typical turbine system and description

8/18/2019 Typical Turbine System and Description

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Industrial Resources, Inc.www.indresinc.comPO Box 3686, Biloxi, MS 39540

Phone: 228-392-3973 Fax: 228-392-7257

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Typical Turbine System and Description

PREFACE

This Training System Description has been designed to assist you in meeting the

requirements of Turbine System of the Plant Operator Training Program. It contains

information about the Turbine System. This includes system function, flow path, and

details about the major system components and operation.

You should review each chapter objective. In doing so you will be better prepared to

learn the required information. You should also walk down the system and identify the

components and controls. Should you have additional questions about the system, ask

your supervisor.

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TYPICIALTURBINE SYSTEM TRAINING SYSTEM DESCRIPTON

TABLE OF CONTENTS

1.0 Introduction......................................................................................................................... 7

1.1 Function .............................................................................................................................. 7

1.2 Basic System Description ................................................................................................... 8

1.2.1 Turbine System Parameters ............................................................................................. 9

1.3 System Flow Path ............................................................................................................... 9

2.0 System Major Components............................................................................................... 12

2.1 Main Stop Valves.............................................................................................................. 13

2.1.1 Main Steam Stop Valve Data......................................................................................... 17

2.1.2 Main Stop Valve Control ............................................................................................... 172.2 Control Valves .................................................................................................................. 17

2.2.1 Control Valve Data ........................................................................................................ 21

2.2.2 Control Valve Controls.................................................................................................. 21

2.3 High Pressure (HP) Turbine Section................................................................................. 21

2.3.1 High Pressure (HP) Turbine Section Data ..................................................................... 23

2.3.2 High Pressure (HP) Turbine Section Controls............................................................... 23

2.4 Combined Reheat Valves (CRV’s)................................................................................... 23

2.4.1 Combined Reheat Valves (CRV’s) Data ....................................................................... 27

2.4.2 Combined Reheat Valves (CRV’s) Controls ................................................................. 27

2.5 Intermediate Pressure (IP) Turbine................................................................................... 27

2.5.1 Intermediate Pressure (IP) Turbine Data ....................................................................... 29

2.5.2 Intermediate Pressure (IP) Turbine Controls ................................................................. 29

2.6 Low Pressure (LP) Turbines ............................................................................................. 30

2.6.1 Low Pressure (LP) Turbines Data.................................................................................. 32

2.6.2 Low Pressure (LP) Turbine Controls............................................................................. 32

2.7 Turbine Front Standard ..................................................................................................... 33

2.7.1 Turbine Protective Devices............................................................................................ 33

2.7.2 Low Speed Switch ......................................................................................................... 34

2.7.3 Shaft Driven Main Oil Pump ......................................................................................... 34

2.7.4 Permanent Magnet Generator ........................................................................................ 34

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2.7.5 Turbine Supervisory Instrumentation ............................................................................ 34

2.7.5.1 Eccentricity Detector ..................................................................................................... 35

2.7.5.2 Differential Expansion Detector .................................................................................... 35

2.7.5.3 Shell Expansion Detector............................................................................................... 35

2.7.5.4 Speed Sensors ................................................................................................................ 35

2.8 Middle Standard................................................................................................................ 36

2.8.1 HP/IP to LP-“A” Coupling ............................................................................................ 36

2.8.2 Thrust Bearing Wear Detector ....................................................................................... 37

2.9 Turbine Bearings............................................................................................................... 38

2.9.1 Journal Bearings............................................................................................................. 38

2.9.2 Thrust Bearing ............................................................................................................... 41

2.9.3 Turbine Bearing Data..................................................................................................... 44

2.9.4 Turbine Bearing Controls .............................................................................................. 44

2.9.4.1 Temperature Controls - Monitoring............................................................................... 44

2.9.4.2 Vibration Controls – Monitoring ................................................................................... 46

2.10 Turning Gear..................................................................................................................... 48

2.10.1 Turning Gear Data ......................................................................................................... 50

2.10.2 Turning Gear Controls ................................................................................................... 50

2.11 Turbine Auxiliary Equipment ........................................................................................... 53

2.11.1 Auxiliary Valves ............................................................................................................ 542.11.1.1 Ventilator Valve (VV) ................................................................................................... 54

2.11.1.2 Equalizer Valve.............................................................................................................. 55

2.11.1.3 Packing Blowdown Valve (BDV) ................................................................................. 55

2.11.1.4 Heating Steam Blocking Valve (HSBV) ....................................................................... 56

2.11.2 Turbine Drains ............................................................................................................... 56

2.11.2.1 Main Stop Valve Above and Below Seat Drains........................................................... 56

2.11.2.2 Control Valve Steam Lead Drains ................................................................................. 58

2.11.2.3 Intercept Valve After Seat Drains.................................................................................. 59

2.12 Turbine Subsystems.......................................................................................................... 59

2.12.1 Extraction Steam System ............................................................................................... 60

2.12.2 Exhaust Hood Cooling System ...................................................................................... 60

2.12.3 Turbine Lube Oil System............................................................................................... 61

2.12.4 Electro Hydraulic Control System................................................................................. 61

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2.12.5 Rotor Prewarming System ............................................................................................. 62

2.12.6 Steam Seal System......................................................................................................... 63

3.0 System Operation.............................................................................................................. 73

3.1 System Startup .................................................................................................................. 73

3.2 Normal Operation ............................................................................................................. 76

3.3 Abnormal Operation ......................................................................................................... 77

3.3.1 High Vibration ............................................................................................................... 77

3.3.2 Operation With Feedwater Heaters Removed From Service......................................... 77

3.3.3 Turbine Trip ................................................................................................................... 79

3.3.4 Auxiliary Steam Seal System......................................................................................... 80

3.3 System Shutdown.............................................................................................................. 80

4.0 References......................................................................................................................... 82

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List of Figures:

Figure 1 – Main Stop Valve

Figure 2 – Stop Valve Bypass

Figure 3 – Main Stop Valve Lower Steam Leakoff

Figure 4 – Separate Mounted Control Valves (Typical)

Figure 5 – Control Valves

Figure 6 – Combine Reheat Valve (CRV)

Figure 7 – Left Side (No.1) CRV

Figure 8 – Right Side (No.2) CRV

Figure 9 – LP Turbines

Figure 10 – Low Pressure Turbine “A”

Figure 11 – Front Standard

Figure 12 – Middle Standard

Figure 13 – Solid (Rigid) Coupling

Figure 14 – Thrust Wear Detector

Figure 15 – Tilt Pad Bearing

Figure 16 – Typical Forces Applied to Individual Pads

Figure 17 – Elliptical Journal Bearing (Typical)

Figure 18 – Thrust Bearing

Figure 19 – Tapered Land Oil Wedge (Typical)

Figure 20 – Vibration Monitor Probe

Figure 21 – Turning Gear

Figure 22 – Turning Gear Local Controls

Figure 23 – Packing Gland Arrangement HP/IP Turbine

Figure 24 – Packing Gland Arrangement LP Turbines

Figure 25 – Steam Pressure Unloading Valve (SPUV)

Figure 26 – MOV-B, Steam Pressure Unloading Valve, Bypass Valve

Figure 27 – Steam Diverting Valve

Figure 28 – Auxiliary Steam Seal Regulator

Figure 29 – Gland Steam Condenser and Exhauster

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List of Drawings:

Drawing 1 – Unit 7 Basic Steam Flow

Drawing 2 – Shell and Nozzle Assembly

Drawing 3 – Turbine HP Section

Drawing 4 – Turbine IP Section

Drawing 5 – Turbine Steam Drains

Drawing 6 – Steam Seal System

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1.0 Introduction

Chapter Objectives:

Describe the functions of the Turbine System

1. State, from memory, the functions of the Turbine System

2. Draw a simplified Turbine System.

3. Describe the flow path and how the Turbine System performs its

function.

3. List the normal Turbine System operating parameters of pressure,

temperature and flow.

Your Turbine

1.1 FunctionThe function of the main turbine is to convert the thermal energy, contained in the steam,

into mechanical energy for turning the main turbine and generator.

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1.2 Basic System Description

Refer to Drawings 1 and 2 to follow the flow of steam through the main turbine.

Unit 7 is provided with one (1) General Electric tandem-compound eighteen-stage,

opposed flow reheat turbine with two (2) double-flow low pressure sections and consists

of the following major components:

1. Main stop valves (2)

2. Control valves (4)

3. High pressure turbine

4. Combined reheat intercept valves (2)

5. Intermediate pressure turbine

6. Low pressure turbines (2)

7. Turbine front standard

8. Turbine middle standard

The main turbine consists of an opposed flow high-pressure intermediate section, and two

(2) double-flow low-pressure sections. The high-pressure section includes the high-pressure

turbine stages, and the intermediate pressure reheat turbine stages. The high-pressure stages

are referred to as the high pressure, or HP turbine. The intermediate pressure reheat turbine

stages are referred to as the intermediate pressure, or IP turbine. The double-flow, low-

pressure sections are referred to as low pressure, or LP turbines.

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1.2.1 Turbine System Parameters

Manufacturer General Electric

Type Tandem-compound opposed flow HP, reheat

turbine with two (2) double flow low-pressure

sections

Number of stages 18

Throttle pressure 2400 psig

Design back pressure 1-inch Hg

Speed 3600-rpm

Superheat/reheat steam temperature 1000/1000 degrees Fahrenheit

Steam flow 3,800,000 lb per hour

Design capacity 512,094 kW

1.3 System Flow Path

(Refer to Drawing 1)

High-pressure steam from the secondary superheater outlet is routed through the main steam

line to the main stop valves. The main steam line splits into two (2) individual lines

upstream of the stop valves, passing the steam to the two (2) main stop valves. The steam

passes through the stop valves to the external control valve chest, where four (4) control

valves are located. The steam passes through the control valves, and to the main turbine

through four (4) lines called steam leads. Two (2) of these steam leads enter the bottom of

the high-pressure turbine, and two (2) enter at the top. Each of the four (4) steam leads pass

steam to an individual 90 degree nozzle box assembly mounted in quarter segments around

the periphery of the first stage of the high pressure turbine.

High-pressure steam enters the turbine near the center of the HP section, flowing through

the individual nozzle boxes and the six-stage HP turbine toward the front-end standard. The

steam then leaves the HP turbine, and returns to the reheat section of the boiler. The

reheated steam returns to the turbine through single hot reheat line, which splits into two (2)

individual lines upstream of the combined reheat intercept valves. Steam flows through the

combined reheat intercept valves, and into the five-stage IP turbine.

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The inlet end of the IP turbine is located near the center of the high-pressure section, next to

the HP turbine inlet. Steam flow in the IP turbine is in the direction of the generator; this is

opposite to the direction of flow in the HP turbine.

Steam is exhausted from the IP turbine into a single crossover pipe, which routes steam

from the IP turbine exhaust to the inlet of the two (2) double-flow LP turbines. Steam then

enters the center of each seven-stage LP turbine.

The LP turbines consist of two (2) identical sets of LP turbine stages. In each LP turbine;

one-half of the steam flows through one (1) set of LP turbine stages in the direction of the

turbine front standard, the other half of the steam flows through the other set of LP turbine

stages in the direction of the generator. The steam then exits the LP turbines and is

exhausted into the condenser.

The main turbine shaft is connected to and rotates the main generator. Controlling the steam

flow to the main turbine controls the generator speed and/or load. The generator and the

exciter are fully discussed in Training System Description, Generator and Generator

Excitation System.

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LP-ATE

LP-AGE

LP-B TE

LP-BGE

CONDENSER

HOTWELL

RightSide

LeftSideCRV

Control Valves

HP

LP Crossover Pipe

IP

1

2

4

3

1

2

Main Steam

Top Steam Lead

Bottom Steam Lead

Top Steam Lead

Bottom Steam Lead

Stop Valve

Stop Valve

Control Valve Chest

Hot Rehe t aSteam 1

Cold Reheat

2

Hot Rehe t aSteam

CRV

Drawing 1 - Basic Steam Flow

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This Page Intentionally left Blank

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2.0 System Major Components

Chapter Objectives:

Describe how the Turbine System Components perform their functions and

how they interface with other System components.

1. Draw from memory a diagram of the Turbine System showing major

components

2. State from memory, the names and functions of major Turbine System

components.

3. Describe the construction of and flow paths through the major components.

The main turbine consists of the following major components:

1. Main Stop Valves (2)

2. Control Valves (4)

3. High Pressure (HP) Turbine

4. Combined Reheat Valves (CRV’s) (2)

5. Intermediate Pressure (IP) Turbine

6. Low Pressure (LP) Turbines (2)

7. Turbine Front Standard

8. Turbine Middle Standard.

Components are described below as necessary to illustrate how they contribute to the

performance of the main turbine function.

2.1 Main Stop Valves

The primary function of the main stop valves is to quickly shut off main steam flow to

the turbine under emergency conditions. The stop valves (Figure 1) also provide a

second line of defense against turbine overspeed in the event the control valves fail. The

main stop valve bypass valves are also used for full arc operation during startup and

shutdown of the turbine. Full arc to partial arc transfer is discussed in the accompanying

Unit Operating Procedure, , and in Training System Description, Electro Hydraulic

Control (EHC) System.

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High-pressure steam is admitted to the main turbine through two (2) parallel main stop

valves. The main stop valves are located in the main steam piping between the boiler and

the turbine control valve chest. The outlet of each stop valve is welded directly to the valve

chest.

Figure 1 – Main Stop Valve

Steam

Strainer

Closing

Spring

Valve

Stem

Valve

Disc Pressure

Seal Head

Valve

Seat

Steam

Outlet

Steam

Inlet

Actuator

The main stop valves are totally unbalanced and cannot open unless the pressure drop across

the disk is reduced to approximately 15 percent of initial pressure. The stop valves can open

when the pressure drop has been reduced by operation of the internal bypass valve (Figure

2) located in each stop valve.

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MAIN STOP

VALVE DISC

MAIN STOP

VALVE D

SEATI

SURFACE

ISC

NG

ISC

TEM

MAIN STOP

VALVE S

BYPASS

VALVE

PORTS

(8 EA)

MAIN STOP

VALVE,

BYPASSVALVE D

Figure 2 – Stop Valve Bypass

The bypass valve disk is fastened to the end of the stem by special coarse threads strong

enough to withstand full closing force, yet designed to permit freedom of disk movement

relative to the stem so that the valve will seat.

The bypass valve is held in the valve disk by a bolted cap. Holes are located in the cap for

steam entrance, and holes in the valve disk pass the steam when the bypass valve is utilized.

When the stop valve is opened the bypass valve opens first as the valve stem moves in the

open direction. When the bypass valve is fully open it contacts a bushing on the stop valve

and pulls it open. When the stop valve is fully open, a bushing seats on the inner end of the

valve stem bushing and prevents steam leakage along the valve stem.

Each stop valve has two (2) steam leakoff points where the stop valve stem passes through

the stop valve casing. The first leakoff point located closest to the stop valve is referred to

as the high-pressure leakoff and is routed to the steam seal header. During startup or low

loads steam is supplied to this leakoff to assure a seal. After the turbine is loaded, steam is

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fed through this line from the stop valve stem into the steam seal header. The second

leakoff point is referred to as the low-pressure leakoff (Figure 3) and is routed to the gland

steam condenser. The gland steam condenser and steam seal system are fully discussed in

section 2.12.6.

Figure 3 – Main Stop Valve Lower Steam Leakoff

Full arc to partial arc transfer is fully explained in Training System Description Electro

Hydraulic Control (EHC) System.

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2.1.1 Main Steam Stop Valve Data


Quantity Two (2)

Actuate (Open) Hydraulic Cylinder (Servomotor)

Actuate (Close) Closing Spring

Operating Pressure (Steam) 2400-psi

Operating Temperature 1000 degrees Fahrenheit

2.1.2 Main Stop Valve Control

The main steam stop valves are operated and controlled by the turbines Electro Hydraulic

Control System in concert with the Units DCS Control System.

2.2 Control Valves

Refer to Drawing 2 when reading this section.

The control valves (Figure 4) regulate the steam flow to the turbine to control the main

turbine speed and/or load. The four (4) control valves are mounted in line on a common

external valve chest. Steam is supplied to the external valve chest through the main stop

valves. The valve chest is separated from the turbine, and individual steam leads from the

valve chest are provided from each control valve to the inlet of the HP turbine. Each control

valve is operated by a hydraulic power actuator which positions the control valves in

response to signals from the Electro Hydraulic Control System.

During startup, the control valves are wide open (full arc), and the stop valves’ internal

bypass valves control the steam flow to the turbine. Under these conditions, steam is

admitted through all four (4) steam leads around the entire periphery of the HP turbine inlet.

The purpose of this full arc admission is to reduce thermal stresses caused by unequal steam

flow through the nozzle sections. During full arc admission, throttling of the steam occurs at

the stop valve bypass valves only, and there is uniform steam flow into the HP turbine. This

also results in lower steam velocities at the turbine inlet. Because of the lower steam

velocities the temperatures cannot change as rapidly. Full arc admission is used until the

high transfer point is reached, at which time transfer to partial arc will occur.

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Figure 4 – Separate Mounted Control Valve (Typical)

NOTE: The high transfer point is determined by a set of micro-switches activated by the

stop and control valve stem positions. Therefore, the load point at which transfer occurs

varies according to the steam temperature and pressure.

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Rotor

180 Degree Nozzle Box

180 Degree Nozzle Box

HP

Inner

Shell

HP

Inner

Shell

HP

Inner

Shell

HP

Inner

Shell

HP

Inner

Shell

HPInner

ShellUpper

Lower

Snout

Pipe

Seal

Rings

Snout Pipes

Steam From

No. 1

Control Valve

Steam From

No. 3

Control Valve

Snout Pipes

Steam From

No. 4

Control Valve

Steam From

No. 2

Control Valve

Drawing 2 - Shell and Nozzle Assembly

Snout

Pipe

Seal

Rings

Drawing 2 – Shell and Nozzle Assembly

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During normal operation, the main stop valves are wide open and the control valves control

steam flow to the turbine. The control valves (Figure 5) operate sequentially to control

steam flow to the turbine and the Unit load. All four (4) control valves are never open the

same amount for any given load up to full load with wide-open control valves. This is

referred to as partial arc admission. Transfer to partial arc admission is normally

automatically performed by the low transfer and high transfer micro- switches but may also

be initiated by the operator when the OK TO TRANSFER light comes on. The control

valves are throttled until they have control of steam flow and the stop valves then

automatically run full open. A detailed explanation of full arc to partial arc transfer is

discussed in Training System Description EHC Control System.

Figure 5 – Control Valves

Number l and 2 control valves are balanced type, with internal pilot valves. Number 3 and 4control valves are unbalanced single disk type.

The balanced type valves are equipped with an internal pilot valve connected to the valve

stem. When opening, the pilot valve is opened first to equalize the pressure across the main

valve disk. Further opening of the stem opens the main disk.

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The disk of the unbalanced type valve is directly connected to the stem.

Each control valve is provided with two (2) steam leakoff points where the control valve

stem passes through the external steam chest wall. The first leakoff point located closest to

the external steam chest is referred to as the high-pressure leakoff and is routed to the hot

reheat steam line. The second leakoff point is referred to as the low-pressure leakoff and is

routed to the steam seal header.

2.2.1 Control Valve Data


Quantity Four (4)





2.2.2 Control Valve Controls

The control valves are operated and controlled by the turbines Electro Hydraulic Control

(EHC) System in concert with the Units DCS Control System.

2.3 High Pressure (HP) Turbine Section

Refer to Drawing 3 when reading this section.

The high-pressure turbine is a six-stage, single-flow turbine. Steam enters the HP turbine

through separately mounted stop valves and control valves. A steam lead from each of the

control valves routes the steam to the center of the high-pressure casing. Two (2) steam

leads are connected to the upper half of the casing and two (2) to the lower half. Steam is

admitted to both casing halves allowing for uniform heating of the casing and thus

minimizing distortion.

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Flow

IPHP Section

6th 5th 4th3rd 2nd

1st

2nd3rd4th5th

6th

Diaphrag(Stationary

Nozzle(1st

Buckets/Blad

(Rotating

Drawing 3 - Turbine HP Section

Each control valve regulates the steam flow to one (1) of four (4) nozzle box-opening

sections (nozzles/partitions). The nozzle boxes are located within the HP casing; thus

containing the steam before it passes through the first stage nozzle openings.

The steel alloy high pressure outer shell is supported on the front standard at the turbine end,

and the middle standard at the generator end.

The high-pressure inner shell is supported in the outer shell on four (4) shims and is located

axially by a rabbit fit. The inner shell is keyed on the upper and lower vertical centerlines to

locate it transversely. This arrangement maintains accurate alignment of the inner shell

under all operating conditions. The nozzle box steam inlets are equipped with slip ring

expansion joints that permit the nozzle boxes to move with respect to the shells and still

maintain a steam-tight fit.

Rotating blades (buckets) are placed in grooves machined into the rotor. Each blade is

pinned to ensure its position is fixed.

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The fixed blades are mounted in interstage diaphragms located between each stage of

moving blades. The interstage diaphragms serve as nozzles to increase the velocity of the

steam and to direct the steam flow onto the next stage of moving blades. Each interstage

diaphragm is constructed of two (2) halves that are mounted in grooves in the upper and

lower casings. When assembled in the turbine, the diaphragms are sandwiched in between

the rotating wheels.

Steam leaving the nozzle boxes is directed through the six (6) stages of HP turbine blading,

with the steam flowing toward the turbine front standard. The expanded steam exhausts

through two (2) nozzles at the bottom of the casing and is routed to the reheat section of the

boiler through the cold reheat line.

A small portion of the high-pressure turbine exhaust is extracted from the cold reheat line

for 7-7A and 7-7B feedwater heaters.

2.3.1 High Pressure (HP) Turbine Section Data


Type Impulse

Speed 3600 rpm

Number of Stages Six (6)

Inlet Pressure 2400-psi

Inlet Temperature 1000 degrees Fahrenheit

2.3.2 High Pressure (HP) Turbine Section Controls

The HP turbine is operated and controlled by the turbines Electro Hydraulic Control


2.4 Combined Reheat Valves (CRV’s)

Two (2) combined reheat stop and intercept valves are provided, one (1) in each hot reheat

line supplying reheat steam to the intermediate pressure turbine (Figure 6, Figure 7 and

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Figure 8). As the name implies, the combined reheat intercept valve is actually two (2)

valves, the intercept valve (IV) and the reheat stop valve (RSV), incorporated in one (1)

valve casing. Although they utilize a common casing, these valves have separate operating

mechanisms and controls. The function of the intercept valves and reheat stop valves is to

protect the turbine against overspeed from stored steam in the reheater.

The intercept valve disk is located above the reheat stop valve disk, with its stem extending

through the upper head. The reheat stop valve stem extends downward through the below-

seat portion of the casing. Both valves share a common seat; however, the intercept valve is

designed to travel through its full stroke regardless of the reheat stop valve position, while

the intercept valve must be in the “closed” position for the reheat stop valve to open.

During normal operation of the turbine-generator unit, the intercept valves are fully open.

The purpose of the intercept valve is to shut off steam flow from the reheater, which,

because of its large storage capacity, could possibly drive the Unit to overspeed upon loss of

generator load. The intercept valve is capable of reopening against maximum reheat

pressure and of controlling turbine speed during reheater blowdown following a load

rejection.

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Intercept

Actuator

Reheat Stop

Actuator

Balance

Chamber

Out

In

ClosingSprings

Reheat Stop

Disc

InterceptDisc

Steam

Strainer

Closing

Springs

Figure 6 – Combined Reheat Valve (CRV)

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Figure 7 – Left Side (No.1) CRV

The reheat stop valves' primary function is to provide a second line of defense (backup

protection) against the energy storage of the reheater in the event of failure of the intercept

valves or the normal control devices. However, note that the reheat stop valves also close

upon a routine shutdown, or by operation of certain boiler and electrical trips whenever the

main stop valves are closed. The reheat stop valve power actuators are sized so that the

reheat stop valves are capable of reopening against a steam pressure differential of

approximately 15 percent of maximum reheat pressure.

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Figure 8 – Right Side (No.2) CRV

2.4.1 Combined Reheat Valves (CRV’s) Data


Quantity Two (2)





2.4.2 Combined Reheat Valves (CRV’s) Controls

The operation of the combined reheat valves is controlled by the turbines Electro

Hydraulic Control (EHC) System in concert with the Units DCS Control System.

2.5 Intermediate Pressure (IP) Turbine

The IP turbine (Drawing 4) is a five-stage, single-flow unit. The IP turbine is located on the

generator end of the HP turbine. Steam is routed to the IP turbine through two (2) parallel

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combined reheat intercept valves. During normal operation, the reheat stop and intercept

valves are fully open. Steam flow to the IP turbine is equal to the steam flow to the HP

turbine less the extraction flow to 7-7A and 7-7B feedwater heaters.

10th 9th

Dia hra ms (Stationary Stages)

11th

8th

7th

7th

IP Section

Nozzle

Block

HP

11th 10th 9th8th

HotReheatSteam

Buckets/Blades (Rotating Stages)

Drawing 4 - Turbine IP Section

The outlets of the combined reheat intercept valves are welded directly to the bottom half of

the HP turbine casing, near the center.

Steam enters the IP turbine and passes through a nozzle block, which directs the steam onto

the first stage of IP turbine blades. Throughout the turbine, the turbine stages are numbered

sequentially beginning with the first stage of the HP turbine. Therefore, the first stage of the

IP turbine is the seventh turbine stage.

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The IP turbine moving blades are attached to the common HP and IP turbine rotor. The

blades are placed in grooves machined into the rotor and held in position by pinning.

Interstage diaphragms are located between each stage of moving blades.

The steam expands as it passes through each of the IP turbine stages and exhausts through a

single crossover pipe in the upper casing. The crossover pipe directs the steam to the LP

turbines. The steam flow through the IP turbine is toward the generator end, which is

opposite to the flow in the HP turbine. By arranging the flows in the HP and IP turbines in

opposite directions, the axial thrust caused by the pressure drop through the turbine stages is

reduced.

A portion of the steam flowing through the IP turbine is extracted at the 9th and 11th stages

of the turbine and supplied to feedwater heaters 7-6A, 7-6B and deaerating heater No. 5

respectively. The 11th stage extraction steam is also the normal low-pressure steam supply

to the boiler feed pump turbines and a source of fire protection to the mills.

2.5.1 Intermediate Pressure (IP) Turbine Data


Type Impulse

Speed 3600 rpm

Number of Stages Five (5)

Inlet Pressure 650-psi (Approximate)

Inlet Temperature 1000 degrees Fahrenheit

2.5.2 Intermediate Pressure (IP) Turbine Controls

The operation of the IP turbine is controlled by the turbines Electro Hydraulic Control


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2.6 Low Pressure (LP) Turbines

The function of the LP turbines (Figure 9) is to convert part of the remaining energy

contained in the steam exhausted from the IP turbine to mechanical energy for rotating the

main generator.

Crossover Pipe

LP “B”LP “A”

Figure 9 – LP Turbines

There are two (2) LP turbines arranged in tandem with the HP and IP turbine. Refer to

Figure 10, as the LP turbines are described in the following paragraphs.

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Steam Flow

Steam

Low Pressure

ExhaustInner Case

Bearing

No.3 Bearin

No.4

Atmospheric Relief

DiaphragmAtmospheric Relief

Diaphragm

Figure 10 – Low Pressure Turbine “A”

The LP turbines are seven-stage, pressure compounded, double-flow units. IP turbine

exhaust steam flows through the crossover pipe to the LP turbines. This steam enters each

LP turbine at the center of the casing. As on the HP and IP turbine, this arrangement

provides for even heating of the turbine casing and prevents distortion. Inside the turbine,

the steam flow is split, flowing across seven (7) stages of blading to each end. The exhaust

steam leaving the LP turbines is then drawn through the exhaust hood to the main

condenser.

Extraction steam is taken from the following stages:

1. 13th stage, which supplies heating steam to feedwater heater 7-4



4. 17th stage, which supplies heating steam to feedwater heater 7-1A and 7-1B.

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The LP turbine casing consists of two (2) halves, upper and lower. The casing halves are

machined and bolted together to ensure a steam-tight fit. The upper half is provided with

two (2) rupture discs, which relieve to the turbine room atmosphere if the turbine exhaust

pressure exceeds five (5) psi. The lower casing half consists of an inner and outer casing.

The inner casing is the exhaust hood. Exhaust steam enters the main condenser through this

hood. Exhaust hood spray is required to limit exhaust hood temperatures during startup and

low loads, since the steam flow through the turbine is not adequate to remove heat generated

by the rotating turbine blades. The Condensate System supplies water to the exhaust hood

sprays.

The LP turbine rotor is a single solid forging. The rotating blades are placed in grooves

machined in the rotor. Each blade is pinned to ensure its position is fixed. The fixed blades

are placed in grooves machined into the turbine casing. They are also pinned to ensure their

positions are fixed.

2.6.1 Low Pressure (LP) Turbines Data


Type Impulse

Speed 3600 rpm

Number of Stages Seven (7) TE and Seven (7) GE (Both the “A” and “B”

Rotors)

Exhaust Pressure 1.0-inch Hg

2.6.2 Low Pressure (LP) Turbine Controls

The operation of the LP turbines is controlled by the turbines Electro Hydraulic Control


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2.7 Turbine Front Standard

The turbine front standard, shown in Figure 11, houses the following components:

1. Main Turbine Bearing No.1 (Discussed in Section 2.9 of this System Description)

2. Turbine protective devices (emergency trip valves)

3. Turbine low speed switch

4. Turbine shaft driven oil pump

5. Permanent magnet generator

6. Turbine supervisory instrumentation.

Figure 11 – Front Standard

2.7.1 Turbine Protective Devices

Turbine protective devices include:

1. Manual mechanical trip valve

2. Master trip solenoid valve

3. Oil trip and reset solenoid valve

4. Extraction air relay dump valve

5. Auxiliary speed sensor unit.

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These devices are fully discussed in Training System Description CF7-PG02-SD, EHC

Control System.

2.7.2 Low Speed Switch

The low speed switch is a hydraulic device which trips at least one (1) of two (2) electrical

switches as the hydraulic pressure decreases below a preset value. These switches sound an

alarm and automatically engage the turning gear. The low speed switch consists of a

toothed wheel, an oil supply, and receiving nozzles. The teeth of the wheel intermittently

interrupt the flow of oil from the supply to the receiver jets. If the shaft speed decreases to

less than two (2) rpm, the toothed wheel will not interrupt oil flow and the pressure switches

are activated. The 25 psi turbine lubrication oil header supplies oil for use in the low speed

switch.

2.7.3 Shaft Driven Main Oil Pump

The turbine shaft driven oil pump is a double-suction, centrifugal type, and is described in

Training System Description Lube Oil System. It is mounted directly to the turbine shaft,

and therefore operates at turbine speed.

2.7.4 Permanent Magnet Generator

The function of the permanent magnet generator is to supply redundant control power to the

Electro Hydraulic Control System. It is driven directly from the turbine shaft. The output of

the permanent magnet generator is 420 hertz, 118 volts AC.

2.7.5 Turbine Supervisory Instrumentation

Turbine supervisory instrumentation, located in the front-end standard, includes the

following:

1. Eccentricity detector

2. Differential expansion detector

3. Shell expansion detector

4. Speed sensors.

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2.7.5.1 Eccentricity Detector

The eccentricity detector, located on the stub shaft in the front end standard, detects the

amount of wobble (bow) of the shaft while on turning gear and transmits this information to

a recorder in the control room.

2.7.5.2 Differential Expansion Detector

The differential expansion detector consists of a collar machined onto the turbine stub shaft,

sitting between two (2) magnetic sensors attached to the front standard. The combination of

these gives information of the difference in expansion between the turbine shaft and turbine

casing.

2.7.5.3 Shell Expansion Detector

The shell expansion detector is attached to the front standard base plate with a shaft

extended against the front end standard. Because the front standard is attached to the turbine

casing, any movement of the casing causes the front standard to move. This movement is

indicated on a recorder in the control room via the shell expansion detector.

2.7.5.4 Speed Sensors

Three (3) speed sensors provide the speed signals for the EHC speed control and auxiliary

speed sensor units. The speed sensors are positioned around an 80-toothed wheel, which is

attached to the stub shaft. The number of teeth is selected to give a 4800 Hz signal at rated

speed. The speed sensor has no moving parts and does not make contact with the toothed

wheel. The sensor consists of a magnet and a coil of wire. Each time a tooth passes a

sensor, a pulse is generated. The faster the speed of the toothed wheel, the faster the pulses.

A circuit board in the TSI cabinet changes the varying frequency (pulses) to a varying

voltage; thus, with more rpm more voltage is transmitted to the meter in the control room

indicating higher turbine speed.

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2.8 Middle Standard

The turbine middle standard, illustrated in Figure 12, houses the following components:

1. Main turbine journal bearings 2 and 3 (Discussed in Section 2.9 of this System

Description)

2. High pressure and "A" low pressure shaft coupling

3. Thrust bearing (Discussed in Section 2.9 of this System Description)

4. Thrust bearing wear detector.

Figure 12 – Middle Standard

2.8.1 HP/IP to LP-“A” Coupling

The high pressure and "A" low-pressure rotors are connected with solid-bolted couplings

shown in Figure 13.

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Coupling

Bolt Holes

Male

Register

Fit

Female

Register

Fit

Coupling Bolt Holes

Figure 13 - Solid (Rigid) Coupling

2.8.2 Thrust Bearing Wear Detector

The thrust bearing wear detector (Figure 14) is a hydraulic device, which continuously

detects axial position of the turbine shaft compared to the thrust bearing casing. The device

is mounted close to the thrust bearing in the middle standard.

Oil pressure is bled from an opening at the tip of the thrust bearing wear detector probe

against a beveled section on the thrust bearing collar. As the shaft moves axially, the

distance between the probe and the collar changes, allowing either more or less oil pressure

to be bled off. This change in oil pressure is then transposed into a wear reading, and

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activates two (2) pressure switches. Activation of a single pressure switch sounds an alarm;

activation of both switches trips the Unit. The thrust bearing wear detector trip points are

tested weekly as described in Training System Description EHC Control System.

Figure 14 – Thrust Wear Detector

2.9 Turbine Bearings

The main turbine is equipped with 10 radial bearings and one (1) double thrust bearing.

2.9.1 Journal Bearings

The No.1 and No.2 bearings are of the tilt pad design, which is illustrated in Figures 15

and 16.

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Figure 15 – Tilting Pad Bearing

Figure 16 – Typical Forces Applied to Individual Pads

The journal bearings are numbered one (1) through 10 beginning with No. 1 located in the

front standard, and proceeding through No. 6 located at the generator end of No. 2 LP

turbine. Journal bearings No. 7 and 8 are generator bearings, and 9 and 10 are exciter

bearings.

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Journal bearings No. 1 and 2 are tilting pad, self-aligning bearings consisting of six (6)

Babbitt-lined steel pads as shown in Figure 15. The pads are supported on a straight seal in

the bearings shells, three (3) in each half, so as to be free to pivot in the direction of shaft

movement and adapt them to the greatest oil film wedge during operation.

Oil is fed into the bearing at the center joint on the upcoming side of the journal. The oil

groove at the opposite joint contains a drilled hole, which restricts the flow sufficiently to

build up a slight pressure on the discharge side of the bearing. Oil passing through this

discharge hole is carried to the oil sight box; most of the oil, however, discharges through

the ends of the bearings.

Journal bearings No. 3 through No. 10 are elliptical bore-type bearings, which are illustrated

in Figure 17.

The ellipse of the bearing bore is obtained by machining the bore to the larger horizontal

diameter, with shims inserted in the joints of the bearings; the shims are then removed for

final assembly. The bore has an overshot oil groove extending over the top half of the

lining.

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Rotation

Figure 17 – Elliptical Journal Bearing (Typical)

To facilitate the entrance and discharge of the oil, the bearing has the Babbitt cut away at the

horizontal joint. This forms oil grooves with well rounded edges, which extends to within a

short distance of the ends of the bearing. Oil is fed into the bearing at the center joint on the

upcoming side of the journal. The oil groove at the opposite joint contains a drilled hole,

which restricts the flow sufficiently to build up a slight pressure on the discharge side of the

bearing. Oil passing through this discharge hole is carried to the oil sight box; most of the

oil, however, discharges through the ends of the bearing. The TURBINE BRG TEMP

HIGH alarm is energized whenever the exiting oil temperature exceeds 155 degrees

Fahrenheit.

2.9.2 Thrust Bearing

The thrust bearing, illustrated in Figure 18, is located on the main shaft of the turbine.

Independently mounted inside the middle standard, the thrust bearing absorbs the axial

thrust of the turbine and generator rotors, which are connected by a solid coupling.

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Thrust Runner Thrust Runner

Thrust Case

Thrust Case

Spacer Plates

Turbine Shaft

Copper Backed

Tapered Land

Thrust Plates

Figure 18 - Thrust Bearing

This tapered-land thrust bearing consists of two (2) stationary thrust plates, and two (2)

rotating thrust collars on the turbine shaft, which provide the front and back faces to the

bearing. These plates are supported in a casing so that they may be positioned against the

rotating faces of the collars. The thrust collar faces are machined and lapped, producing

smooth, parallel surfaces.

The surfaces of the two (2) thrust plates are Babbitted, and have tapered lands of fixed

converging surfaces, permitting a wedge of oil (see Figure 19) to exist between the rotating

thrust collars and the thrust plates. The thrust plates are constructed as split copper rings,

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with the Babbitted surfaces divided into lands by radial, oil feed grooves. The surface of

each land is tapered, so that it slopes toward the rotating collar, both in the direction of

rotation and from the inner to the outer radius at the leading edge of the land. The radial

grooves are dammed at the outer ends, maintaining an oil pressure in the groove.

Thrust Runner

Direction of Rotation

Oil Wedge

Copper Backed

Thrust Plate Babbitted Tapered Lands

Oil Wedges Formed by

Tapered Lands

Figure 19 – Tapered Land Oil Wedge (Typical)

Bearing oil, at 25-psi, is fed into the thrust bearing by separate feed pipes to each thrust

plate. The proper amount of oil is metered to the bearing by an orifice in each pipe. The

individual oil supplies enter the lower half of the casing radially, and are carried into the

radial oil grooves of each thrust plate.

Most of the oil from the thrust bearing discharges through the casing and into the bottom of

the standard, where it is returned to the oil tank through the drain pipe. A portion of the

discharge oil is piped through a sight box on the standard. This permits a visual inspection

of the oil flow and temperature measurement of the oil.

The temperature of the inlet oil should be 110 to 120 degrees Fahrenheit. The normal

temperature rise of the oil should not exceed 45 degrees Fahrenheit. The bearing should

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operate at a fairly constant temperature rise under full-load conditions. Any sudden increase

in the average temperature rise [five (5) degrees Fahrenheit or greater] should be considered

abnormal, even though the total rise may be within 45 degrees Fahrenheit. The TURB

THRUST BRG TEMP HIGH alarm is energized whenever the exiting oil temperature

exceeds 175 degrees Fahrenheit.

The four (4) Generator and Exciter bearings are of the elliptical design and are also

“insulated”. Refer to Generator and Exciter System Description CF7-PG06-SD for more

complete details on these bearings.

2.9.3 Turbine Bearing Data


Quantity (Turbine) Six (6) Journal and One (1) Double Thrust

Quantity (Generator/Exciter) Two (2) Each, Total of Four (4) (See CF7-PG06-SD)

Turbine Journal Bearing Type

No.1 and No.2 Bearings Six (6) Section, Flooded, Tilting Pad, Babbitted

Bearings

No.3 through No.6 Horizontal Split, Elliptical, Babbitted Bearings

Thrust Bearing Type Copper Backed, Babbitted, Tapered Land

Thrust Bearing Quantity Two (2), One (1) Active and One (1) Inactive

2.9.4 Turbine Bearing Controls

Oil to the bearings is controlled by oil orifices and the regulated oil pressure to the bearings.

2.9.4.1 Temperature Controls - Monitoring

The bearing temperatures are monitored and recorded by a Yokogawa multi-point print

wheel, which stamps the number of points being monitored. The temperature recorder

monitors both bearing metal temperature and bearing oil temperature with the scale between

0-400 degrees Fahrenheit.

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The following is a list of points monitored and recorded:

1. Turbine bearing No. 1 oil drain temperature

2. Turbine bearing No. 1 metal temperature



















A thrust bearing temperature recorder indicates and records the metal and oil temperatures

of the thrust bearing, as well as the turbine oil cooler and condenser circulating water

temperatures in and out of the condenser.

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The following is a list of the points monitored and recorded by the thrust bearing

temperature recorder:

1. Turbine thrust bearing front plate metal upper temperature

2. Turbine thrust bearing rear plate metal upper temperature

3. Turbine thrust bearing front plate metal lower temperature

4. Turbine thrust bearing rear plate metal lower temperature

5. Turbine thrust bearing front plate oil drain temperature

6. Turbine thrust bearing rear plate oil drain temperature

7. Turbine oil cooler inlet temperature

8. Turbine oil cooler outlet temperature

9. Condenser 7-1 circulating water inlet temperature

10. Condenser 7-2 circulating water inlet temperature

11. Condenser 7-1 circulating water outlet temperature

12. Condenser 7-2 circulating water outlet temperature

40 7-1 Cooling water inlet average

41 7-2 Cooling water inlet average

42 7-1 Cooling water outlet average

43 7-1 Cooling water outlet average

2.9.4.2 Vibration Controls – Monitoring

A bearing vibration recorder monitors and records the six (6) turbine, two (2) generator, and

two (2) exciter bearings. The recorder consists of a continuous strip chart with three (3) dual

ranges of 0-15 mils, and a multi-point print wheel which stamps the number of the bearing

being monitored. The recorder is driven by a two-speed motor. In the SLOW speed, the

paper moves 1-inch per hour and stamps every six (6) seconds. In FAST speed, the chart

moves 15-inches per hour and prints every 1.2 seconds. The recorder prints the correct time

on the chart, regardless of speed. The speed switch is located below the recorder door. Fast

speed is normally selected when the turbine is rolled and then transferred to slow speed

when the unit is on load.

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A vibration monitor, mounted on the top of each bearing (Figure 20), extends through the

bearing cap with an arm and a detector shoe that rides on the shaft. The detector measures

bearing vibration and transmits an equivalent electrical signal to the turbine supervisory

instrument cabinet which then sends the signal to the recorder.

Vibration

Monitor

Probe

Figure 20 – Vibration Monitor Probe

The following is a list of points monitored and recorded:

Turbine Vibration

1 Vibration bearing No. 1








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A vibration phase - angle measurement meter monitors the phase angle (position of the

unbalance) of any particular bearing. This information is useful for plotting trends in

balance and to assist in the balancing procedure.

The monitor is equipped with a meter with a range of 0-360 degrees, a filter, and a selector

switch unit. The selector switch selects any of the 10 bearings for monitoring on the meter.

The filter switch is in the IN position when the turbine is at 3600 rpm, and in the OUT

position at any other speed.

2.10 Turning Gear

The motor-driven turning gear (Figure 21) is mounted separately and independently of the

turbine-bearing cap, adjacent to the turbine- generator coupling, to permit meshing with a

bull gear. The primary function of the turning gear is to rotate the turbine-generator shaft

slowly and continuously during shutdown periods when rotor temperature changes are

occurring. The turning gear is driven by a vertical electric motor and power is transmitted

through a reducing gear train to the turbine-generator shaft.

When a turbine is shut down, cooling of its inner elements continues for many hours. If the

rotor is allowed to remain stationary during this cooling period, distortion begins almost

immediately. This distortion is caused by the flow of hot vapors to the upper part of the

turbine casing, resulting in the upper half of the turbine being at a higher temperature than

the lower half. The parts do not return to their normal position until the turbine has cooled

to the point where both the upper and lower halves are at approximately the same

temperature.

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Figure 21 – Turning Gear

During shutdowns, the turning gear is used to keep the rotor revolving continuously until the

temperature change has stopped and the casings have become cool. This eliminates the

possibility of distortion.

The turning gear is also used to jack the rotor over small amounts at desired intervals for

inspection.

During the starting period, operation of the turning gear eliminates the necessity of

"breaking away" the turbine-generator rotor from standstill with steam, and thereby provides

for a more uniform and controlled starting. It is recommended, therefore, that the turning

gear be placed in operation whenever the turbine is shut down and that it is used until the

turbine is again ready for service or until the turbine casings have become thoroughly cooled

in cases of indefinite shutdown.

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Lubrication for the turning gear and the turbine bearings is provided from the main turbine

lubricating system. Any of the auxiliary or emergency oil pumps will, therefore, provide the

lubricating requirements for turning gear operation. However, since it is possible that the

turbine may be on turning gear operation for extended periods of time, a turning gear oil

pump is provided which supplies only the turbine bearing and turning gear requirements.

Use of this pump avoids operating the emergency bearing oil pump, which is for the sole

purpose of providing a final backup of the lubricating system.

2.10.1 Turning Gear Data


Quantity One (1)

Output Speed of Turbine Three (3) rpm

2.10.2 Turning Gear Controls

The turning gear is controlled from a two-position control switch in the Unit Control Room,

and from a series of control switches and pushbuttons located at the local console beside the

turning gear motor (Figure 22).

Figure 22 – Turning Gear Local Controls

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The two-position control switch in the Unit Control Room is spring-loaded to return to the

center (neutral) position from the START or STOP positions.

START: Starts the turning gear motor provided the following permissives are

satisfied:

1. Switch is not locked out

2. Control switch on local panel is in the NORMAL position

3. Lube oil pressure at the turning gear is greater than 15 psi

4. Generator breakers are open.

After the turning gear motor is started, the turning gear automatically engages if the low

speed switch at the front end standard is energized.

STOP: Stops the turning gear. The STOP position is also provided with a PULL-

TO-LOCK feature. Placing the control switch in the STOP position and

pulling outward on the pistol grip handle lock out the turning gear.

However, the turning gear may be run from the JOG pushbutton and local

start control switch located on the local console.

Red and green indicating lights, located above the control switch in the Unit Control Room,

indicate whether the turning gear motor is running (red) or off (green).

Red and green indicating lights, located above the control switch in the Unit Control Room,

indicate whether the turning gear motor is engaged (red) or disengaged (green).

Two (2) three-position control switches, two (2) pushbuttons and four (4) indicating lights

are located on the turning gear local control console.

The two (2) three (3)-position control switches are:

1. Turning gear switch

2. Turning gear oil pump switch.

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The turning gear switch has three (3) positions: START, NORMAL, and STOP, with

spring-return back to NORMAL from the START and STOP positions.

START: Starts the turning gear motor provided the following permissives are

satisfied:

1. START position selected on the control switch

2. Lube oil pressure at the turning gear is greater than 15 psi

3. Generator breakers are open.

After the turning gear motor is started, the turning gear automatically

engages if the low speed switch at the front end standard is energized.

NORMAL

(AUTO): Allows the turning gear to be started automatically by the low speed switch,

and started or stopped by the control switch located in the control room.

Locking the control room control switch out does not affect starting or

stopping from the local panel.

The turning gear automatically starts if all the following conditions occur:

1. The local control switch is in the NORMAL position

2. The low speed switch at the front end standard is energized due to

turbine shaft speed

3. The lube oil pressure at the turning gear is greater than 15-psi

4. The generator breakers are open.

STOP: Placing the control switch in the Stop position stops the turning gear motor.

The turning gear oil pump control switch is discussed in Training System

Description CF7-PG03-SD, Main Turbine Generator Lube Oil and

Conditioning.

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The two (2) pushbuttons on the local panel are:

1. ENGAGE pushbutton

2. JOG pushbutton.

ENGAGE: Depressing the turning gear ENGAGE pushbutton energizes an air solenoid

causing an air piston to engage the turning gear if the:

1. Turning gear motor is running

2. Low speed switch at front standard is energized.

JOG: Allows the turning gear motor to be energized from the local console if the

following permissives are satisfied:

1. Local control switch is in the NORMAL or START position

2. Turning gear lube oil pressure is above 15 psi.

The turning gear trips if an overcurrent condition occurs. An alarm sounds if any of the

following conditions exists:

1. Low bearing oil pressure

2. Turning gear not engaged or not operable.

Local panel indicating lights are:

1. Turning gear run: A red light indicating when the turning gear motor is running

2. Turning gear disengaged: A green light indicating the turning gear is disengaged

3. Turning gear engaged: Red light indicating the turning gear is engaged

4. Turning gear ready for auto start: A red light indicating 15 psi oil pressure

available.

2.11 Turbine Auxiliary Equipment

The main turbine is provided with the following auxiliary equipment:

1. Auxiliary valves

2. Turbine drains

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2.11.1 Auxiliary Valves

The main turbine auxiliary valves are:

1. Ventilator valve (VV)

2. Equalizer valve

3. Packing blowdown valve (BDV)

4. Heating steam blocking valve (HSBV)

5. Turbine Drains

2.11.1.1 Ventilator Valve (VV)

In the event of a turbine trip while carrying load, the high-pressure turbine blading may

seriously overheat, due to heat build up caused by windage, if allowed to spin in high-

pressure bottled-up steam.

The purpose of the ventilator valve is to open during a turbine trip. This allows steam to be

drawn from the reheat section of the boiler backwards through the rotating turbine blades,

through the ventilator valve, and then exhaust to the condenser. This valve is not used to

quickly blowdown the reheater, but rather only to provide a relatively small cooling flow

through the HP turbine with the turbine tripped and the shaft still rotating.

The ventilator valve connects the HP turbine downstream of the No. 1 control valve to the

main condenser. The ventilator valve, which is normally closed, automatically opens when

a turbine trip is initiated to allow the high-pressure steam in the reheater to flow backward

through the HP turbine to the main condenser.

The ventilator valve is pneumatically operated by control signals supplied from the Electro

Hydraulic Control System. The ventilator valve automatically opens when the control

valves are closed in partial arc admission or the stop valves are closed in full arc admission,

and the reheat pressure is above 10 percent. There is also a limit switch attached to the

ventilator valve, which trips the Unit when the ventilator valve is opened.

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The valve is a balanced type valve with an internal pilot valve. The upward stroke of the

stem lifts the pilot valve off its seat. This action allows steam to flow through drilled

passages in the main disk to the downstream side of the valve. As the pressure drop across

the valve equalizes, the stem force lifts the main disc off its seat. An alarm VENT VALVE

OPEN, is energized in the control room, when the valve opens. A temperature switch actu-

ates an additional alarm VV OUTLET TEMP HIGH.

2.11.1.2 Equalizer Valve

The equalizer valve allows reopening of the reheat stop valves following a trip anticipator

action. It is located on the No. 2 combined reheat intercept valve. The equalizer valve

reduces the pressure differential across the reheat stop valve by connecting the intercept

valve reheat chamber through piping to the condenser.

The equalizer valve is an air-opened, spring-closed, valve specially designed to seal against

condenser vacuum. It opens anytime both combined reheat intercept valves are closed.

2.11.1.3 Packing Blowdown Valve (BDV)

The packing blowdown valve connects the interstage packing chamber (mid span) between

the HP and IP turbine to the main condenser. The packing blowdown valve helps prevent

the turbine from over speeding following a turbine trip.

When the turbine is tripped the main stop valves, control valves, intercept valves, and reheat

stop valves close. This results in a large volume of steam at high energy levels being bottled

up in the reheat section of the boiler and the HP turbine. This steam is at reheat pressure

while the IP turbine and LP turbine sections downstream of the reheat stop valves are under

a vacuum. Because of this, steam flows through the shaft packings between the HP and IP

turbines. If these packings are worn, sufficient steam leakage flow is possible to drive the

turbine to overspeed if allowed to expand through the low-pressure end of the turbine.

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The packing blowdown valve prevents the steam packing leakage from entering the IP

turbine following a turbine trip. The packing blowdown valve automatically opens

whenever the intercept valves are less than 20 percent open.

2.11.1.4 Heating Steam Blocking Valve (HSBV)

The heating steam blocking valve connects the HP turbine exhaust end seal leakoff to the IP

turbine exhaust. The heating steam blocking valve is normally open. Steam from the HP

turbine exhaust end seal leakoff enters the IP turbine exhaust downstream of the extraction

check (dump) valve.

The same trip signal that opens the packing blowdown valve closes the heating steam

blocking valve. This prevents the steam leakoff from expanding through the IP turbine,

causing a turbine overspeed should the extraction check (dump) valve fail to close. During

rotor prewarming, the heating steam blocking valve is given a hard close signal by the

prewarming circuit. This assures no steam flow between the high-pressure packing and IP

turbine during rotor prewarming; thus, lessening the chance of rolling the turbine off turbine

gear with steam.

2.11.2 Turbine Drains

Refer to Drawing 5 as the turbine drains are described in the following paragraphs.

Drains are installed in the turbine steam inlet piping to remove moisture that might collect

due to the condensation of steam. These drains are located at various low points where

water collects. The following drains are provided:

1. Main stop valves above and below seat drains

2. Control valve steam lead drains (SLDV)

3. Intercept valve after seat drains.

2.11.2.1 Main Stop Valve Above and Below Seat Drains

Drains from above the main stop valves are routed to the blowdown header through motor-

operated isolation valves. Drains from below the seat of main stop valves are routed to the

condenser through motor-operated isolation valves.

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The above seat drain valves drain the valve body upstream of the seat, and also drain a

portion of the main steam line. The below seat drain valve drains the valve body

downstream of the seat, and also the steam chest between the stop valves and control valves.

The main stop valves above and below seat drain valves are interlocked to open when the

generator breaker opens and close when the generator breaker closes.

The four (4) main stop valves above and below seat drains are automatically controlled.

Any one (1) of the following conditions will cause these valves to open:

1. Turbine trip

2. Appropriate generator disconnect switch 1404 auxiliary relay de-energized

3. Both the appropriate generator air circuit breaker 1401 auxiliary relay de-

energized, and the appropriate generator air circuit breaker 1405 auxiliary

relay de- energized.

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Right

Side

CRV

Left Side CRV

Control Valves

HP IP

1

2

4

3

1

2

Main Steam

Stop Valves

1

2

To Blowdown Header

MOV SV1

MOV SV3

MOV SV2

To Condenser

To Condenser

To Condenser

MOV IV4

Control Valve Drain Manifold

Orifice

To

Condenser

MOV

IV2 To

Condenser

MOV SV4

MOV

S4

Drawing 5 - Turbine Drains

2.11.2.2 Control Valve Steam Lead Drains

A drain line is connected to each of the four (4) steam leads from the control valves to the

HP turbine. Each steam lead is tapped at its low point and piped to a common drain

manifold, which is routed to the condenser through a motor-operated manifold drain valve

(S4). The motor-operated manifold drain valve is opened during startup and remains open

until the turbine-generator is up to 15 percent load 1st stage pressure. The No.1 steam lead

drain is routed directly to the manifold. The No.2 and No.3 steam lead drains are routed to

the manifold through pneumatically operated drain valves. These drain valves are operated

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by the Electro Hydraulic Control System. The No.4 steam lead drain is routed to the

manifold through a 3/16-inch orifice.

The two (2) pneumatically operated drain valves (No.2 and No.3) automatically open by

either of the following:

1. The drain valves are opened at any time below a control valve position

corresponding to the cracking point of the No. 2 control valve when in partial arc

admission.

2. The drain valves open when operating in full arc admission if the stop valves are

not fully opened.

This arrangement of steam lead drains provides adequate draining of the steam leads during

startup, and continued heating of the control valves and steam leads with minimum loss as

load is increased, thus avoiding thermal shock as the control valves open.

2.11.2.3 Intercept Valve After Seat Drains

The intercept valve after seat drain valves drain the valve body downstream of the valve

seat. The after seat drain lines are routed to the main condenser through motor-operated

isolation valves.

The intercept valve after seat drain valves are opened during startup, and automatically close

after the turbine reaches 15 percent 1st stage pressure.

2.12 Turbine Subsystems

In addition to the main turbine component and auxiliary equipment, the main turbine is also

supplied with individual support subsystems:

1. Extraction Steam System

2. Exhaust Hood Cooling System

3. Turbine Lubricating Oil System

4. Electro Hydraulic Control System

5. Rotor Prewarming System

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6. Steam Seal System.

2.12.1 Extraction Steam System

The Extraction Steam System extracts steam from various turbine stages and supplies steam

to the following:

1. Feedwater Heaters

2. Boiler Feed Pump Turbines.

The major components of the Extraction Steam System are piping and valves. The

Extraction Steam System is discussed fully in Training System Description CF7-PG04-SD,

Extraction Steam and Heater Drains System.

2.12.2 Exhaust Hood Cooling System

During startup and low load operation, turbines remove little energy from their driving

steam, with the result that the exhaust hood temperature reaches an exceptionally high level.

This high temperature affects the mechanical characteristics of the turbines' last stages, inner

casings, and exhaust hoods.

To control this temperature a water spray system, with nozzles installed just downstream of

the last stage buckets, is provided in each LP turbine.

The major components of the exhaust hood cooling system are the exhaust hood spray valve

and associated piping. The exhaust hood spray valve routes condensate from the condensate

pump discharge, to the exhaust hood spray nozzles in the low-pressure turbines.

An air-operated control valve controls the flow of water to the nozzles. This valve receives

pneumatic positioning signals from a pressure selector/relay associated with temperature

sensors installed in the two (2) LP turbine hoods. The exhaust hood cooling water valve

begins opening at an exhaust hood temperature of 120 degrees Fahrenheit and is fully open

at 180 degrees Fahrenheit. A manual bypass valve, which is to be used if the automatic

system fails, is provided.

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A compound pressure gauge is installed upstream of the spray nozzles but downstream of

both the control and the bypass valve, to indicate line pressure at that point.

If exhaust hood temperature rises to 175 degrees Fahrenheit, the appropriate thermostat (one

(1) is located in each exhaust hood) closes a set of contacts to activate the respective alarm

in the control room, TURBINE EXHAUST HOOD A OR B TEMP HIGH. A second set of

contacts, which close at 225 degrees Fahrenheit exhaust hood temperature, are wired to

actuate the "TURBINE EXHAUST HOOD A OR B TEMPERATUER VERY HIGH"

alarm. The turbine exhaust hood spray regulator should be left in service at all times. If it is

not placed in service until the hood temperature is high, it should be put in service slowly to

prevent a sudden temperature change in the LP turbines. Exhaust hood temperature is

indicated on a recorder in the control room and locally on each exhaust hood.

2.12.3 Turbine Lube Oil System

The turbine lube oil system supplies the oil necessary for lubricating the main turbine

generator support and thrust bearings. The turbine lube oil system is discussed in Training

System Description CF7-PG03-SD, Main Turbine Lube Oil System.

2.12.4 Electro Hydraulic Control System

The Electro Hydraulic Control System positions the main steam stop valves, control valves,

and combined reheat intercept valves to control the steam flow to the turbine, and to provide

protection from abnormal conditions. The Electro Hydraulic Control System is fully

described in Training System Description EHC Control System.

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2.12.5 Rotor Prewarming System

The rotor prewarming system consists of an electrical circuit incorporated within the EHC

System, and turbine valves which this circuit positions. The valves and their prewarming

positions are listed below:

1. Main Stop Valves (closed)

2. Main Stop Valves, Bypass Valves (open)

3. Ventilator valve (closed)

4. Blowdown valve (open)

5. Heating steam blocking valve (closed)

6. Steam lead drain valves (open)

The function of the rotor prewarming system is to preheat the high-pressure and reheat

turbine rotors prior to admitting high temperature steam to the turbine during a cold startup.

This prewarming is important for several reasons:

1. Cyclic life of rotor and shell surfaces are increased because warming is

accomplished with more gradual transients.

2. Thermal stress at the rotor bore is reduced by gradual bore-warming so that the

combined thermal and centrifugal stresses at the rotor bore are not excessive.

3. The rotors and shells are warmed so that their temperature is above the transition

temperature. The transition temperature (300 deg F) is that temperature below

which the metal is brittle; and above which the metal is tough and ductile, much

more tolerant of possible defects, and thus much better able to withstand the

thermal and centrifugal stresses.

Recently obtained data from long-term aging tests on high temperature rotor materials have

revealed a tendency toward embrittlement with time - that is, the transition temperature

increases with time in service. Similar effects have been noted i

typical turbine system and description

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