Combustion Turbine (Fig 2-18)

The dual fuel system includes all components for the oil and gas fuel operation. In
addition to these two systems, certain instruments have additional functions unique to
fuel transfer.
39
Limit Switch-Gas Isolation Valve
In normal gas fuel operation, this switch is used for HMI indication that Fuel Gas
Isolation valve is not closed, and also gas start sequence logic confirmation. During
transfer from Oil to Gas, this switch is part of timeout protection that can abort the
transfer. It also acts as one of the conditions signaling transfer to gas is in process.
PRESSURE SWITCH - FUEL OIL NOZZLE
In normal fuel operation, this device is only an HMI indication. For transfer from Gas to
Oil, this switch is part of watchdog timeout that can abort the transfer. The controls the
fuel transfer process without any unique instrumentation in LOCAL or REMOTE mode,
manual Fuel transfer is initiated from keyboard selection on the HMI. Automatic fuel
transfer to fuel oil will be initiated by the following:
Signal from refinery DCS indicating low fuel gas supply pressure
High fuel gas knockout level
Low fuel gas temperature
High fuel gas filter differential
High fuel gas strainer differential
Failure of fuel gas filter/separator differential pressure transmitter.
Fig. 2-16. Typical fuel Handling and storage system.
40
Fig. 2-17. Fuel tank with floating suction.
41
Fig. 2-18. Dual fuel nozzle.
42
Generator Description
A. General Arrangement
These instructions apply to an outdoor type, air-cooled, non-salient-pole, 2-pole,

revolving field, a-c turbine generator with a brushless exciter. The generator is designed
so as to be suitable for use with a Westinghouse gas turbine.
Air coolers are not used. Instead, the non-recirculating ventilation system draws in
outside air thru filters and a silencer, and discharges the air to atmosphere thru another
silencer. The generator rotor is supported by a bearing bracket at each end, and the
exciter has a single pedestal bearing support. A bedplate is used under the generator so as
to raise the centerline of the generator rotor to the same level as the shaft of the gas
turbine. This bedplate also contains oil piping and electrical conduits.
To facilitate rapid installation of the complete gas-turbine generator and switchgear the
generator-exciter package is preassembled and prewired at the factory to the maximum
extent permitted by shipping limitations. To accomplish this, the exciter housing is
shipped assembled with the generator. For the same reason, several items of switchgear,
such as current transformers and neutral grounding equipment, are incorporated in the
generator assembly. Those are mounted in the air inlet side housings which are shipped
separately, due to dimensions beyond shipping limits, and are then attached at
installation. The top discharge housings are also shipped separately and assembled at
erection. Electrical circuits requiring grounding are connected to the generator frame or
bedplate. Grounding pads on the generator bedplate provide for electrical connections to
the external ground available at the installation site.
B. Stator
B1. Frame and Core
The generator frame and the enclosing end brackets are fabricated from steel plate which
is rolled and welded to form the required shapes. The generator frame feet rest on the
bedplate, which in turn rests on the foundation. The stator is constructed with a core and
a frame. The core is stacked and wound, and the frame is fabricated and machined. The
core is attached to the frame by means of a set of flexible springs. This flexible mounting
is such that very little of the double frequency vibration in the core is transmitted to the
frame feet.
The stator core consists of silicon steel laminations. Both sides of the laminations are
treated with an insulating material to prevent short circuiting the laminations. Vent
spacers are built in with laminations at intervals to provide passages thin the core for the
ventilating air. Adequate pressure is applied during the stacking operation to produce a
tight core. Heavy endplates and non-magnetic finger plates are used at both ends of the
core to maintain adequate pressure on the laminations at all times. This machine has
insulated non-magnetic thru-bolts which extend axially thru the punchings back of the
43
slots. These bolts apply pressure on the endplates to maintain pressure on the
laminations. After being assembled, the entire core is coated with varnish to protect it
from rust.
B2. Winding
The stator winding of this generator has THERMALASTIC, Class B insulation, and
groups of strands are transposed in the slots and at the ends to reduce eddy current losses.
Corona is suppressed in the following manner: Conducting varnish on the slot portion of
the coil contains the dielectric stress within the solid insulation. High resistance Coronox,
on the portion of the coil end which adjoins the slot portion, grades the voltage stress
along the coil surface. Corona resistant treatment is applied to the coil ends beyond the
portions treated with Coronox.
Resistance type temperature detectors calibrated for 10 ohms at 25 ºC are embedded
between coils in various slots in the stator winding of the machine in order to obtain an
indication of the operating temperature.
The leads from the temperature detectors are connected to terminal boards. Refer to
Temperature Detectors in the section of this book under operation. The end turns of the
stator windings are braced against short circuit stresses by lashing the coils with glass
twine to Micarta brackets which are firmly bolted to the endplates.
C. Rotor
C1. Construction
The rotor is a one-piece steel forging with integral shaft ends. Radial slots for the field
windings are machined in the rotor body. Extensions of these slots as well as radial holes
drilled in the rotor teeth provide passages for the ventilating air.
C2. Winding
The arrangement of a typical rotor winding in place in the slot. The insulation is full
Class B with molded mica between the winding and ground, and flat melamine Micarta
insulation between turns. The top turns are mica taped for extra insulation. Rotor coils
are baked under radial pressure until the winding becomes a solid mass. The coils are
held in the slots by sturdy non-magnetic wedges. The rotor end turns are supported
radially by forged steel retaining rings which are lined with asbestos Micarta. The
retaining rings are shrunk and keyed onto the ends of the rotor body.
Ventilating air passes under the end of the retaining ring, flows over the rotor winding
end turns, and discharges thru radial holes and slots in the ends of the rotor body. Axial
support is provided to the coil end turns by means of fined Micarta blocks which also
serve to direct and control the flow of ventilating air over the end turns. A portion of the
air flows underneath the rotor winding and is discharged thru the holes that are drilled in
the rotor teeth.
44
C3. Blowers
An axial flow blower is mounted on the shaft at each end of the generator to force the
ventilating air out of the generator. The construction of the blower and the method of
assembly are shown in
D. Lubricating Supply System
The generator lubricating oil pipe connections. The lubrication system which serves the
gas turbine also serves the generator has a destructive effect upon the shaft journals and
bearings. To block the flow of any current thru this circuit, suitable thicknesses of
Micarta are placed between the bearing and the bearing housing, and insulated hardware
is used at the seals.
E. Bearings and Shaft Seals
The turbine end of the rotor is solidly connected to the shaft of the gas turbine. The
exciter end and turbine end of the generator rotor are supported by bracket type sleeve
bearings. The bearing brackets are bolted solidly to the outer frame of the generator.
Dowels are provided in the bottom half of the bracket for locating purposes. Pressurized
air seals are bolted onto both the inner and outer face of the bearing bracket to prevent
leakage of oil into the generator and exciter. Each of these seals has two chambers. The
inner chamber is vented to the atmosphere, while the outer chamber is supplied with air
under pressure. This type of construction, in conjunction with labyrinth seals, effectively
prevents oil vapor leakage. These seals are adjustable to give proper clearance to the
generator shaft. For proper method of setting the seals. Drawings of the bearing brackets,
bearings, and seals.
F. Blower Shroud
Each bearing bracket supports a blower shroud that carries the stationary blower blades.
The features and method of assembly of the blower shroud.
G. End Bells
The end bells on each end of the generator enclose the end turns of the stator winding
and serve to direct the air flow discharging from the blower. They are attached to the
frame rings inside the generator.
H. Generator Main Leads

The three line leads are brought out at a covered opening at the exciter end of the
generator, on the right side of the frame as viewed from the exciter end. A flange permits
the attachment of weatherproof bus duct continuation. The joints -between the main leads
and the external bus bars must be taped at installation, and the bus must be separately
supported. Flexible connectors are required between the line leads and the bus.
45
The three neutral leads remain inside the generator. The neutral point of the winding is
formed by a bus bar inside the side housing opposite the main leads. A cable connects the
neutral point of the stator winding to ground thru standard neutral grounding equipment
which is supplied as part of the generator and is mounted inside the enclosure at the
exciter end of the generator.
Current and potential transformers are installed with the main leads, two current
transformers at each of the line and neutral leads, and four potential transformers
connected in open delta. Space is provided to permit installation of one additional current
transformer per lead.
I. Mechanical Rotation
The generator will rotate in the direction indicated by the Outline Supplement.
J. Phase Sequence
The voltages induced in the phases will reach positive maximum values in the order
specified on the Outline Supplement.
K. Shaft Currents
Variations in reluctance in the magnetic circuit of an alternating current machine may

cause periodic changes in the amount of flux which links the shaft. This change in flux
may generate sufficient voltage to circulate current thru the circuit consisting of shaft,
bearings, and frame. If this current is permitted to flow, it soon has destructive effect
upon the shaft journals and bearings. To block the flow of any currents thru this circuit,
suitable thickness of Micarta are placed between the bearing and the bearing housing,
and insulated hardware is used at the seals.
L.Ventilation
In the open-type, non-recirculating ventilation system used, all air is circulated by the
two shaft-mounted, axial-flow blowers. Air is drawn into the system through two
Louvered openings, one on each side wall of the side housings. The air is cleaned as it
passes through banks of wire mesh filters. From there, the air passes radially inward to
the stator core and the rotor winding. Some of the air enters the exciter housing. In
ventilating the active parts of the generator, the cooling air enters orificed openings at the
outside of the stator core. These connect directly to the air vents, in which the air passes
radially inward and eventually discharges to the air gap between the rotor and stator,
absorbing the stator core and copper losses in the process. In the air gap, the air flows
axially toward each end of the generator, cooling the rotor surface along the way.
Some of the cool air flows thru passages provided in the frame towards the ends of the
blower hubs which are mounted on the shaft ends. Entering thru channels cut in the
blower hubs, the circulating air ventilates the rotor as described in paragraph C2.
46
All the air collected at the ends of the air gap returns to the respective blower inlets to be
exhausted back to the atmosphere through the top housing and through the discharge
muffler located above this housing. Cool filtered air for ventilating the brushless exciter
is bled from the inlet openings at the exciter end of the generator thru ducts connecting to
the exciter housing. After cooling the exciter, the air is discharged into the generator
discharge passage.
M. Auxiliary Wiring
Lights and Outlets in Exciter End Housing
Beside the door in the exciter housing is a suitable switch to control the lights inside the
housing. Near the switch is a convenient outlet to which portable electric equipment may
be connected.
Space Heaters
Some of the space heaters are intended to prevent condensation of moisture on the
equipment. Such heaters are located in the lower part of the generator frame, in the
portions of the side housings which contain the main and neutral leads and auxiliary
transformers, and in the exciter housing. Additional heaters are distributed across the
surface of the precipitation trap which protects the generator from rain or snow which
might enter the exhaust duct during a shutdown Such heaters are energized when
necessary to melt any snow which might obstruct the flow of air.
Vibrometers
A vibrometer pickup is mounted at each of the three bearing housings. They are of the
shaft proximitor type and require special adjustment. For shipping purposes, the shaft-to-
sensor gap is approximately 0.50 inches. At erection the pickup must be reset for a 0.05
to 0.06 inch gap.
Stator Winding Temperature Detectors
Twelve of the stator slots contain resistance temperature detectors embedded between the
upper and lower coil sides. Each has a copper element having a resistance of 10 ohms at
25ºC. The temperature coefficient on resistance is 0.00427 per ºC at 0ºC. This results in
the following relation between detector resistance (RT) in ohms and the temperature (T)
in ºC.
RT = 10 (T ± 234.5) / 259.5
Air Temperature Detectors
Four iron-constant and thermocouples are located in the various air streams. One each is
located in the air inlet and air outlet of the generator and in the air inlet and air outlet of
the exciter.
47
Bearing Oil Drain Temperature Detectors
Three iron-constantan thermocouples are provided. One is located in each of the oil drain
pipes leading away from the two generator bearings and the one exciter bearing.
Current Transformers on Main and Neutral Leads
On each of the six main and neutral leads of the Y-connected stator winding, two current
transformers are provided. They are located inside the generator side housings at the
exciter end. Each has an ampere ratio of 4000/5. The secondary leads are to terminal
boxes at the turbine end of the generator. Space is provided for a third current
transformer on each lead if it should be required.
WARNING:
Be sure to observe the precautions relative to not operating the generator with the current
transformer secondaries open-circuited.
Neutral Grounding Equipment
The neutral point of the Y-connected stator winding is formed inside the side housing by
a neutral shorting bar which connects leads T4, T5, and T6 together. The neutral point is
grounded to the bedplate through neutral grounding equipment mounted in the housing
near the neutral leads.
Potential Transformers on Main Leads
The main leads are furnished with a complement of 4 potential transformers connected in
open delta. The transformer ratio is 120/1. These transformers are fused on the primary
side. They are located in the side housing below the main lead compartment. Access to
the transformers and fuses is gained by removing the filters for exciter intake air. The
secondary leads of the transformers are brought to a terminal board near the turbine end
of the unit.
Exciter Field Winding
A pair of leads brings field current to the stationary field windings of the a-c exciter
which is part of the brushless exciter. These leads run to one of the auxiliary terminal
boards at the turbine end of the generator.
Terminal Boards
Leads from all auxiliary wiring are brought to terminal boxes and boards located near the
turbine end of the generator frame.
48
Plug Type Connectors
To expedite installation of the generator, plug type connectors are used to join the wires
from the resistance temperature detectors and the vibrometers with the external wires
leading to the automatic control system.
49
OPERATION SEQUENCES
To start a unit generally involves selecting a fuel, selecting a mode of operation,
initiating a unit start, synchronizing and loading the unit. The unit can be synchronized
manually or automatically and loaded manually or automatically.
MODE SELECT
MODE OF Description NOTES
OPERATION
OFF The “OFF” mode is selected after a unit
stop has been completed. The OFF
command prevents "inadvertently” starting
of the unit. OFF cannot be selected while
the unit is starting or running.
CRANK The “CRANK” mode is usually selected Use for axial compressor
when the unit is to be rotated at or near its cleaning, “forced” cooling of
purge speed without admitting fuel,
the unit or heat recovery
CRANK mode cannot be selected any time
after the unit has fired. steam generator or shaft
rotation after a failure of the
unit to go on cool down after
a shut down or trip.
FIRE The “FIRE” mode is selected when it useful to dry the unit after a water
desired to “fire” the unit (admit and ignite wash if it is not going to be
fuel) but not bring it to full speed. operated within the next 12 hours.
“STARTING”, then “FIRING”, and after
flame has been initiated, “WARMING UP”.
Once flame has been initiated, fuel flow will
remain at the pre–set warm–up value.
Since the unit is not self–sustaining at low
speeds, the starting means will continue to
provide torque to the unit.
AUTO The “AUTO” mode is the normal mode of
operation selected when a unit is to be
started
REMOTE Selecting the “REMOTE” mode allows the Personnel must remember that
plant’s central control system (DCS). when REMOTE is selected, the
local is still able to issue
The switching from REMOTE to AUTO and commands to the control panel;
back must be done from the local panel. control does not transfer to the
plant control.
COOLDOWN CONTROL
MODE OF Description NOTES
COOLDOWN
ON - the ac–powered lube oil pump will operate, *used during unit cool down to
RATCHET Providing both lubrication and the “muscle” prevent rotor bow.
ON needed for rotor rotation.
OFF - COOLDOWN OFF” or “RATCHET OFF” GT 9001E will not accept a
RATCHET will terminate the cool down cycle. COOLDOWN OFF until 12–14
OFF hours after the unit has been
shutdown.
50
*If the rotor was to remain stationary after being shutdown, the upper half of the rotor would
tend to get warmer than the lower half and the rotor would bow‫الـتقوس‬. This could cause a
vibration problem during a subsequent start–up or might prevent the rotor from turning at all.
LOAD CONTROL
LOAD Description NOTES
SELECTION
The unit will automatically load or
PRE–SELECT unload at the automatic loading rate
LOAD until the preselected load output is
attained.
fuel flow is regulated to
provide the maximum power
When “BASE LOAD” is selected, the for the ambient conditions
unit will load at the normal loading without “over firing” the
rate until the unit goes on exhaust machine.
BASE LOAD temperature control; at this point, It is important to note that as
the unit is at its nominal rated power ambient conditions change,
output for the ambient conditions. primarily compressor inlet
temperature, the unit’s power
output will change.
When selected, the unit will load at
the normal loading rate until the unit One hour of PEAK operation is
goes on peak exhaust temperature equivalent to six hours of
EXT LOAD
control. When operating on PEAK, BASE operation.
the unit is operating at a firing
temperature above its design limit
NORMAL START-UP
The initial conditions are as follows:
1- No work permit opened.
2- Shaft line at standstill or at turning gear speed.
3- Fire detection and protection operational.
4- Power equipment available and operational.
5- Fluids available with the correct levels (cooling water in makeup tank, oil level transformers…etc).
6- Fuel available.
7- Start-up permissive green status.
If the shaft is already in turning gear sequence, as soon as start command is initiated, the turning gear
motor stops, the starting motor starts and the sequence proceeds as described below.
When the gas turbine has been at standstill for more than two days without barring, it is recommended
to start the auxiliaries first and keep the machine at turning speed for few minutes, as described in the
above chapter “cool down sequence”. After few minutes running, the normal start up sequence may be
initiated.
Input Description Output State

Mode Select : The automatic mode is selected.
Auto
Start The visual alarms on the turbine Blinking Duration
command compartment blink to indicate the ‫وقت لان ا داخل الوحده لتح ير من بداخل الوحده‬
imminent start of the following
components :
The emergency lube oil pump proceed to 88QE ‫ااختبا ااتوماتيكي‬ 1/0
test sequence.
51
The turbine compartment ventilation is 88BT 1
running.
The gas compartment ventilation is 88VL 1
running.
The auxiliary oil pump starts, the oil 88QA 1
pressure builds up.
The oil mist eliminator fan starts. 88QV 1
The generator lift oil pumps start. 88QB 1
The drive motor of the torque converter Approx. 67degree
blades puts the converter in the
maximum torque position.
The high pressure oil pump starts. 88HQ 1
The starting motor starts. 88CR 1
14HR The shaft starts, the "zero speed" signal
detects start of rotation.
14HT The gas leak test is activated. @4 - 6 % speed (120 - 180
rpm).
The exhaust compartment ventilation is 88EF 1
running.
14HM The shaft speed reaches the firing Minimum
threshold ‫مستوى ااشتعال‬. speed@16%(approx.
480rpm)
The exhaust duct purge cycle is 3 min.
activated,
The drive motor of the torque converter Approx. 16 degree
blades puts the converter in the minimum
torque position.
The turbine speed decreases to reach
firing speed
The firing sequence is activated. Approx. @ 390 rpm
The firing transformers are energized.
The fuel valves open.
28FD Presence of flame is detected in the Approx. @350 rpm
combustion
chambers.
The drive motor of the torque converter
blades puts the converter in the
maximum torque position.
The ventilation of the load compartment 88VG 1
is active.
After firing, the fuel flow is maintained at 1 min.
its warm up value for one minute.
The fuel flow gradually increases to
accelerate the shaft.
The generator lift pump stops. 88QB 0
14HA The "acceleration" speed threshold is Approx. 50% (1500 rpm)
reached.
14HC The self-sustaining speed threshold is Approx.60% (1800 rpm)
reached.
The starting motor stops. 88CR 0
14HS The auxiliary oil pump stops. 88QA Approx.95% (2850 0
rpm)
The high pressure oil pump stops. 88HQ 0
The first cooling fan of the exhaust frame 88TK 1 1
starts.
The second fan starts a few seconds 88TK2 1
after the first.
The generator is excited.
Turbine at nominal speed.
52
NOW, Gas turbine is at nominal speed, generator excited at nominal voltage, turbo-generator set ready to
be synchronized to the grid for electrical power supply.
Mark VI Start-up Curve

SYNCHRONIZING
1- Turbine at nominal speed.
2- Generator excited at nominal voltage.
3- Grid available.
INPUT Description Output STATE

Sync Control : The Speedtronic adjust the speed of the unit and the
AUTO SYNC generator voltage.
The generator circuit breaker closes automatically.
NOW, Unit reaches spinning reserve load.
53
NORMAL SHUTDOWN
1 - Set synchronized to the grid.
Or
2 - Gas Turbine at full speed no-load.
INPUT DESCRIPTION OUTPUT STATE
1- Set synchronized to the grid:
Master control : The load drops down to
Stop the reverse power relay
threshold
The set’s circuit breaker
opens.
The compressor bleed
valves open.
2-Gas turbine at full speed no-load:
Deceleration of shaft
due to decreased fuel
flow.
14HS The auxiliary oil pump 88QA 1
starts.
The high pressure oil 88HQ 1
pump starts.
The cooling fans of the 88TK1,2 0
exhaust frame stop.
The loss of flames is
detected.
The ventilation of the 88VG 0
load compartment is
stopped.
54
One of the bearing lift 88QB 1
pump starts.
14HT The exhaust 88EF Approx. @ 0
compartment ventilation 4%(120 rpm)
stops.
Turning gear motor 88TG Approx. @ 1
starts. 99 rpm.
The drive motor of the Approx. 44 degree
torque converter blades
puts
the converter in the
turning torque position.
After 1 hour the 88BT 1 AND 0
selected turbine
compartment fan
restarts according to
wheelspace
temperatures.
NOW, the shaft line is rotating at turning gear speed to allow the cooling cycle to be carried out.
Automatic shutdown is forbidden the first hours of cooling.
AUXILIARIES SHUTDOWN
Operation consists of stopping the shaft turning gear after a complete cooling down period of the gas
turbine.
INPUT DESCRIPTION OUTPUT STATE

Cool down The turning gear motor 88TG 0
control : OFF stops.
The shaft line speed
decrease.
14HR 14HR confirm that the
shaft line stops.
The bearing lift pump 88QB 0
stops.
The auxiliary oil pump 88QA 0
stops.
The high pressure oil 88HQ 0
pump stops.
NOW, the gas turbine is at standstill.

Starting sequence is possible at any time.
EMERGENCY SHUTDOWN
This manual or automatic operation consists in quickly closing the fuel valve in order to stop the fuel flow.
This action can be initiated with the gas turbine loaded, starting or in normal shutdown condition:
1- Either by pressing an emergency shutdown pushbutton.
2- Or through the operation of an electrical or mechanical protection.
START PROCEDURE:
Step 1: Mode Select To “AUTO”: Press "F1" then choose AUTO then enter.
Step 2: Master Control “START” Signal: Press "F2" then choose START then enter.
Step 3: Load Selection to Base Load: Press "F5" then choose BASE then enter.
STOP PROCEDURE :
Normal Stop Command: Press "F2" then choose STOP then enter.
Cool down On: Press function key “F15” (press down on the “SHIFT” and “F5” keys simultaneously).
then choose Cool down On then enter.
55
Cool down Off: Press function key “F15” (press down on the “SHIFT” and “F5” keys simultaneously)
then choose Cool down OFF then enter.
SPEED DETECTORS:
L14HR Zero–Speed (approx. 0% speed)

L14HM Minimum Speed (approx. 16% speed)
L14HA Accelerating Speed (approx. 50% speed)
L14HS Operating Speed (approx. 95% speed)
56
PART (1-C): GAS TURBINE MAINTENANCE
General
Operation of the combustion gas turbine, as of any rotating power equipment, must
include a planned program of periodic inspection, with accompanying repair and
replacement of parts as necessary, to ensure the maximum availability and reliability of
the unit.
The object of this Maintenance Section is threefold:
1. To aid the user in becoming familiar with the unit by separating the inspections
according to specific systems and, where appropriate, describing briefly the reason for
the inspection and the action to be taken.
2. To identify those components and parts that should be periodically examined between
the initial start-up tests and the designated inspection.
3. Inspection intervals herein are based on engineering judgment and experience gained
with gas turbine units. The actual time interval established for any particular gas turbine
should be based on the user’s operating experience and on ambient conditions, such as
humidity, dust, and corrosive atmosphere.
Prior to scheduled inspections or taking operating data, clean the compressor per the gas
turbine compressor cleaning procedure in the Standard Practices. Before and after any
inspection a complete set of operating data including vibration readings should be taken
and recorded for reference. A record of the inspections made and the maintenance work
performed will be most valuable in helping to establish a good maintenance program for
the gas turbine unit(s).
It is expected that the maintenance program will start with minor work, and increase in
magnitude over a period of time to a major overhaul, and then repeat the cycle. The
performance of inspections can be optimized to reduce unit outage time and maintenance
cost for a particular mode of operation, and still maintain maximum availability and
reliability of the unit.
Operating Factor Affecting Maintenance
The factors having the greatest influence on the life of parts for any given machine are
shown in Table 5-1.
 Type of fuel
 Starting frequency
 Load cycle
 Environment
 Maintenance practices
Table 5-1. Parts life factors.
57
NOTE:
The effect of maintenance factors for fuel, starts and load duty are cumulative if all the
above factors are present. It should also be understood that as the maintenance factor
increases the time between inspections and component repairs decreases and it is possible
that component replacement frequency will increase.
Fuel
The effect of the type of fuel on parts life is associated with the radiant energy in the
combustion process and the ability to atomize the various liquid fuels. Therefore, natural
gas, which does not require atomization, has the lowest level of gradiant energy and will
produce the longest life of parts.
Fig. 5-1. Effects of fuel.
Natural gas has been the traditional fuel for use with gas turbines in industrial
applications. Limitations on the available supply of natural gas, with the resultant
increase in costs, have led to the consideration of liquid fuels to a greater degree than at
any time in the past. Of the liquid fuels, distillate fuel will produce the next highest life,
and crude oil and residual oils, with the attendant higher radiant energy and more
difficult atomization, will produce shorter parts lives, as shown in Figure 5-1.
Contaminants in the fuel also affect maintenance intervals. This is particularly true for
liquid fuels in which dirt results in accelerated replacement of pumps, metering elements,
and fuel nozzles. Contaminants in fuel gas can erode or corrode control valves and fuel
nozzles. The limiting item to continuous operation on liquid fuels is the fuel nozzles.
Exceptionally “clean” fuel can increase this interval, while “dirty” fuel will decrease it
accordingly.
Starting Frequency
Each stop and start of a gas turbine subjects the hot gas path to significant thermal cycles.
Control systems are designed and adjusted to minimize this effect. However, a gas
58
turbine with frequent starting and stopping requirements will demonstrate parts lives that
are shorter than those for a similar unit in continuous-duty service. See Figure 5-2.
Fig. 5-2. Effects of starts.
Load Cycle
The load cycle of the gas turbine, up to its continuous rating, will have little effect on
parts lives, provided it does not require frequent and rapid load changes. See Figure 5-3.
Fig. 5-3. Effect of load duty.
Environment
The condition of the inlet air to the gas turbine can have a significant effect on
maintenance costs and intervals if it is either abrasive or corrosive. If abrasives are in the
inlet air (e.g., as from sand storms), careful attention should be paid to inlet filtering in
order to minimize this effect. If the gas turbine is to be operated in a corrosive
atmosphere (for example, one with salts) careful attention should be paid to the location
of the inlet air arrangement and the application of correct materials and protective
59
coatings. It is essential during the planning stages of an application to recognize any
abrasive or corrosive contaminants and to take the necessary steps to minimize them.
Maintenance Practices
Parts condition information is based on estimates only, and will vary with machines and
specific operating conditions. However, estimates based on previous experience can be
very useful in planning a maintenance program. As actual operating data is accumulated
on a specific application, adjustments of inspection cycles should be the next step in a
well-planned program.
Initial inspection planning can be based on the combustion inspection schedule, hot gas
path inspection schedule, and major inspection schedule tailored to your unit and
estimated outage requirements listed in Table 5-2.
Type of Inspection 8 Hour Shift

Combustion 10
Hot Gas Path 21
Major 38
 No repair time – replacement only

Assumptions
 All parts available

 All necessary tools available
 Crew with average trade skill
 Inspection has been pre-planned
Table 5-2. Estimate outage requirement.
It must be recognized that the foregoing estimated outage requirements can be used for
estimating maintenance cycles, however, these numbers will vary depending upon the
many factors which establish the operating conditions for a specific installation. The
inspection cycles will vary depending upon fuel, duty cycle and maintenance philosophy
of the owner. The inspection man-hours will vary depending upon pre-planning,
availability of parts, productivity, weather conditions, union regulations, supervision, etc.
Good maintenance planning for minimum down-time requires the availability of
replacement parts, either new or previously repaired, that can be exchanged with existing
parts. The exchanged parts can then be repaired without extending the down-time. To
ensure optimum performance of the gas turbine, the minimum stock of spare parts should
be able to support the service inspection. A predetermined central location can stock
spare parts that are adequate for hot gas path inspection. Many gas turbine plants stock
capital spare parts on-site, recognizing that this parts availability minimizes the turn-
around time required for major overhauls. The planned maintenance program anticipates
the needs of the equipment and is tailored to meet the requirements of the system for
utilization, reliability, and cost.
60
Types of Inspections
The types of inspections covered in this publication may be broadly classified in terms of
unit “running” and unit “shutdown” inspections. The running inspection is performed
during start-up and while the unit is operating. This inspection indicates the general
condition of the gas turbine unit and its associated equipment. The shutdown inspection
is performed while the unit is at a standstill. The shutdown inspections include
“Combustion,” “Hot Gas Path” and “Major” inspections. These latter inspections require
disassembly of the turbine in varying degrees. See Figure 5-4.
61
Fig. 5-4. Types of shutdown inspections.
Turbine starting reliability can be aided by conducting a “standby” inspection while the
unit is shutdown. Routine servicing o the battery system, changing of filters checking oil
and water levels, cleaning relays, checking device settings an calibrations, lubrication
and other genera preventative maintenance can be performed in off-peak hours without
interrupting the availability of the turbine. Certain designated accessories in need of
repair o replacement may be returned to the factor on either a repair and return basis or
an exchange basis.
Periodic test runs are also an essential part of a good maintenance program. It is highly
recommended that the unit be operated at load for at least 1 hour bi-monthly, and data
recorded. This operation should dry out the moisture which may accumulate inside the
ducting and other components due to the variation in atmospheric temperature and
62
humidity. The unit is to be down for long periods o time, place on turning gear weekly a
circulate lubricant to recoat journals to prevent rusting. Special inspections such as bore
scope or eddy current probe can be used to further plan periodic maintenance without
interrupting availability. It is also recommended that visual inspections be performed
whenever there are personnel at the unit.
Combustion Inspection
A short “shutdown” inspection is required to change out fuel nozzles and to check the
combustion liners, transition pieces and crossfire tubes. These parts require the most
frequent attention, as continues operation with a deteriorated combustion system can
result in much shortened life of the downstream parts, such as turbine nozzles and
buckets. It is also inherent in the gas turbine design that these parts are the first to require
repair or replacement. Therefore, the importance of this inspection in the maintenance
program must be emphasized.
A visual inspection of the leading edge of the first-stage turbine nozzle partitions and
buckets should be made during the combustion inspection to note any wear or
deterioration of these parts. This inspection will help to establish the schedule for the Hot
Gas Path inspection. The combustion liners, transition pieces, crossfire tubes, and fuel
nozzles should be removed and replaced with new or repaired liners, transition pieces,
crossfire tubes and new or cleaned fuel nozzles. This procedure reduces downtime to a
minimum and the removed liners, transition pieces, crossfire tubes, and fuel nozzles can
be cleaned, inspected and repaired later when it is more convenient.
After the combustion inspection is completed and the turbine has been returned to
service, the removed liners, and transition pieces can be bench inspected and repaired if
necessary, by competent service personnel, or off-site at a qualified service facility. Off-
site cleaning inspection and repair of the liners and transition pieces is recommended,
since this activity can best be performed where specialized equipment and fixtures are
available. The removed fuel nozzles can be cleaned on site. Liquid fuel nozzles should be
stored in sets, all by the same manufacturer, for use at the next inspection.
Hot Gas Path Inspection
The Hot Gas Path inspection includes the Combustion Inspection just described and, in
addition, a detailed inspection of the turbine nozzles and turbine buckets. To perform this
inspection, the top half of the turbine case (shell) and the first-stage nozzle must be
removed. The second-stage nozzle, the third-stage nozzle, and the turbine buckets will be
inspected visually while still in place in the unit. A complete set of turbine clearances
should also be taken during any inspection of the hot gas path. Figure 5-4 shows the
components involved in the hot gas path inspection. As with the combustion inspection,
it is recommended that replacement combustion liners, fuel nozzles and transition pieces
be available for installation at the conclusion of the visual inspection. The removed parts
can then be inspected at a qualified service facility and returned to stock for use during
the next inspection. It is also recommended that the Hot Gas Path inspection be
conducted under the technical direction of the Manufacturer Field Service Representative
for accurate analysis of inspection data and most effective use of outage time.
63
Major Inspection
The Major Inspection involves inspection of all of the major “flange-to-flange”

components of the gas turbine which are subject to wear during normal turbine operation.
This inspection includes elements of the Combustion and Hot Gas Path inspections. In
addition, casings are inspected for cracks and erosion, compressor rotor and stator blades
are to be checked for tip clearance, rubs, bowing, cracking, and war pages. Shrouds are
checked for clearance, erosion, rubbing and build-up. Seals and hook fits of nozzles and
diaphragms are inspected for rubs, erosion, fretting or thermal deterioration. The
compressor and inlet are inspected for fouling, erosion, corrosion, and leakage. Bearings
and seals are inspected for clearance and wear. All clearances are checked against their
original values.
Inspection Intervals
It is important to develop a schedule of inspection intervals and maintenance procedures

based on the utilization of the equipment and the experience accumulated during its
operation. A schedule developed in this manner will result in minimum downtime and
lowest overall maintenance costs.
Tables 5-3 and 5-4 lists the recommended combustion, hot gas path, and major
inspection intervals for all MS 9001 gas turbine duty applications at the base load firing
temperature mode. Inspection frequency intervals for peak load firing temperature will be
provided by the Gas Turbine Division if the user plans to consistently operate at this
mode.
Table 5-3. MS 9001 model E inspection intervals (Combustion inspection).
64
Table 5-4. MS 9001 model E inspection intervals (Hot gas path and major inspection).
65
Part (2) : Advanced Brayton Cycles
Advanced Brayton Cycles

Introduction
Gas turbines could play a key role in the future power generation market addressing issues of
producing clean, efficient, affordable, and fuel-flexible electric power. Numerous projections
estimate that gas turbines will comprise a significant portion of the required generation
capacity in the 21st century. Novel advanced gas turbine cycle modifications intended to
improve the basic Brayton cycle performance and reduce pollutant emissions are currently
under development or being investigated by gas turbine manufacturers and Research and
Development (R&D) organizations.
Preliminary conceptual analyses of advanced cycles indicate that it may be possible to
achieve an improved combination of efficiency, emissions, and specific power output which in
turn should reduce the power generation equipment cost on a $/kW basis.
Developing turbine technology to operate on coal-derived synthesis gas and hydrogen is
critical to the development of advanced power generation technologies and the deployment of
Future Gen plants. The Future Gen plant concept may also be deployed in natural gas-based
plants with respect to generating power with near-zero emissions while utilizing these
advanced Brayton cycle machines and securing fuel diversity.
Gas Turbine Technology

A conventional gas turbine cycle consists of pressurizing a working fluid (air) by compression,
followed by combustion of the fuel; the energy thus released from the fuel is absorbed into the
working fluid as heat (see figure 1). The working fluid with the absorbed energy is then
expanded in a turbine to produce mechanical energy, which may in turn be used to drive a
generator to produce electrical power. Unconverted energy is
66
exhausted in the form of heat which may be recovered for producing additional power. The
efficiency of the engine is at a maximum when the temperature of the working fluid entering
the expansion step is also at a maximum. This occurs when the fuel is burned in the presence
of the pressurized air under stoichiometric conditions.
Fig.(2-1) Gas Turbine and the Ideal Brayton Cycle P-V Diagram
When natural gas is burned with air under stoichiometric conditions, however, the resulting
temperature is greater than 1940ºC (3500ºF) depending on the temperature of the combustion
air. It is therefore necessary to utilize a large excess of air in the combustion step, which acts
as a thermal diluents and reduces the temperature of the combustion products, this
temperature being dependent on the gas turbine firing temperature which in turn is set by the
materials used in the turbine parts exposed to the hot gas and the cooling medium (its
temperature and physical properties) as well as the heat transfer method employed for cooling
the hot parts. A fraction of the air from the compressor is bled off as cooling air when air is
utilized for cooling, the air being extracted from the compressor at appropriate pressures
depending upon where it is utilized in the turbine. From a cycle efficiency and engine specific
power output (kW per kg/s of suction air flow) standpoint, it is important to minimize the
amount of cooling air as well as the excess combustion air.
The necessity to use a large excess of pressurized air in the combustor as well as for turbine
cooling when air cooling is employed creates a large parasitic load on the cycle, since
compression of the air requires mechanical energy and this reduces the net power produced
from the system, as well as reducing the overall efficiency of the system.
Some of the technological advances being made or being investigated to improve the Brayton
cycle include the following, in addition to the changes in the basic cycle configuration such as
the inclusion of reheat combustion, intercooling (which is justified for very high pressure ratio
 Rotor inlet temperature of 1700ºC (3100ºF) or higher which would require the
cycles), recuperation and humidification :
development and use of advanced materials including advanced thermal barrier

coatings and turbine cooling techniques including closed loop steam cooling.
 Advanced combustor liner (combustion air and combustion products being hotter)
required due to increases in rotor inlet Temperatures.
 High blade metal temperature in the neighborhood of ~1040ºC (1900ºF) while limiting
coolant amount would again require the development and use of the advanced
materials including advanced thermal barrier coatings.
67
 Pressure gain combustor.
 Cavity or trapped vortex combustor.
 High pressure ratio compressor (greater than 30 to take full advantage of higher firing
temperature).
 Integration capability with high temperature ion transport membrane air separation in
IGCC applications.
Gas Turbine Firing Temperature
Current-state-of-the-art gas turbines have firing temperatures (rotor inlet temperatures) that
are limited to about 2600ºF. This increase in firing temperature has been made possible by
being able to operate the turbine components (that come into contact with the hot gasses) at
higher temperatures while at the same time utilizing closed circuit steam cooling. In a state-of-
the-art air-cooled gas turbine with firing temperature close to 1320ºC (2400ºF), as much as
25% of the compressor air may be used for turbine cooling, which results in a large parasitic
load of air compression. In air-cooled gas turbines, as the firing temperature is increased, the
demand for cooling air is further increased. Closed circuit steam cooling of the gas turbine
provides an efficient way of increasing the firing temperature without having to use a large
amount of cooling air. Furthermore, steam with its very large heat capacity is an excellent
coolant. Closed circuit cooling also minimizes momentum and dilution losses in the turbine
while the turbine operates as a partial reheater for the steam cycle.
Another major advantage with closed circuit cooling is that the combustor exit temperature and
thus the NOx emissions are reduced for a given firing temperature; the temperature drop
between the combustor exit gas and the turbine rotor inlet gas is reduced since the coolant
used in the first stage nozzles of the turbine does not mix with the gasses flowing over the
stationary vanes. Note that control of Nox emissions at such high firing temperatures becomes
a major challenge. The General Electric (GE) H series gas turbines as well as the Siemens
and Mitsubishi G series gas turbines incorporate steam cooling although the GE turbine
includes closed circuit steam cooling for the rotors of the high pressure stages.
Taking the firing temperature beyond 1430ºC (2600ºF) poses challenges for the materials in
the turbine hot gas path. Single crystal blading has been utilized successfully in advanced
turbines but in addition to this, development of advanced thermal barrier coatings would be
required. Extensive use of ceramics may be predicated. Reheat or sequential combustion is
an alternate approach to decreasing the amount of excess combustion air without increasing
the firing temperature.
Gas Turbine Pressure Ratio

The optimum pressure ratio for a given cycle configuration increases with the firing
temperature of the gas turbine. Thus to take full advantage of the higher firing temperature of
the gas turbine with firing temperature in the neighborhood of 1700ºC (3100ºF) the required
pressure ratio may be in excess of 30. Another constraint to consider is the temperature of the
last stage buckets in the turbine.
This temperature may have to be limited to about 650ºC (1200ºF) from a strength of materials
standpoint since the last stage buckets in large scale gas turbines tend to be very long and a
certain minimum pressure ratio would be required to limit this temperature.
Combustor Developments:
1- Pressure Gain Combustor
A pressure gain combustor produces an end-state stagnation pressure that is greater than the
initial state stagnation pressure. An example of such a system is the constant volume
68
combustion in an ideal spark ignited engine. Such systems produce a greater available energy
in the end state than constant pressure systems. It has been shown that the heat rate of a
simple cycle gas turbine with a pressure ratio of 10 and a turbine inlet temperature of ~1200ºC
(2200ºF) can be decreased by more than 10% utilizing such a constant volume combustion
system1. Pulse combustion which relies on the inherent unsteadiness of resonant chambers
can be utilized as a pressure gain combustor. Research continues at the U.S. DOE and at
NASA for the development of pressure gain combustors.
2- Trapped Vortex Combustor
The Trapped Vortex Combustor (TVC) has the potential for numerous operational advantages
over current gas turbine engine combustors. These include lower weight, lower pollutant
emissions, effective flame stabilization, high combustion efficiency, and operation in the lean
burn modes of combustion. The TVC concept grew out of fundamental studies of flame
stabilization and is a radical departure in combustor design using swirl cups to stabilize the
flame. Swirl-stabilized combustors have somewhat limited combustion stability and can blow
out under certain operating conditions. On the other hand, the TVC maintains a high degree of
flame stability because the vortex trapped in a cavity provides a stable recirculation zone that
is protected from the main flow in the combustor.
The second part of a TVC is a bluff body dome which distributes and mixes the hot products
from the cavity with the main air flow. Fuel and air are injected into the cavity in a way that it
reinforces the vortex that is naturally formed within it.
The TVC may be considered a staged combustor with two pilot zones and a single main zone,
the pilot zones being formed by cavities incorporated into the liners of the combustor 2. The
cavities operate at low power as rich pilot flame zones achieving low CO and unburned
hydrocarbon emissions, as well as providing good ignition and the lean blowout margins. At
higher power conditions (above 30% power) the additional required fuel is staged from the
cavities into the main stream while the cavities are operated at below stoichiometric
conditions. Experiments have demonstrated an operating range that is 40% wider than
conventional combustors with combustion efficiencies of 99%+. Use of the TVC combustor
holds special promise as an alternate option for suppressing the Nox emissions in syngas
applications where pre-mixed burners may not be employed.
3- Catalytic Combustor
Lean stable combustion can be obtained by catalytically reacting the fuel-air mixture with a
potential for simultaneous low NOx, CO and unburned hydrocarbons. It also has the potential
for improving lean combustion stability and reducing combustion induced pressure oscillations.
The catalytic combustor can play a special role in IGCC applications to reduce NOx emissions.
4- IGCC Applications
The H2O vapor content of the working fluid flowing through the turbine when firing syngas
while utilizing water vapor as the diluents, is significantly higher than that in the case when
natural gas is the fuel (i.e., compared to the case when natural gas is fired in dry low NOx
combustors). The following implications exist for the gas turbine in such applications:
1. Derating of the turbine firing temperature due the different aero-heat transfer characteristics
and
2. Life of the thermal barrier coatings, and any ceramics that may be utilized in advanced gas
turbines in the future.
Additionally, a gas turbine designed for a certain firing temperature on natural gas would see
derating of the firing temperature not only due to the increased concentration of H 2O vapor in
the working fluid but also due to the increase in the pressure ratio since the temperature of the
cooling air increases as the pressure ratio is increased. In the case of a steam-cooled gas
turbine, however, derating of the firing temperature may be less significant (since the cooling
69
steam temperature may be maintained independently of the gas turbine pressure ratio), unless
the low pressure air-cooled stages of the gas turbine become the bottleneck.
Furthermore, if dual fuel capability, i.e., operating capability on natural gas and on syngas is
required, a large surge margin would be necessary for the compressor with a pressure ratio in
excess of 30 and may require a twin-spool aero-compressor for high pressure ratios. Air
extraction from the engine to supply the air separation unit may alleviate some of these
challenges.
Integration capability with high temperature membrane air separation in IGCC applications
may be a requirement in the future when these advanced gas turbines are deployed.
Capabilities for extraction of ~ 50% of the compressor discharge air for the membrane unit
while introducing hot (~800ºC or 1500ºF) depleted air from it into the gas turbine combustor
would be required. Within the combustor, its liner design and materials would be impacted.
Inlet Air Fogging
Another approach to reducing the parasitic load of air compression in a gas turbine is to
introduce liquid water into the suction air4. The water droplets will have to be extremely small
in size and be in the form of a fog to avoid impingement on the blades of the compressor
causing erosion. As the water evaporates within the compressor from the heat of compression,
the air being compressed is cooled which in turn causes a reduction in the compressor work.
Note that the compression work is directly proportional to the absolute temperature of the fluid
being compressed.
A benefit in addition to increasing the specific power output of the engine is the reduction in
the NOx due to the presence of the additional water vapor in the combustion air. A number of
gas turbines have been equipped with such a fogging system. Care should be taken, however,
in specifying the water treatment equipment since high quality demineralized water is required
as well as in the design of the fogging system to avoid impingement of the compressor blades
with water droplets.
Figure (2-2) High pressure fogging skid in operation for a heavy-duty gas turbine.
Fuel Cell Hybrids

A fuel cell, as an electrochemical device is similar to a battery that converts chemically bound
energy directly into electricity but unlike conventional batteries, the chemical energy to the cell
is supplied on a continuous basis in the form of a fuel such as natural gas or synthesis gas
while the oxidant (air) is also supplied continuously. Higher conversion efficiencies are
achievable with a fuel cell when compared to heat engines; the chemical energy is directly
70
converted into electricity, the intermediate step of conversion into heat as in a heat engine is
eliminated and thus without being constrained by temperature limitations of the materials as is
the case with heat engines.
A fuel cell-based hybrid cycle consists of combining a fuel cell with a heat engine to maximize
the overall system efficiency.
Overall system efficiencies greater than 60% on natural gas on an LHV basis may be
achieved. High temperature fuel cells such as solid oxide and molten carbonate fuel cells are
most suitable for such applications. In the case of a high pressure fuel cell based hybrid (see
figure 4), the combustor of the gas turbine is replaced by the fuel cell system while in the case
of a low pressure fuel cell based hybrid, the heat rejected by the fuel cell may be transferred to
the working fluid of the gas turbine through a heat exchanger (indirect cycle) 5.
The characteristics for gas turbines needed in these hybrid applications are:
• Recuperation (currently only small gas turbines, i.e., less than 15 MW are offered as
recuperated engines for generator drives)
• Low firing temperature of less than 1000ºC (1800ºF) and pressure ratio in the range of 4 to
12
• Combustors accepting hot and depleted fuel and air when gas turbine combustors are
utilized for oxidation of the fuel cell anode exhaust gas
• Oil free bearings to avoid carbon deposition in the anode section of the fuel cell.
Fig.(2-3) A Pressurized SOFC Hybrid
Conclusions
Gas turbines could play a key role in the future power generation market including coal based
Future Gen plants. Potential exists to take the overall cycle efficiencies to 65% on natural gas
on an LHV basis, 60% being the state-of-the-art combined cycle efficiency with the
technological advances being made or being investigated which include higher rotor inlet
temperature of 1700ºC (3100ºF) or higher and higher blade metal temperature ~1040ºC
(1900ºF) made possible with the use of advanced materials including advanced thermal barrier
coatings and turbine cooling techniques including closed loop steam cooling, advanced
combustor liners to handle the higher temperatures within the combustor, pressure gain and
cavity combustors, high pressure ratio compressors (greater than 30 to take full advantage of
higher fi ring temperature) and integration capability with high temperature ion transport
71
membrane air separation in IGCC applications. In tandem, changes to the basic cycle
configuration such as the inclusion of reheat combustion and intercooling which is
advantageous in very high pressure ratio cycles would be complementary in achieving the
goals of higher thermal efficiency and higher engine specific power output. These desirable
attributes could also be further enhanced by the use of advanced combustor concepts such as
the pressure gain combustor while the TVC holds the promise of an alternate option for
suppressing the Nox emissions, especially in syngas applications.
REFERENE;
1- R.S. Gemmen, G. A. Richards and M. C. Janus, “Development of a Pressure Gain
Combustor for Improved Cycle Efficiency, Proceedings of the ASME Cogen Turbo Power
Congress and Exposition (1994).
2- D. L. Burrus, A. W. Johnson and W. M. Roquemore, and D. T. Shouse, “Performance
Assessment of a Prototype Trapped Vortex Combustor for Gas Turbine Application,”
Proceedings of the ASME IGTI Turbo-Expo Conference (New Orleans, June 2001).
3- A. D. Rao, “Process for Producing Power,” U.S. Patent No. 4,289,763 dated May 16, 1989.
4- R. Bhargava and C. B. Meher-Homji, “Parametric Analysis of Existing Gas Turbines with
Inlet Evaporative and Overspray Fogging,” Proceedings of the ASME IGTI Turbo-Expo
Conference, (Amsterdam, June 2002).
5- K. Litzinger, et. al., “Comparative Evaluation of SOFC Gas Turbine Hybrid System
Options,” Proceedings of the ASME Turbo Expo Conference (Reno-Nevada, June 2005); G.
Agnew, et. al., “The Design and Integration of the Rolls-Royce Fuel Cell Systems 1 MW
SOFC, “Proceedings of the ASME Turbo Expo Conference (Reno-Nevada, June 2005); R.
Schonewald, “Turbo- Machinery Requirements for Practical SOFC-Gas Turbine Hybrid
Systems,” Proceedings of the ASME Turbo Expo Conference
(Reno-Nevada, June 2005); H. Ghezel-Ayagh, “Hybrid Controls,” Presented at the ICEPAG
Conference (Irvine, California, September 2004).
72
Part (3) :Improvement of gas turbine performance based

on inlet air cooling systems: A technical review
Abstract—Gas turbine air inlet cooling is a useful method for increasing output for regions where
significant power demand and highest electricity prices occur during the warm months. Inlet air cooling
increases the power output by taking advantage of the gas turbine’s feature of higher mass flow rate
when the compressor inlet temperature decreases. Different methods are available for reducing gas
turbine inlet temperature. There are two basic systems currently available for inlet cooling. The first and
most cost-effective system is evaporative cooling. Evaporative coolers make use of the evaporation of
water to reduce the gas turbine’s inlet air temperature. The second system employs various ways to chill
the inlet air. In this method, the cooling medium flows through a heat exchanger located in the inlet duct
to remove heat from the inlet air. However, the evaporative cooling is limited by wet-bulb temperature
while the chilling can cool the inlet air to temperatures that are lower than the wet bulb temperature. In
the present work, a thermodynamic model of a gas turbine is built to calculate heat rate, power output
and thermal efficiency at different inlet air temperature conditions. Computational results are compared
with ISO conditions herein called "base-case".
Therefore, the two cooling methods are implemented and solved for different inlet conditions (inlet
temperature and relative humidity).
Evaporative cooler and absorption chiller systems results show that when the ambient temperature is
extremely high with low relative humidity (requiring a large temperature reduction) the chiller is the
more suitable cooling solution. The net increment in the power output as a function of the temperature
decrease for each cooling method is also obtained.
Keywords—evaporative cooling, gas turbine, turbine inlet cooling.
Gas turbines are used for power electric generation, operating airplanes and for several industrial
applications [1].The gas turbine engine consist of a compressor to raise combustion air pressure, a
combustion chamber where the fuel/air mixing is burned, and a turbine that through expansion extracts
energy from the combustion gases [2]. These cycles operates according to the open Brayton
thermodynamic cycle and present low thermal efficiency [3] and are referred as combustion turbines.
Usually, the rated capacities of combustion turbines are based on standard ambient air, and zero inlet
and exhaust pressure drops, as specified by the International Organization for Standardization (ISO) [2].
Therefore, the air inlet conditions are: air temperature 15 °C, relative humidity 60 %, absolute pressure
101.325 kPa at sea level.
Combustion turbines are constant-volume engines and their power output is directly proportional and
limited by the air mass flow rate entering the engine. Combustion turbines are constant-volume engines
and their power output is directly proportional and limited by the air mass flow rate entering the engine.
As the compressor has a fixed capacity for a given
rotational speed and a volumetric flow rate of air, their volumetric capacity remains constant and the
mass flow rate of air it enter into the gas turbine varies with ambient air temperature and relative
humidity [2].
The performance of a gas turbine power plant is commonly presented in function of power output and
specific fuel consumption [2], and it is sensible to the ambient conditions [4]. Thermodynamic analyses
from literature show that thermal efficiency and specific output decrease with the increase of humidity
and ambient temperature, but the temperature ambient is the variable that has the greatest effect on gas
turbine performance [1].
The temperature ambient rise results in decrease in air density, and consequently, in the reduction of the
mass flow rate. Thereby, less air passes through the turbine and the power output is reduced, at a given
turbine entry temperature. Moreover, the compression work increase due the augmentation of the
volume occupied by the air. According to [4], the net power output produced by gas turbine is directly
proportional to the air mass flow, it that decreases when ambient temperature increases. The work of
73
Ibrahim, [5] shown that an increment of 1 °C in the compressor air inlet temperature decreases the gas
turbine power output by 1 %.
Gas turbines have been used for power generation in several places in the world [6], [7], and each region
have different climatic conditions. Furthermore, the periods of the peak electricity demand occur during
the summer, when the ambient temperature is high. For example, in Arabian Gulf region the average
ambient temperature presents a variation by more than 30 °C from summer to winter and this factor
generate a large drop in power output during the summer [8]. Due to these severe ambient conditions,
the turbine inlet air cooling is one of many available technologies to improve the performance of the gas
turbine power plants by cooling the air at the compressor entry [1], [6]. Thus, the interest in the intake
air cooling techniques for gas turbines has augmented in the last years, due the increasing requirement
for power to a low specific investment cost [1].
Two different methods are frequently employed to obtain turbine inlet air cooling: the evaporative
cooling and inlet chilling systems [7], [8].
Fig. (3-1) Evaporative cooler theory.
Several works has been studied these cooling technologies as below detailed. [1] Presented a
comparison between two usual inlet air cooling methods, evaporative cooler and mechanical chiller, and
one new technique that uses turbo-expanders to improve performance of a gas turbine located at the
Khangiran refinery in Iran. Their results showed that turbo-expander method has the better cost benefit,
because it offers the greatest increase in net power and a lower payback period. [3] Performed a review
of inlet air cooling methods that can be used for enhancing the power production of the Saudi Electric
Company’s gas turbine during summer peak hours.
They concluded that the evaporative cooling system and the high-pressure fogging require a large
amount of water this factor limits its use in the desert climate, the absorption chiller is an expensive
system and its cost of investment isn’t justifiable if it used only to improve the power output in the
hour’s peak. Mechanical refrigeration requires large electric power demand during the peak times, and
thermal energy storage methods necessitate low electric power, but these systems need a very large
storage volume. The favored alternative choose for these authors is refrigeration cooling with chilled
water or ice thermal storage, the last option can produce lower inlet air temperature and requires a
smaller storage volume. [9] presented a thermodynamic assessment of some inlet air cooling system for
gas turbine power plants in two different regions of Oman, and the considered techniques are
evaporative cooling, fogging cooling, absorption cooling using both LiBr–H2O and aqua-ammonia, and
vapour-compression cooling systems. These different cooling techniques were compared with relation
their electrical energy production augmentation, as well as their impact on increasing the on peak
capacity of the considered gas turbine. Hosseini et al. [10] modeled and evaluated an evaporative
cooling system installed in gas turbines of the combined cycle power plant in Fars (Iran). Their results
74
showed that the power output of a gas turbine, at ambient temperature of 38 °C and relative humidity of
8 %, it presents an increment by 11 MW for temperature drop of the intake air of about 19 °C.
At this context, the present work focuses on evaporative cooling and tested at different ambient
temperature and humidity conditions, and the gas turbine power output and thermal efficiency are
compared.
Fig.(3-2) Effect of ambient intake temperature on the gas turbine thermal efficiency
Fig. (3-3) Effect of evaporative cooling effectiveness on the temperature drop
75
Fig.(3-4) Main components of evaporator cooler
Fig.(3-5) effective media of the Fig. (3-6) vane type mist eliminator
system
76
Fig. (3-7.a,b,c) Installation of evaporator cooler system
77
Case study
Data Comparison Before and After Evaporative Cooler Activation

Simple cycle gas turbine ( 4*125 MW) - Damietta Extension power plant – 500 MWs
DATE: 19 / 1 / 2013
Table (1) :
DATA U N I T #
Description Unit GT 1 GT 2 GT 3 GT 4
ON/
Evap. Status OFF ON OFF ON OFF ON OFF ON
OFF
Load MW 120 124.5 120.5 126 122.5 127.5 121 126
Ambient Temp. °C 16.7 16.2 16.3 15.8 17.4 18 16.9 16
Inlet Temp. °C 18.4 13.1 17.5 12.3 19.5 14 19.5 13.4
Relative Humidity % 37 40 40 39 53 38 55 43
Inlet Air Flow Rate kg\s 362.5 369 483 485 219 236.7 529.5 537
Compr. Discharge
°C 349 342.7 347.5 341 349 342.7 354 345.5
Temperature
Exh. Temperature °C 556 552 555 551.2 550.5 546.5 554.5 551
Compr. Discharge
bar 10.88 11.16 11 11.2 11.1 11.4 11.1 11.3
Press.
Speed rpm 2990 2999 2996 3001 2984 2994 3004 2999
Fuel Mass Flow Rate kg\s 6.56 6.76 5 5 6.76 6.9 .. ..
78
EVAP.COOLER EFFECT
PRESELECT LOAD (80 MW)
GT (1)
With Evap. 23/10/2012
Air Mass flow
Load Ambient Inlet rate
FUEL CPD CTD
Time R.H% CONS.
(MW) (c) (c) Kg/S. Kg/S bar (c)
16:15 80.89 25.05 21.94 52.2% 310.51 4.75 9.9 332.62
Without Evap. 22/10/2012
Air Mass flow
FUEL CPD CTD
Time R.H% CONS.
16:15 80 25.11 26.89 58.6% 306 4.77 9.78 339.56
GT (2)
With Evap. 23/10/2012
Air Mass flow FUEL
Load Ambient Inlet rate CONS. CPD CTD
Time R.H% Kg/S
(MW) (c) (c) Kg/S. bar (c)
16:15 81.26 25.3 22.31 48.9%% 460.38 4.76 9.75 334.43
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
(MW) (c) (c) Kg/S bar (c)
16:15 80.52 25.08 26.88 61.8% 451.4 4.8 9.62 341.96
GT (3)
With Evap. 23/10/2012
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
16:15 79.93 25.16 21.8 45.2% 203.36 4.76 9.89 331.92
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
16:15 79.71 24.9 26.32 60.5% 187.39 4.77 9.76 338.66
GT (4)
With Evap. 23/10/2012
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
16:15 80.56 25.26 22.4 47.4% 427.49 4.71 9.88 335.8
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
16:15 79.5 25.13 27.22 75% 405.31 4.72 9.71 342.83
TEST CONDITION; THE SAME AMBIENT TEMPERATURE AND LOCATION.
79
EVAP.COOLER EFFECT
Base Load Status
GT (1)
With Evap. 22/10/2012
Air Mass flow
FUEL CPD CTD
Time R.H% CONS.
18:00 120.32 23 21.59 69.6% 319. 6.57 10.82 347.59
Air Mass flow
FUEL CPD CTD
Time R.H% CONS.
18:19 118.26 23 24.68 80.55% 318.48 6.52 10.76 351.99
GT (2)
With Evap. 22/10/2012
Air Mass flow FUEL
Load Ambient Inlet rate CONS. CPD CTD
Time R.H% Kg/S
18:00 115.83 23.59 21.7 62.4% 457.55 6.41 10.53 347.28
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
18:19 113.97 23.4 24.89 66.1% 455.39 6.34 10.46 351.73
GT (3)
With Evap. 22/10/2012
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
18:00 118.89 23 21.28 61.1% 211.63 6.6 10.78 346.16
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
18:19 117.54 23.11 24.35 65.15% 215.13 6.51 10.7 350.6
GT (4)
With Evap. 22/10/2012
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
18:00 117.92 23.38 21.95 57.45% 422.6 6.5 10.76 348.99
FUEL
Air Mass flow
CONS. CPD CTD
Time R.H% Kg/S
18:19 117.67 23.54 23.54 67.2% 422.2 6.5 10.73 350.42
TEST CONDITION; THE SAME AMBIENT TEMPERATURE AND LOCATION.
80
Conclusion
In the present review, the development occurred in the inlet air cooling system that is used to improve the
performance of the gas turbine power plants had been classified. The following list summarizes the conclusion
drawn:
1. The diversity used of system to achieve the cooling function reflects the necessity of this technique in
improving the performance of the gas turbine power plants.
2. The success of evaporative cooling in reducing the high air temperature depends on relative humidity of the
ambient air. These types of systems are economical and suitable for hot and dry climates rather than hot and
humid ones.
3. In preselect load status, we suggest NOT TO use the evap. Cooler system because of power consumption in
evap. Cooler system (water treatment, R.O pump, evap. lifting pump) which may be greater than decreased in
fuel consumption.
4. In Base load status, fuel consumption increased but increased in power gained is more, so overall efficiency
will increased.
Criteria Preselect load (80 MW) Base load
Inlet air temp. Decreased Decreased
Air mass flow rate Increased (8.5%) Increased (0.4 % )
Fuel consumption Decreased (0.4%) Increased (1.1%)
C . P. D Increased Increased
C.T.D Decreased Decreased
MWs Constant Increased
Thermal Little Increased Increased
efficiency
REFERENCES
[1] Farzaneh-Gord, M.; Deymi-Dashtebayaz, M. Effect of various inlet air cooling methods on gas
turbine performance. Energy, 36, 1196–1205, 2011.
[2] ASHRAE. ASHRAE Handbook – HVAC Systems and equipment (SI). Atlanta, 2008.
[3] Al-Ibrahim A. M.; Varnham, A. A review of inlet air-cooling technologies for enhancing the
performance of combustion turbines in Saudi Arabia. Applied Thermal Engineering, 30, 1879–1888,
2010.
[4] Amell, A. A.; Cadavid, F. J. Influence of the Relative Humidity on the Air Cooling Thermal Load in
Gas Turbine Power Plant. Applied Thermal Engineering, 22, 1529–1533, 2002.
[5] Ibrahim, T. K.; Rahman M. M.; Abdalla A. N. Improvement of gas turbine performance based on
inlet air cooling systems: A technical review. International Journal of Physical Sciences, 6 (4), 620-627,
2011.
81
[6] Jaber, Q. M. Jaber, J. O.; Khawaldah, M. A. Assessment of power augmentation from gas turbine
power plants using different inlet air cooling systems. Jordan Journal of Mechanical and industrial
Engineering, 1(1), 7–15, 2007.
[7] Alhazmy, M. M.; Najjar, Y. S. H. Augmentation of gas turbine performance using air coolers.
Applied Thermal Engineering, 24,415– 429, 2004.
[8] Nasser, A. E. M.; El-Kalay, M. A. A heat-recovery cooling system to conserve energy in gas-turbine
power stations in the Arabian Gulf. Applied Energy, 38 (2), 133–142, 1991.
[9] Dawoud, B.; Zurigat Y. H.; Bortmany, J. Thermodynamic assessment of power requirements and
impact of different gas-turbine inlet air cooling techniques at two different locations in Oman. Applied
Thermal Engineering, 25, 1579–1598, 2005.
82

Gas Turbine Performance Based On Inlet A

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gas turbine performance based on inlet air cooling systems: A technical review

A- Gas Turbine Overview – Technical overview

* The Basic Cycle.

B- Main Gas Turbine Auxiliary Systems

* Oil Fuel System.

C- Gas Turbine Maintenance

Part(2) Advanced Brayton Cycles. 68 - 74

Improvement of gas turbine performance based

PART (1) : GAS TURBINE OVERVIEW

Fig. 1-2. Similarities in gas turbine and 4 stroke cycle.

Fig. 1-3. Combustion zone.

The Turbine Section

Fig. 1-4. G. T. Arrangement showing energy values.

(a) Better part load thermal efficiency.

The Accessory Section

Fig. 1-8. Gas and generator-simplified schematic.

Fig. 1-9. Unit configuration.

Turbine Base and Supports Base (Fig 1-10)

Fig. 1-10. Final Machining of Base.

Fig. 1-10. Final Machining of Base. Continued.

Fig. 1-11. Flexible support plate.

Fig. 1-12. Gib block and key before welding.

Compressor Rotor (Fig 1-13)

Fig. 1-13. Rotor positioned in casings.

Fig. 1-14. Turbine casings complete.

Variable Inlet Guide Vanes (Fig 1-15)

Fig. 1-15. Variable inlet guide vanes.

Fig. 1-16. Multiple combustion chambers.

The Turbulator System accomplishes this aerodynamically by stabilizing the lean

Fig. 1-17. Annual combustion chambers.

Fig. 1-19. Flame stabilizing and general airflow pattern.

Transition Pieces (Fig 1-20)

Fig. 1-20. Fitting transition pieces.

The Turbine Section

Fig. 1-21. First and second

Second-Stage Nozzle and Diaphragm

Turbine Rotor Assembly

Accessory Gear (Fig 1-24 & 1-25)

Fig. 1-24. Accessory gear box mounted on turbine base.

DESIGN DATA – TABLE

Location of Shaft Driven Accessory RPM Approximate Load

No. 1 Outboard Clutch 5100 --------

No. 1 Inboard Turbine Coupling 5100 --------

No. 2 Outboard Water Pump 3583 35 hp

No. 2 Inboard (Machined to Accept Brake) 3583 --------

No. 3a Outboard Fuel Pump 1814 108 hp

No. 3b Inboard Atomizing Air Compressor 6003 380 hp

No. 4 Outboard Hydraulic Supply Pump 1415 9hp

No. 4 Inboard Lube Oil Pump (Shaft Covered) 1415 31 hp

Fig. 1-25. Accessory gear box split on horizontal plane.

Gearwheel and Quill-Shaft (Fig 1-26)

Fig. 1-26. Quill shaft fitted to load gearwheel.

Flexible Couplings (Fig 1-27)

Fig. 1-27. Types of flexible coupling misalignment.

To protect against unanticipated transient torques such as generator electrical faults or

In addition to the spacer centering control to minimize coupling unbalance tight

Fig. 1-28. Journal bearings.

Fig. 1-29. Journal bearing oil wedges.