Typical Turbine System and Description

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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 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.

1

Typical Turbine System and Description 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............................................................... Components....... ........................................................................................ ................................ 12

2.1

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

2.1.1

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

2.1.2

Main Stop Valve Control ...................................................... ............................................................................................... ......................................... 17

2.2

Control Valves ...................................................... .............................................................................................................. ............................................................ .... 17

2.2.1

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

2.2.2

Control Valve Controls............................................... 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)............................................................ (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................................................... 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.................................................. Data.................................................................................. ................................ 32

2.6.2

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

2.7

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

2.7.1

Turbine Protective Devices............................................................ 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

2

Typical Turbine System and Description 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 2.11.1

Turbine Auxiliary Equipment .................................................. ......................................... 53 Auxiliary Valves ................................................ ............................................................ 54

2.11.1.1 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 3


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

4

Typical Turbine System and Description 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

5

Typical Turbine System and Description 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

6

Typical Turbine System and Description 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

Function

The 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.

7


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 co nsists 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.

8


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.

10


Main Steam

Hot Reheat Steam

Control Stop Valves Valve

1

Stop Valve

Left Side CRV LP Crossover Pipe

Top Steam Lead Bottom Steam Lead

1 2 4

2

1

3

HP

IP

LP-A TE

LP-A GE

LP-B TE

Cold Reheat

Bottom Steam Lead Top Steam Lead

Control Valve Chest

CONDENSER

Hot Reheat Steam

2

Right Side CRV

HOTWELL

Drawing 1 - Basic Steam Flow

11

LP-B GE


This Page Intentionally left Blank

12


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.

13


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.

Steam Strainer Steam Inlet

Valve Disc Pressure Seal Head

Valve Seat

Valve Stem

Steam Outlet

Closing Spring

Actuator

Figure 1 – Main Stop Valve

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.

14


MAIN STOP VALVE, BYPASS VALVE DISC

MAIN STOP VALVE DISC

BYPASS VALVE PORTS (8 EA)

MAIN STOP VALVE DISC SEATING SURFACE

MAIN STOP VALVE STEM

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

15

Typical Turbine System and Description 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.

16


Main Steam Stop Valve Data

Manufacturer

General Electric

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.

17


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.

18

Typical Turbine System and Description Steam From No. 3 Control Valve

Steam From No. 1 Control Valve

Snout Pipes Snout Pipe Seal Rings HP Inner Shell

180 Degree Nozzle Box

HP Inner Shell

HP Inner Shell Upper Rotor Lower

HP Inner Shell

HP Inner Shell

180 Degree Nozzle Box

HP Inner Shell

Snout Pipe Seal Rings

Snout Pipes Steam From No. 2 Control Valve

Steam From No. 4 Control Valve

Drawing - Shell andNozzle Nozzle Assembly Drawing 2 – 2Shell and Assembly

19

Typical Turbine System and Description 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 4 control 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.

20

Typical Turbine System and Description 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

Manufacturer

General Electric

Quantity

Four (4)

Actuate (Open)


Actuate (Close)

Closing Spring


2400-psi



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.

21

Typical Turbine System and Description Flow

Diaphrag (Stationary 6th

5th

4th

3rd 2nd

Nozzle (1st

HP Section

6th

5th

2nd 4th 3rd

IP 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.

22


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

Manufacturer

General Electric

Type

Impulse

Speed

3600 rpm

Number of Stages

Six (6)

Inlet Pressure

2400-psi

Inlet Temperature


2.3.2

High Pressure (HP) Turbine Section Controls

The HP turbine is operated and controlled by the turbines Electro Hydraulic Control (EHC) System in concert with the Units DCS Control System.

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

23

Typical Turbine System and Description 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 belowseat 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.

24


Steam Strainer

Balance Chamber

Closing Springs

In

Intercept Disc Intercept Actuator

Out

Reheat Stop Disc

Closing Springs

Reheat Stop Actuator

Figure 6 – Combined Reheat Valve (CRV)

25


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.

26


Figure 8 – Right Side (No.2) CRV

2.4.1

Combined Reheat Valves (CRV’s) Data

Manufacturer

General Electric

Quantity

Two (2)

Actuate (Open)


Actuate (Close)

Closing Spring


650-psi



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

27

Typical Turbine System and Description 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. Hot Reheat Steam Dia hra ms (Stationary Stages) 9th

10th

11th

8th 7th

Nozzle Block

IP Section

HP

7th

8th

9th

10th

11th

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.

28

Typical Turbine System and Description 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

Manufacturer

General Electric

Type

Impulse

Speed

3600 rpm

Number of Stages

Five (5)

Inlet Pressure

650-psi (Approximate)

Inlet Temperature


2.5.2

Intermediate Pressure (IP) Turbine Controls

The operation of the IP turbine is controlled by the turbines Electro Hydraulic Control (EHC) System in concert with the Units DCS Control System.

29


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.

30


Steam Flow Atmospheric Relief Diaphragm

Atmospheric Relief Diaphragm

Low Pressure Exhaust

Inner Case

Bearing No.3

Bearing No.4

Steam

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: th

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



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

31

Typical Turbine System and Description 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

Manufacturer

General Electric

Type

Impulse

Speed

3600 rpm

Number of Stages

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

Rotors) Exhaust Pressure

2.6.2

1.0-inch Hg

Low Pressure (LP) Turbine Controls

The operation of the LP turbines is controlled by the turbines Electro Hydraulic Control (EHC) System in concert with the Units DCS Control System.

32


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.

33

Typical Turbine System and Description 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.

34

Typical Turbine System and Description 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 magnetic sensors attached to the front 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 turbine casing, any movement of the casing causes the 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 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 with the toothed wheel. The sensor consists 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 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.

35


Middle Standard

The turbine middle standard, illustrated in Figure 12, houses the following components: 1. Main turbine turbine journal bearings 2 and 3 (Discussed (Discussed in Section 2.9 of this System Description) 2. High pressure and "A" low pressure 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.

36


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 turbine shaft compared to the thrust 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. 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 transposed into a wear reading, and

37

Typical Turbine System and Description activates two (2) press pressure ure switches. Activation of a single pressure pressure switch sounds an alarm; activation of both switches trips trips the Unit. The thrust bearing wear detector trip 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.

38


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.

39

Typical Turbine System and Description 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.

40


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.

41


Copper Backed Tapered Land Thrust Plates

Thrust Runner

Thrust Runner Thrust Case

Turbine Shaft

Thrust Case

Spacer 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,

42

Typical Turbine System and Description 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.

Copper Backed Thrust Plate

Babbitt ed Tapered Lands

Oil Wedge Oil Wedges Formed by Tapered Lands Thrust Runner

Direction of Rotation

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

43

Typical Turbine System and Description 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

Manufacturer Quantity

General Electric (Turbine)

Quantity (Generator/Exciter)

Six (6) Journal and One (1) Double Thrust 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.

44

Typical Turbine System and Description 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

3.


4.


5.


6.


7.


8.


9.


10.


11.


12.


13.


14.


15.


16.


17.


18.


19.


20.


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.

45

Typical Turbine System and Description 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.

46

Typical Turbine System and Description 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

2


3


4


5


6


7


8


47

Typical Turbine System and Description 9


10


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.

48


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.

49

Typical Turbine System and Description 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

Manufacturer

General Electric

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

50

Typical Turbine System and Description 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 PULLTO-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.

51

Typical Turbine System and Description 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.

52

Typical Turbine System and Description 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

53

Typical Turbine System and Description 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.

54

Typical Turbine System and Description 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 actuates 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.

55

Typical Turbine System and Description 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 motoroperated isolation valves. Drains from below the seat of main stop valves are routed to the condenser through motor-operated isolation valves.

56


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 deenergized, and the appropriate generator air circuit breaker 1405 auxiliary relay deenergized.

57


Main Steam

1

To Condenser

MOV SV2

Left Side CRV

MOV IV2

To Condenser

Control Valves

Stop Valves

1 1 2

MOV SV1

HP

IP

4 2 3

Orifice MOV SV3 MOV SV4

Right Side CRV

To Condenser

2

To Blowdown Header

MOV IV4

Control Valve Drain Manifold

MOV S4

To Condenser

To Condenser

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

58

Typical Turbine System and Description 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

59

Typical Turbine System and Description 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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Typical Turbine System and Description 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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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 in tests on older low pressure rotors. Thus, it becomes even more desirable to prewarm older rotors during cold starts. Operation of the rotor prewarming circuit is explained in detail in Training System EHC Control System.

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2.12.6 Steam Seal System

The function of the steam seal system is to prevent air leakage into, and steam leakage out of the main turbine and BFP turbines from the shaft seals. This is accomplished by: 1. Supplying sealing steam to the main turbine shaft at points where the turbine shaft penetrates the turbine casings. 2. Collecting and condensing steam, which flows out through the turbine glands, and returning the condensate to the main condenser. 3. Supplying sealing steam to various turbine valves.

The steam seal system is also utilized by the boiler feed pump turbines and is discussed in detail in Training System Description Boiler Feed Pumps and Turbines System.

A diagram of the steam seal system is illustrated in Drawing 6. The steam seal system consists of a steam seal header and the control valves, which regulate the flow and pressure of the sealing steam at different turbine loads.

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TO ATMOSPHERE GLAND EXHAUSTERS

CONDENSATE TO AND FROM GLAND STEAM CONDENSER

GLAND STEAM

Main Steam

STEAM SEAL DESUPERHEATER

TO CONDENSER

Stem Leakoff To Hot Reheat

C 1

C 2

C 4

C 3

STEAM CHEST

S 1

S 2 N-1

HP

N-2

TO HP TURBINE

IP

N-3

LP-A

N-4

N-5

N-6

LP-B

N-7

BDV

To Hot Reheat

Steam Seal Instrument Board

Steam Seal Diverting Valve SSDV

To Condenser

Orifice

Drain To Condenser

To Condenser

SPUV Steam Pressure Unloading Valve SSFV Steam Seal Feed Valve

Drawing 6 - Steam Seal System

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Auxiliary Steam Seal Regulator

To Extraction Steam

Typical Turbine System and Description Labyrinth type shaft packings (Figures 23 and 24) are located at points where the shaft passes through the turbine casing. The shaft packings limit the flow of steam through the openings in the turbine casing and seal these openings against the leakage of steam to the atmosphere or air into the turbine. STEAM SEAL LANDS

MAIN STEAM

AIR STEAM PACKING

STEAM PACKING

SEALING STEAM IN DURING START UP AND LOW LOAD

STEAM PACKING

SEALING STEAM EXHAUST

SEALING STEAM OUT DURING FULL LOAD

Figure 23 – Packing Gland Arrangement HP/IP Turbine

The packing is a steam-throttling device consisting of stationary and rotating teeth arranged concentrically with small radial clearance. This arrangement presents a high resistance to the flow of steam and greatly reduces the amount of leakage.

The main turbine is provided with seven (7) shaft packings, one (1) located at each end of the HP and IP turbine, one (1) located at each end of the two (2) LP turbines, and one (1) located between the HP and IP turbines.

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Typical Turbine System and Description SLANT CUT SEAL GROOVES

AIR

SEALING STEAM EXHAUST

SEALING STEAM IN

Figure 24- Packing Gland Arrangement LP Turbines

Steam must be supplied to the shaft seals at all times when there is a vacuum in the main condenser. This is necessary to prevent air leakage into the turbine and condenser. The pressure of the steam in the steam seal supply header is maintained at approximately four (4) psi.

The steam seal system can be divided into the following two (2) major sections: 1. Steam supply 2. Packing exhaust.

Sealing steam is supplied to the steam seal header from the main steam line: 1. During startup, after the boiler has developed sufficient pressure. 2. Before the Unit is on load. 3. After the Unit is on load, but the HP and IP turbine is not up to pressure.

Steam flows from the main steam line through a motor-operated steam feed isolation valve (MOV-S1) and a steam seal feed valve (SSFV) to the steam seal header. The steam seal feed valve senses steam seal header pressure, and starts closing as the pressure increases toward four (4) psig. If the steam seal feed valve fails or does not allow enough steam to

66

Typical Turbine System and Description pass on startup, steam seal feed bypass valve MOV-S2 may be opened. The steam seal feed bypass valve can be opened from the control room regardless of header pressure.

With little or no pressure in the HP and IP turbine, and a vacuum in the LP turbines, steam flows into the seals on all four (4) turbine sections and the following associated valves: 1. Control Valves 2. Main Stop Valves 3. Ventilator Valve 4. Blowdown Valve 5. Combined Reheat Valves 6. Steam Seal Diverting Valve.

As turbine load increases, steam pressure inside the main turbine increases. When this pressure is great enough, steam reverses direction and starts flowing out from the turbines toward the LP turbine seals.

After the turbine is up and on an increased load, sealing steam to the steam seal header is then supplied from: 1. Steam seal leakoff from the main stop valves stem (there is no leakoff when the stop valves are full open) 2. Control valves' stem leakoff 3. HP and IP turbine shaft seal leakoff 4. Blowdown valve stem leakoff.

NOTE: Due to the LP turbine being under a vacuum, steam always flows into the

seals. Reverse steam flow from the LP turbine seals to the steam seal header does not occur.

As the turbine generator load increases, more steam flows to the steam seal header from the pressure packings, increasing the header pressure. Because of the increased steam seal header pressure, the steam seal feed valve, sensing steam seal header pressure, closes. At

67

Typical Turbine System and Description this time the steam seal system is no longer dependent upon the steam seal supply from the main steam line, and the turbine is said to be self-sealing.

Figure 25 – Steam Pressure Unloading Valve

As turbine load is increased, the amount of steam flowing out of the main turbine seals to the seal supply header continues to increase. In order to maintain the supply header pressure at four (4) psig, the steam pressure-unloading valve (SPUV) (Figure 25) is installed in the supply header.

This valve dumps excess steam to the low-pressure feedwater heater 7-1A (normal), or to the condenser (backup), by means of the steam seal-diverting valve.

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Typical Turbine System and Description If the steam pressure-unloading valve fails, allowing header pressure to increase above 4.psig, the steam pressure unloading motor-operated bypass valve (MOV-B) (Figure 26) can be opened from the control room to regulate pressure.

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

If steam seal header pressure increases above 20 psig, relief valve R1 opens. If the header pressure increases above 200-psi, relief valve R2 opens.

Normally, above one-half load, excess steam for the steam seal header discharges through the automatic unloading valve to the diverting valve into the top of the shell on the 7-1A LP heater. This steam mixes with the steam extracted from the turbine and is condensed. Under abnormal conditions, it is possible for the steam from the steam seal header to go back through the extraction line into the turbine. These abnormal conditions fall into two (2) general categories: 1. If, under unusual circumstances, the automatic steam seal supply valve sticks open, more steam is supplied to the steam seal header from the main steam line than is required. Under this condition, the steam seal regulator-unloading valve

69

Typical Turbine System and Description opens automatically and permits hot steam to enter the low-pressure turbine through the extraction line.

2. If the heater in the extraction line is removed from service for repairs when operating above one-half load, or if the steam supply to the heater is shut off because of flooding, steam discharging through the unloading valve would flow back into the turbine. This steam would generally be at an appreciably lower temperature than the throttle steam, which is admitted as described above, but it is still hotter than the normal operating temperature of the low-pressure extraction stage of the turbine.

Therefore, the steam seal diverting valve (Figure 27) is provided to dump the excess steam seal header pressure to the main condenser when conditions are such that this steam would enter the extraction stage of the turbine instead of going to the feedwater heater.

Figure 27 – Steam Seal Diverting Valve

The system also has an auxiliary steam seal regulator (Figure 28) to supply sealing steam from another unit.

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Figure 28 – Auxiliary Steam Seal Regulator

The turbine shaft seals are labyrinth type packings, which minimize leakage by providing a tortuous path. A portion of the steam supplied to the seals normally flows toward the outer packing rings. This steam is drawn to the steam packing exhauster, along with some turbine building air, through the exhaust header. A vacuum (approximately 10 inches of water) is maintained on the exhaust header piping by the gland steam condenser. The gland steam condenser consists of a shell and U-tube condenser and two (2) exhaust fans (Figure 29).

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Figure 29 – Gland Steam Condenser and Exhauster Blower(s)

Condensate flowing through the U-tubes condenses the sealing steam. Non-condensable gases are discharged to the atmosphere through the fan, and the condensate drains to the condenser via the miscellaneous drains tank.

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System Operation

Chapter Objectives: Describe the Turbine System operation during: -

System Startup

-

Normal Operation

-

System Shutdown

NOTE: This System operation section is included for instructional purposes

only, and should not be used as an operating procedure.

3.1

System Startup

Verify the status of the Turbine control and ATS control screens and open, or verify open, the Stop Valve, Combined Reheat Valve, Main Steam Lead, Cold Reheat, Hot Reheat and Extraction Steam Low Point drains.

Verify that the Lube Oil System is in service; the turning gear oil pump is on and start the main turbine turning gear by pressing the turning gear motor control pushbutton to START.

Visually inspect the turbine to verify that it is rolling, and that there is no indication of rubbing.

Start up the turbine steam seal system by starting one (1) steam packing exhauster blower by turning its control pushbutton to START. Verify that a vacuum of approximately 10 inches H2O is established in the steam seal leak-off header and open the steam seal feed isolation valve to the steam seal header. [If steam seal pressure is not high enough then open the steam seal feed bypass valve to increase the pressure to four (4) psi.] Verify that the steam seal feed valve controller is in automatic.

Establish a vacuum in the main condenser as per start-up procedure.

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Typical Turbine System and Description NOTE: If the 1st stage shell inner surface thermocouple temperature is less than 300 degrees Fahrenheit, prewarm the turbine as established by the Starting and Loading procedure.

Prior to rolling the turbine with steam, record the turbine metal temperatures and steam conditions. The temperature ramp rates for the high pressure and reheat sections of the turbine from blocks 3 and 4 of the starting and loading chart have been set at 150 degrees Fahrenheit per hour. Do not exceed this rate at any time during the startup or subsequent operation.

Use the starting and loading chart to determine the proper startup rate, “hold” durations, initial load, and initial load duration.

Start the motor suction oil pump by pressing the START pushbutton, and “reset” the turbine.

Select the startup rate according to the starting and loading chart by depressing the SLOW, MEDIUM or FAST pushbutton and enter 200-rpm speed setpoint on the SPEED CONTROL switch N, in the TURBINE AUTO CONTROL.

Verify that the turning gear has disengaged and stop the turning gear motor.

When the SPEED indication shows “set speed”, select the desired speed as determined by the starting and loading chart.

Verify that the SPEED starts to increase, and walk the turbine down listening for rubs as the turbine is rolled.

Verify from the TURBINE AUTO CONTROL screen that the control valves and combined reheat intercept valves open fully and the main stop valve bypasses crack open to roll the turbine. The turbine speed will now increase under speed control to speed set selected.

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Typical Turbine System and Description Hold the turbine speed at 1000 rpm, if necessary for a heat soak required by the starting and loading chart.

Depress the 3000-rpm pushbutton on the SPEED SET RPM panel. When the turbine speed increases to 1600 rpm the turbine speed rate will automatically increase to 600 rpm. This is to rapidly accelerate the turbine through its two (2) critical speeds of 1800-1900 rpm and 2600-2700 rpm.

If a hold at 3000 rpm is necessary, the Wobbulator will automatically raise and lower the reference speed from 2900-3100 rpm in a slow cycle to avoid running for an extended period of time at a bucket critical speed. Hold the turbine at 3000 rpm for a heat soak if required by the starting and loading chart.

Test the oil trip speed when the turbine speed is approximately 3300 rpm; the mechanical oil trip device should trip at 3400 rpm. If it does not trip shut down the turbine immediately.

Change the setpoint on the SPEED CONTROL to 3600 rpm. Hold the turbine at 3600 rpm for a heat soak if required by the starting and loading chart.

When the generator breaker is closed, as indicated by the TURBINE AUTO CONTROL panel circuit breaker light, select the manual mode on the EHC panel load selector. Then select the 10 percent loading rate briefly to apply initial load preventing motorizing of the generator.

Verify that the drains interlocked with the generator go closed.

Increase the load to the load point established in the startup by increasing the TURBINE LOAD CONTROL setpoint pushbutton on the load selector panel.

Stop the turning gear oil pump and the motor suction oil pump.

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Typical Turbine System and Description Hold at the initial load for the time determined from the starting and loading chart. After the initial load hold, increase the turbine load by changing the load setpoint. Do not exceed the temperature ramp rates of 150 degrees Fahrenheit per hour. Control the firing rate, pressure and loading rate as necessary to maintain ramp rates.

Determine the proper transfer time by use of the two (2) allowable temperature differential charts (Refer to Figure drawings UOP-1-1 and UOP-1-2.

When the TRANSFER light comes on, transfer is accomplished Automatically. Verify that stop valves come wide open and the control valves throttle to maintain load. If manual is not selected then F/A to P/A transfer will take place at the high transfer point (maximum steam flow through the stop valve bypass valves).

When 1st stage pressure is high enough to produce approximately 15 percent load (80 MW), verify that the steam drains close.

Load Unit as directed by the Load Dispatcher.

3.2

Normal Operation

During normal operation, the main turbine is in service at full load (530 MW), converting the thermal energy of steam from the boiler into mechanical energy for turning the generator. The Turbine Electro Hydraulic Control System (EHC) automatically controls the main turbine steam flow.

The turbine lubrication system is in service, with the shaft- driven main oil pump supplying all of the lube oil requirements of the main turbine and generator. The motor suction pump, emergency bearing oil pump, and the turning gear oil pump control switches should be selected for automatic operation.

The main turbine gland steam seals must be in service supplied and controlled by the steam seal control valves.

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The turbine supervisory instruments and recorders must be in service, monitoring the mechanical operating parameters of the main turbine.

3.3

Abnormal Operation

Abnormal operations discussed in the following paragraphs include: 1. High vibration 2. Operation with feedwater heaters removed from service 3. Turbine trip.

3.3.1

High Vibration

In the event of high turbine vibration, action must be taken immediately to prevent/minimize damage. If the vibration exceeds 10 mils on bearings 1 through 10, an automatic turbine trip occurs.

If the automatic trip setpoint is not exceeded, it may be possible to reduce the vibration to acceptable levels. Varying the turbine load or lube oil temperature may reduce the vibration. The operator should monitor the following recorders for irregularities: 1. Differential expansion 2. Turbine bearing metal temperature 3. Turbine bearing oil temperature.

3.3.2

Operation With Feedwater Heaters Removed From Service

Assuming that the throttle steam flow is not changed, the following will occur when a feedwater heater is removed from service: 1. If the highest-pressure heater is removed from service, megawatt output increases. This occurs because the steam, which was formerly extracted, now passes through the turbine to the condenser. (In order to maintain a constant megawatt output when the highest-pressure heater or heaters are removed from service, the control valve position is reduced.)

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Typical Turbine System and Description 2. When other than the highest pressure heater is removed from service, extraction flow to the next higher pressure heater increases because the feedwater temperature rise across that heater is greater than formerly. A slight decrease in megawatt output will be noted.

3. Turbine and feedwater cycle efficiency decreases when any feedwater heater is removed from service.

Conditions a and b affect stage pressure, stage pressure drops, and steam flow through the turbine, so that bucket, diaphragm, and thrust loading, etc. are affected.

The turbine is designed and built so that heaters may be removed from service without undue loading and overstressing of any part. The control valve position is adjusted so the megawatt load is in accordance with the following:

1. The maximum guaranteed output can be generated with one (1) or more nonadjacent heaters removed from service.

2. The maximum guaranteed output can be generated with adjacent heaters removed from service, provided all heaters at higher pressure are also removed from service. That is, heaters are removed from service in sequence, starting with the highest pressure heater and proceeding in order to the lowest pressure heater to be removed from service. Similarly, when the heaters are returned to service, the lowest pressure heater is placed in service first, and then proceeding in order to the highest pressure heater.

3. The turbine may be operated with the highest pressure heater in service, and any combination of adjacent lower pressure heaters out of service with megawatt generation as follows: •

90 percent of maximum guaranteed output with two (2) adjacent heaters out of service

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Typical Turbine System and Description •

80 percent of maximum guaranteed output with three (3) adjacent heaters out of service

•

70 percent of maximum guaranteed output with four (4) adjacent heaters out of service

•

60 percent of maximum guaranteed output with five (5) adjacent heaters out of service.

3.3.3

Turbine Trip

If a turbine trip occurs, all turbine steam valves are closed to stop steam flow to the turbine. A turbine trip may be caused by any of the following conditions: 1. Vacuum trip; 23 inches Hg vacuum (7.5 inches Hg back pressure) 2. Low hydraulic pressure; 1100 psig 3. Loss of turbine trip EHC fluid pressure; 800-psi 4. Main shaft-driven oil pump pressure low; less than 105-psi and speed greater than 2592 rpm 5. Thrust bearing wear detector; .030 inch turbine shaft movement or lubricating oil pressure less than eight (8) psi 6. High bearing vibration Bearings 1 through 10; 10-mils 7. Loss of stator cooling 8. Loss of both primary speed signals 9. Loss of EHC input DC power 10. Loss of 24V DC to solenoid valves 11. Mechanical overspeed trip; 3960 rpm 12. Back-up overspeed trip; 4032 rpm 13. Operator trip •

Pushbutton

•

Trip handle

14. Generator and transformer relay operation.

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Typical Turbine System and Description The following does not cause an immediate turbine trip, but does result in selected turbine valve closure.

1. Early valve action - closes intercept valves in the event of a transient fault. Valves remain closed until the fault is cleared, usually only 1-2 seconds.

2. Trip anticipator - Closes the main and reheat stop valves at turbine speed of from 108 percent to 112 percent depending on Unit load. The valves reopen when the turbine speed has decreased below 102 percent. If the turbine speed does not decrease to 102 percent within 10 seconds, the turbine is tripped.

3. Power load unbalance relay operation closes control valves on a power load unbalance greater than 40 percent. Refer to Electro Hydraulic Control System, PGS-2 for an early valve actuation, trip anticipator, and power load unbalance.

3.3.4

Auxiliary Steam Seal System

To maintain condenser vacuum, or to pull vacuum, steam for the seals can be provided through the auxiliary steam seal regulator. Pegging steam is taken from other units and reduced to four (4) psi by the auxiliary steam seal regulator. This steam then discharges into the steam seal header. The main steam seal regulator would be closed. This arrangement can only be used on a "Hot Turbine" where the first stage shell temperature is greater than 300 degrees Fahrenheit.

3.3

System Shutdown

The turbine can be tripped from any load that is compatible with plant and system requirements. It is desirable, however, to reduce load gradually to a low load before tripping, except in an emergency.

Establish a shutdown load based on plant and system requirements, and on the desired degree of turbine cooling, if possible as per procedures.

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Typical Turbine System and Description Reduce load to the shutdown load by operation of the load set DECREASE control with the turbine in MANUAL, until 20 MW is reached. The shutdown load should be approached gradually, utilizing the 150 degrees Fahrenheit temperature ramp rates.

Start the motor suction oil pump and the turning gear oil pump.

Trip the turbine (which opens the generator breakers) and verify that the turbine stop valves, control valves and combined reheat intercept valves close.

Verify that the turbine speed is decreasing.

Monitor the bearing metal temperatures as the turbine coasts down. A sudden spike in the temperature is an indication of a wiped bearing.

When the turbine comes to rest, verify that the turning gear motor automatically starts and that the turning gear engages and stop the motor suction oil pump.

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Typical Turbine System and Description

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