2. turbine manual

Ban chuan bi san xuat

Version (a) 15 September 2010

Mr : Le Duy Hanh

Power Plant General Series Course

Volume 2

Turbine Manual

TechComm Simulation Pty Ltd

Turbine manual Version (a) 15 September, 2010` of 190


Table of contents

1. INTRODUCTION............................................................................................ 5

2. LEARNING OUTCOMES ............................................................................... 6

3. DISCLAIMER ................................................................................................. 6

4. ASSESSMENT: EVALUATION, RECORDING AND REPORTING .............. 7

5. HISTORY OF THE STEAM TURBINE ........................................................... 8

5.1 Early applications .................................................................................................. 8

5.2 Benefits of steam turbines .................................................................................... 8

6. STEAM TURBINE OPERATION ................................................................... 9

6.1 Introduction ........................................................................................................... 9

6.2 Principles of operation of a steam turbine .......................................................... 9

6.3 Classification of turbines .................................................................................... 10 6.3.1 Type of flow ................................................................................................................10 6.3.2 Cylinder arrangement .................................................................................................12 6.3.3 Trainee exercise: ........................................................................................................18

6.4 Types of blading .................................................................................................. 19 6.4.1 Impulse ......................................................................................................................19 6.4.2 Reaction .....................................................................................................................26 6.4.3 Trainee exercise: ........................................................................................................29

6.5 Turbine Nozzle Plates or Diaphragms ................................................................ 31 6.5.1 Nozzle Plate ...............................................................................................................31 6.5.2 Trainee exercise .........................................................................................................35

6.6 Basic steam cycle................................................................................................ 36 6.6.1 Trainee exercise: ........................................................................................................39

6.7 Turbine efficiency and wet steam ...................................................................... 40 6.7.1 Deposits on blades .....................................................................................................40 6.7.2 Steam inlet conditions.................................................................................................41 6.7.3 Steam exhaust conditions ...........................................................................................41 6.7.4 Factor affecting condenser back pressure. ..................................................................43 6.7.5 Trainee exercise .........................................................................................................44

7. COMPONENTS OF A TURBINE ................................................................. 46

7.1 Turbine cylinder(s) .............................................................................................. 47 7.1.1 Casing flanges............................................................................................................51 7.1.2 Flange warming ..........................................................................................................53 7.1.3 Trainee exercise .........................................................................................................55

7.2 Turbine rotor ........................................................................................................ 58 7.2.1 Forged steel drum rotor ..............................................................................................58 7.2.2 Solid forged rotor ........................................................................................................59


Turbine manual Version (a) October 1999 of 190


7.2.3 Disc rotor ....................................................................................................................61

7.3 Turbine blade fixing ............................................................................................ 64

7.4 Couplings ............................................................................................................. 70 7.4.1 Flexible couplings .......................................................................................................70

8. TURBINE GLAND SEALING ...................................................................... 75

8.1 Gland steam condenser ...................................................................................... 75

9. LUBRICATION SYSTEMS .......................................................................... 76

9.1 Function ............................................................................................................... 76 9.1.1 Oil Properties..............................................................................................................76 9.1.2 Causes of Oil Deterioration .........................................................................................78 9.1.3 Establishment of Oil Film ............................................................................................79

9.2 Components of a Turbine Lubricating Oil System ............................................ 81 9.2.1 Dissipation of Heat from Bearings ...............................................................................83

10. THRUST BEARING ..................................................................................... 94

11. STEAM TURBINE SPEED CONTROL ........................................................ 95

11.1 The Principles Of Governing .............................................................................. 95 11.1.1 Turbo-Generators Operating in Parallel.......................................................................99 11.1.2 The Speeder Gear of a Turbine Governor .................................................................100 11.1.3 Load Sharing Between Units Fitted with Governors Having Speeder Gears ..............101 11.1.4 Relays ......................................................................................................................103

11.2 Overspeed Control Of A Turbine ...................................................................... 105 11.2.1 Development of Speed Control Systems ...................................................................105 11.2.2 Summary of Speed Control Systems ........................................................................106 11.2.3 Speed Governor .......................................................................................................106 11.2.4 Governor Control Valves...........................................................................................106 11.2.5 Emergency Governor................................................................................................107 11.2.6 Emergency Stop Valves ...........................................................................................107 11.2.7 Bled Steam Non-Return Valves ................................................................................107 11.2.8 The Secondary Governor..........................................................................................107 11.2.9 The IP Interceptor Valves .........................................................................................108 11.2.10 The IP Emergency Stop Valves ................................................................................109 11.2.11 Bled Steam Valves ...................................................................................................109 11.2.12 Governor Control Valves...........................................................................................109 11.2.13 Throttle Control .........................................................................................................109 11.2.14 Nozzle Control ..........................................................................................................109 11.2.15 HP Emergency Stop Valves ......................................................................................110 11.2.16 Load Pay Off or Unloading Gear ...............................................................................110 11.2.17 Summary of Functions Performed by a Speed Control System .................................111

12. CONDENSER ............................................................................................ 113

12.1 Function of the Condenser ............................................................................... 113

12.2 The Condenser as a Deaerator ......................................................................... 114

12.3 Condenser Air Extraction system .................................................................... 117

12.4 Types of Air Extraction Unit.............................................................................. 117




12.5 Condenser Construction ................................................................................... 120

12.6 Condenser tube fouling and use of ball cleaning system .............................. 124

12.7 Access to Condenser ........................................................................................ 125

12.8 LP Turbine Exhaust Spray Cooling System .................................................... 126

13. CONDENSATE SYSTEM .......................................................................... 127 13.1.1 Low Pressure Regenerative Heat Exchangers ..........................................................129 13.1.2 Moisture Extractors ...................................................................................................130 13.1.3 Steam Jet Air Ejector Surface Condensers ...............................................................130

13.2 Low Pressure Feedwater Heaters .................................................................... 131 13.2.1 Deaerator .................................................................................................................131 13.2.2 Reserve feedwater Tanks (surge tank) .....................................................................132 13.2.3 Chemical Dosing and Water Quality Sampling ..........................................................132

13.3 HP Feedwater Heaters ....................................................................................... 133

14. PUMPS AND HEAT EXCHANGERS (COOLERS).................................... 134

14.1 Pumps ................................................................................................................ 134

14.2 Types of Pumps ................................................................................................. 138 14.2.1 Centrifugal Pumps. ...................................................................................................138 14.2.2 Axial and Mixed Flow Pumps ....................................................................................142 14.2.3 Positive Displacement Pumps ...................................................................................143

14.3 HEAT EXCHANGERS ........................................................................................ 145 14.3.1 The Process of Heat Transfer ...................................................................................145 14.3.2 Types of Heat Exchanger .........................................................................................147 14.3.3 Temperature Difference ............................................................................................149 14.3.4 Volume or Mass Flow ...............................................................................................149 14.3.5 Thermal Conductivity of the Heat Transfer Surfaces .................................................149 14.3.6 Heat Transfer Surface Area ......................................................................................151 14.3.7 Flow Characteristics of Fluids. ..................................................................................152

14.4 Regenerative Heat Exchangers ........................................................................ 154 14.4.1 Plate Heat Exchangers .............................................................................................156

15. MAIN COOLING WATER SYSTEMS ........................................................ 159

15.1 TYPES OF MAIN COOLING WATER SYSTEM .................................................. 159 15.1.1 Open (or Once Through) Cooling Water System .......................................................160 15.1.2 Closed Cooling Water System ..................................................................................161

15.2 Components of the System .............................................................................. 164 15.2.1 Trainee exercise: ......................................................................................................182

16. SAFE OPERATION OF A TURBINE ......................................................... 186

17. ANSWERS TO TRAINEE EXERCISES ..................................................... 187




1. Introduction

This module is designed to provide a trainee power station

operator with detailed information on the construction and operation of a generic type turbine.

NOTE: This module contains detailed information relating to a generic turbine and its ancillary equipment. Portions of this

module may reflect the type of equipment at your location but

should not be interpreted as being modelled on any particular plant.

Prior to commencing this module you may wish to obtain a copy of the module Power Plant Induction Course (coal fired

boiler) which covers „Introduction to Power Generation‟

produced by TechComm Simulation. It contains a basic overview of how a thermal (coal fired) power generating plant

is constructed and operates. It will assist you in gaining an

overview prior to specialising on individual items of plant

covered in this module.

This module comprises the second in a series of six modules

that cover the following topics:

Boiler

Turbine (covered in this module)

Generator

Electrical

Controls

External Plant




2. Learning Outcomes

The trainee after completion of this module should have

gained a detailed understanding of the component parts that go together to form an efficient steam turbine.

This course is constructed in such a fashion that the trainee and the trainer/mentor determine which parts of the course

the trainee needs to complete. It is a self-guided course in

which the trainee operates alone or in cooperation with other trainees. This course does not require attendance at formal

training sessions but does require the trainee to venture into

the plant and inspect equipment currently under study. The trainer/mentor will monitor trainee progress and provide

guidance during the program.

3. Disclaimer

While every care will be taken to ensure the accuracy and

adequacy of information, concepts, advice and instructions conveyed to participants in the Course, no responsibility or

liability is accepted by either TechComm Simulation, the

course leaders or their associates, for any errors or omissions which may arise through no fault of the parties, and which

may be attributed to errors or omissions in the information,

advice or instructions given to the parties by the Client or others. Nor is any responsibility or liability accepted for any

consequent errors, omissions or acts of the participants or

others




4. Assessment: Evaluation, Recording and Reporting

Assessment of trainee achievement of the learning outcomes

is an essential part of the training process. Regular assessments during the training will enable trainee‟s progress

to be monitored and any parts of the training where a trainee

may be having difficulty to be identified and appropriate

corrective action to be taken. Each module includes Trainee exercises that are to be completed at the end of each section

and an open book final assignment to be completed at the

end of the module.

The final assignment will assess if the trainee has progressed

to a level suitable for sitting the closed book end of module test.

If a trainee does not satisfy any of the assessment criteria, the trainee will have to be reassessed, this may require

further training.

Assessment will take into account that not only has the

trainee studied this module but also closely examined the

equipment at their location.




5. History of the steam turbine

Early steam engines were of the reciprocating type where

steam acted upon a piston contained within a cylinder. The

piston operated through a connecting rod and onto a crankshaft that was rotated to give the engines mechanical

output.

In the early twentieth century electrical generators had

reached a capacity of 5 megawatts and were driven by a

reciprocating steam engines.

As electrical generator outputs increased an alternative form

of prime mover needed to be developed as the reciprocating steam engine had reached its practical output limitations.

Although not a new idea at the time; the steam turbine had the ability to fill the requirement of larger outputs.

5.1 Early applications

The steam turbine did not have a smooth transition in taking

over from reciprocating steam engine, as early designs had

high noise levels along with difficult regulation and were

prone to frequent breakdowns.

First applications of the steam turbine were in sawmills and

woodcutting shops; with one actually being fitted to a steam locomotive.

5.2 Benefits of steam turbines

As steam turbines became more accepted; rapid development

ensued. With the use of superheated steam, turbine

performance and efficiency exceeded that of the reciprocating engine and the era of the steam turbine had commenced.




6. Steam turbine operation

6.1 Introduction

A steam turbine can be considered as a rotary heat engine constructed of a number of cylinders (each cylinder

comprises a cylinder casing that contains a rotor). Individual

rotors are supported within their respective cylinder casing by journal bearings. The cylinder casing is the stationary

component of the turbine while the rotating section of the

turbine is referred to as the rotor.

The cylinder casing contains rows of stationary or fixed

blades with rotating blades connected to the rotor. These

rotating blades are installed between the fixed blades. The stationary blades are fitted into the cylinder casing in such a

fashion as to direct or redirect the steam onto the next row of

rotating blades. The cylinder rotors are coupled together and connected to the alternator rotor. Steam governor valves

control the turbine output.

A condenser installed at the exhaust or low pressure end of

the turbine receives and condenses the steam prior to it being

pumped back to the boiler.

6.2 Principles of operation of a steam turbine

When high temperature steam passes through a steam

turbine; heat energy contained within the steam is converted into kinetic energy (energy due to motion). The steam flowing

from the high pressure to a lower pressure is then converted

into rotating mechanical energy as the high velocity steam acts on a series of rows of blades mounted on the rotor.

In a typical condensing turbine high pressure; high temperature steam is allowed to expand progressively in

stages through the various rows of blades until it is

exhausted to the condenser.

As the steam progresses through the turbine the pressure

reduces and the volume of the steam increases. To

compensate for this volume increase the blade passages of the turbine take the shape of an expanding cone; with the




largest diameter blades located at the low pressure end of the

turbine.

The amount of heat that is converted into kinetic energy by

the fixed blades (or nozzles) is dependant on the design shape

of these blades.

6.3 Classification of turbines

Turbines are classified as to the:

Type of flow (axial or radial)

Cylinder arrangement (number of cylinders; whether

single, tandem or cross-compound in design)

Type of blading (impulse or reaction)

6.3.1 Type of flow

Turbine construction is either of the radial or axial flow

design. With a radial flow turbine the steam flows outward

from the centre of the casing through stages of blading. Figure 1 shows the principle of a radial flow turbine.

Figure 1: Radial flow turbine




The radial turbine is not normally the preferred choice for

electricity generation and is usually only employed for small

output applications.

Axial flow turbines have the steam flow through the turbine

in a parallel direction to the turbine shaft. Figure 2 shows an

axial flow turbine.

Figure 2: Axial flow turbine

The axial flow type of turbine is the most preferred for

electricity generation as several cylinders can be easily

coupled together to achieve a turbine with a greater output.

In some modern turbine designs the steam flows through

part of the high pressure (HP) cylinder and then is reversed to

flow in the opposite direction through the remainder of the HP cylinder. The benefits of this arrangement are:

outer casing joint flanges and bolts experience much

lower steam conditions than with the one direction design

reduction or elimination of axial (parallel to shaft)

thrust created within the cylinder

lower steam pressure that the outer casing shaft glands have to accommodate




A simplified diagram of a reverse flow high pressure cylinder

is shown in Figure 3.

Figure 3: Reverse flow turbine cylinder

6.3.2 Cylinder arrangement

Turbines can be arranged either single cylinder or multi-stage

in design. The multi-stage can be either velocity, pressure or

velocity-pressure compounded (more about this later).

Single cylinder construction

Single cylinder turbines have only one cylinder casing

(although may be is multiple sections). Steam enters at the

high pressure section of the turbine and passes through the turbine to the low pressure end of the turbine then exhausts

to the condenser.

Figure 2 shows a single cylinder turbine with a high,

intermediate and low pressure section contained within the

one cylinder casing.

Cylinder

exhaust

High pressure

steam

inlet




Tandem construction

Dictated by practical design and manufacturers

considerations modern turbines are manufactured in

multiple sections also called cylinders. Greater output and efficiency can be achieved by coupling a number of individual

cylinders together in what is referred to as tandem (on one

axis). A tandem two cylinder turbine with a single flow high

pressure (HP) cylinder and a double flow low pressure (LP) cylinder is shown in Figure 4.

Figure 4: Tandem two cylinder turbine

You will notice that the turbine shown in Figure 4 has what

is referred to as a double flow LP cylinder. The steam enters

the centre of the double flow cylinder and then divides and

flows to opposite ends of the cylinder where it exhausts to the condenser. This type of arrangement provides sufficient cross

sectional area for the large volume of low pressure steam. If a

single flow design was employed an excessively large diameter cylinder would be required. With the double flow design the

length of the blades are significantly reduced thus simplifying

the construction while reducing the centrifugal force on the rotor. In addition the double flow arrangement balances out

axial thrust on the rotor.

In Figure 5 a tandem three cylinder turbine is shown. It has a

double flow LP cylinder with an IP cylinder arranged so that

the steam flow through it is in the opposite direction to the

HP Rotor

LP Rotor

Exhaust steam to condenser

Steam from

boiler




HP cylinder. This design also greatly reduces the axial thrust

on the rotor.

Figure 5: Tandem three cylinder turbine

Large modern turbines are required to deliver high output

and are generally constructed of four cylinders with the

Exh

au

st

ste

am

to

co

nd

en

ser

Ste

am

fro

m

bo

iler

LP

Ro

tor

HP

Ro

tor

IP R

oto

r




exhaust steam from the HP cylinder passing through a

reheater before entering the IP cylinder. This arrangement is

shown in Figure 6.

Figure 6: Four cylinder turbine with reverse flow HP cylinder and two double flow LP cylinders

Exh

au

st

ste

am

to

co

nd

en

ser

Ste

am

fro

m

bo

iler

LP

1 R

oto

r

HP

Ro

tor

IP R

oto

r

LP

2 R

oto

r

Ste

am

reh

eate

r




In some larger overseas installations that operate at 60 hertz

(frequency) the use of cross-compounding is sometimes

employed. Cross-compounding is where the HP and IP cylinders are mounted on one shaft driving one alternator

while the LP cylinders are mounted on a separate shaft

driving another alternator. This is done so as the LP cylinder

with its large diameter blading can be operated at a greatly reduced speed thus reducing the centrifugal force. This

arrangement is shown in Figure 7.

Figure 7: Tandem cross-compound turbine

Exhaust steam to condenser

Steam from

boiler Steam

reheater

LP 2 Rotor

LP 1 Rotor

Alternator No 2

1800 rpm 4 pole

60Hz

HP Rotor

IP Rotor

Alternator No 1

3600 rpm 2 pole

60Hz




The final turbine arrangement that is becoming increasingly

popular is the “Tandem four cylinder turbine with reverse

flow HP cylinder, double flow IP and twin double flow LP cylinders”. This arrangement is shown in Figure 8.

Figure 8: Tandem four cylinder turbine with reverse flow HP cylinder, double flow IP and LP cylinders

Exh

au

st

ste

am

to

co

nd

en

ser

Ste

am

fro

m

bo

iler

LP

1 R

oto

r

HP

Ro

tor

IP R

oto

r

LP

2 R

oto

r

Ste

am

re

heate

r




6.3.3 Trainee exercise:

Attempt the following Trainee exercises to gauge how you are

progressing. Your answers can then be compared with the

model answers at the end of this module.

3. What determines the amount of heat that is converted

into kinetic energy within a turbine:

.......................................................................................

2. How are turbines classified:

a) ....................................................................................

b) ....................................................................................

c) ....................................................................................

3. Why is the axial flow type turbine preferred for electricity

generation:

.......................................................................................

.......................................................................................

4. What are the advantages of reverse flow turbine cylinders:

a) ....................................................................................

....................................................................................

....................................................................................

b) ....................................................................................

....................................................................................




c) ....................................................................................

....................................................................................

5. Draw the steam flow path through the tandem three

cylinder turbine shown in Figure 9:

Figure 9: Tandem three cylinder turbine

6.4 Types of blading

The heat energy contained within the steam that passes

through a turbine must be converted into mechanical energy.

How this is achieved depends on the shape of the turbine blades. The two basic blade designs are:

impulse

reaction

6.4.1 Impulse

Impulse blades work on the principle of high pressure steam

striking or hitting against the moving blades. The principle of

a simple impulse turbine is shown in Figure 10.

Impulse blades are usually symmetrical and have an

entrance and exit angle of approximately 200. They are

generally installed in the higher pressure sections of the turbine where the specific volume of steam is low and

HP

LP IP

Condenser




requires much smaller flow areas than that at lower

pressures. The impulse blades are short and have a constant

cross section.

Figure 10: Principle of impulse turbine

In a single stage impulse turbine the steam is expanded to

the required pressure in fixed diaphragm nozzles thus

producing high velocity steam.

The expanded, accelerated steam is then directed onto the

moving blades transferring its kinetic energy to the blades.

The velocity of the steam (relative to the moving blades) as it leaves the blades should be zero; indicating that no further

energy may be transferred to the moving blades.

The characteristic features of an impulse turbine are:

all the pressure drop of the steam occurs in the fixed

nozzles

no pressure drop occurs over the moving blades, ie. there is no pressure difference between the two sides

of a row of moving blades (with this feature there is

little tendency for steam to leak past the moving blades)

Rotation

Nozzle

Rotor

Boiler

Flame

Steam

Bearings




Figure 11 shows a section of impulse type blading.

Figure 11: Section of an impulse turbine blade

A cross section of a single stage impulse turbine is illustrated

in Figure 12. The drop in pressure across the nozzles and the

velocity change across the moving blades are also shown in Figure 12.

Force

Steam

IN

Leading edge

Steam

OUT




Figure 12: Cross section of an impulse blade stage

Shaft

B N

V P

Fixed

Nozzles

Steam flows

Moving

blades

Motion

Rotor Casing

Live steam

entering

PC

VL

Exhaust steam

leaving

Section

P – pressure of steam entering turbine

V – velocity of steam entering turbine

N – nozzle (fixed blade)

B – blades (moving)

PC – condenser pressure VL – velocity of steam leaving turbine




Velocity compounding

When the velocity energy produced by one set of fixed nozzles

is unable to be efficiently converted into rotational motion by

one set of moving blades then it is common to install a series of blades as shown in Figure 13. This arrangement is known

as velocity compounding.

Figure 13: Velocity compounded impulse turbine

Shaft

VL

B Moving

B Fixed

Rotor

B Moving N

V P

Fixed

Nozzles

Steam flows

Moving

blades

Motion

Casing

Live steam

entering

PC

Exhaust steam

leaving

Motion

Section

Fixed

blades




B – blades (moving and fixed)

PC – Condenser pressure

VL – velocity of steam leaving turbine




Figure 13 shows the arrangement of a velocity compounded

impulse turbine giving a section of the blading corresponding

to a graph of pressure and velocity as the steam flows through the turbine.

As the steam flows through the fixed nozzles its pressure

drops as its velocity is increased. It then enters the first row of moving blades where the kinetic energy of the steam is

transferred to the moving blades forcing them to rotate. The

steam pressure remains the same but the velocity decreases as it travels across the blades. The steam then enters the

intermediate fixed blades which are installed in the cylinder

between each row of moving blades. These fixed blades have no pressure or velocity drop across them as they only change

the steam direction towards the next row of moving blades.

The process continues through the remaining sets of moving and fixed blades until the steam exhausts the turbine.

Pressure compounding

With pressure compounding the total steam pressure to

exhaust pressure is broken into several pressure drops through a series of sets of nozzles and blades. Each set of one

row of nozzles and one row of moving blades is referred to as

a stage.

Figure 14 shows a two stage pressure compounded impulse

turbine. The steam passes through the first set of nozzles where it looses pressure as it gains velocity. It then passes

across the first row of moving blades where the steam velocity

is reduced while imparting rotational force. The steam then enters the second row of fixed nozzles where it once again

loses pressure as its velocity is increased. It then passes

across the second row of moving blades where the steam

velocity is reduced while imparting additional rotational force. The second row of nozzles (and any subsequent rows of

nozzles) are installed on a diaphragm. This diaphragm

minimises any steam leakage occurring around the nozzles due to the high pressure drop across the nozzles.

When designing a steam turbine the actual number of stages installed will depend on the total energy available and desired

blade speed.

Pressure staging is also known as RATEAU staging.




Figure 14: Two stage pressure impulse turbine

Shaft gland

Fixed

nozzle

Shaft

VL

B Moving N

Rotor

B Moving N

V P

Fixed

Nozzles

Steam flows

Moving

blades

Motion

Casing

Live steam

entering

PC

Exhaust steam leaving

Motion

Section




B – blades (moving and fixed)

PC – Condenser pressure

VL – velocity of steam leaving turbine

Diaphragm




Combination of pressure and velocity compounding

Most modern turbines have a combination of pressure and

velocity compounding. This type of arrangement provides a

smaller, shorter and cheaper turbine; but has a slight efficiency trade off. Turbines using this arrangement are often

referred to as CURTIS turbines after the inventor. Individual

pressure stages (each with two or more velocity stages) are

sometimes called CURTIS stages.

6.4.2 Reaction

The principle of a pure reaction turbine is that all the energy contained within the steam is converted to mechanical energy

by reaction of the jet of steam as it expands through the

blades of the rotor. A simple reaction turbine is shown in Figure 15. The rotor is forced to rotate as the expanding

steam exhausts the rotor arm nozzles.

Figure 15: Principle of reaction turbine

Rotor

Boiler

Flame

Nozzle

Rotation




A section of reaction type blading is shown in Figure 16 while

Figure 17 shows a turbine section with pressure and velocity

relationship.

Figure 16: Section of reaction turbine blading

In practice it is impossible to achieve a pure reaction effect as

the steam already has velocity when it reaches the moving

blades. Therefore the steam on passing across the moving blades imparts some impulse to the blades due to its change

in direction. The force developed by impulse compared with

the force developed by reaction will depend on the blade

speed/steam speed ratio.

In a reaction turbine the steam expands when passing across

the fixed blades and incurs a pressure drop and an increase in velocity. When passing across the moving blades the steam

incurs both a pressure drop and a decrease in velocity.

Steam

IN

Force

Leading

edge

Steam

OUT




Figure 17: Turbine section showing pressure and velocity relationship.

Section

Shaft

B N

V P

Fixed

Nozzles

Steam flows

Moving blades

Rotor Casing

Live steam

entering

PC

VL

Exhaust steam leaving



N – nozzle (fixed)

B – blades (moving)

PC – Condenser pressure VL – velocity of steam leaving turbine

Motion








1. What is the operating principle of an impulse turbine

blade:

.......................................................................................

.......................................................................................

2. Impulse blades are usually installed in which section of a

steam turbine:

.......................................................................................

3. Shown below in Figure 18 is an incomplete diagram of the

pressure and velocity curves for a reaction turbine stage.

Complete the diagram showing steam velocity:

Figure 18: Reaction turbine stage

B N

V P

Steam flows

PC

VL

Motion




4. What are the characteristic features of an impulse turbine:

a) .....................................................................................

b) .....................................................................................




6.5 Turbine Nozzle Plates or Diaphragms

6.5.1 Nozzle Plate

Nozzle plates are installed as the first row of fixed blades or

nozzles. A nozzle plate is constructed of three major components:

Nozzle segments

Centre ring(s) or diaphragm

Baffle strip gland (not required on double flow turbines)

A diagram of a nozzle plate is shown in Figure 19.

Nozzle segments

Nozzle segments are shaped and positioned in the nozzle plate to direct steam onto the rotating blades at the most

effective angle to gain maximum efficiency from the steam.


Centre rings support the nozzle segments and are located in

groves machined into the cylinder casing. In most large

turbines the nozzle plates are in two halves. The top half of the nozzle plate is installed into the top half of the turbine

cylinder casing while the bottom half is installed in the

bottom half of the turbine cylinder casing. This arrangement allows for easy dismantling should maintenance be required.

Baffle strip gland

These are installed to prevent steam from bypassing the

rotating blades by passing around the outer tip of the rotating blades. A diagram of a double flow turbine nozzle

plate showing a baffle strip is displayed in Figure 19.




Figure 19: Nozzle plate for double flow IP cylinder




Diaphragms

The function of a diaphragm is to contain the nozzle

segments and prevent pressure leakage along the rotor shaft

to the next lower pressure stage within the cylinder. A diagram of a diaphragm is shown Figure 20.

A diaphragm is constructed of three major components:

Nozzle segments


Baffle strips

Nozzle segments

Nozzle segments are shaped and positioned in the diaphragm so to direct or redirect the steam onto the rotating blades at

the most effective angle to gain maximum efficiency from the

steam.


Centre rings support the nozzle segments and are located in

groves machined into the cylinder casing. In most large turbines the diaphragms are in two halves. The top half of the

diaphragm is installed into the top turbine cylinder casing

while the bottom half is installed in the bottom half of the

turbine cylinder casing. This arrangement allows for easy dismantling should maintenance be required.

Baffle strip gland

Baffle strip glands in this instance prevent steam pressure leakage along the rotor shaft to the next lower pressure stage

within the cylinder. The baffle strip gland can be seen in

Figure 20.




Figure 20: IP cylinder diaphragm with baffle strips




6.5.2 Trainee exercise

Attempt the following trainee exercises to gauge how you are



1. Why are nozzle plates manufactured in two halves:

.......................................................................................

.......................................................................................

2. What are the three major components of a turbine

diaphragm:

a) ....................................................................................

b) ....................................................................................

c) ....................................................................................

3. What part of a diaphragm is inserted into the machined groove of the turbine casing:

.......................................................................................




6.6 Basic steam cycle

To gain an understanding of how a turbine functions we

must first understand where a turbine fits into the basic steam cycle.

Lets us first start with the simplified diagram of a basic steam cycle shown in Figure 21.

We will start our journey at the bottom of the condenser which is known as the condenser hotwell. At this point the water is in liquid form and is termed condensate. The

condensate is drawn from the condenser hotwell by the

condensate extraction pump. It is then pumped through the non-contact low pressure (LP) heater/s. Travelling through

the low pressure heater/s the condensate is heated. It then

passes to the deaerator (DA) for further heating and oxygen

removal.

The deaerator is a multi function device in that it acts as a

contact type low pressure heater, oxygen remover and a storage vessel allowing for system fluctuations.

Once the condensate exits the DA it enters the feedwater pump. The feedwater pump boosts the pressure to that greater than boiler pressure and therefore forces what is now

known as feedwater through the high pressure (HP) heater/s

and into the boiler. The feedwater gains further heating in the HP heater/s but is still in a liquid form when it enters the

boiler.

As the feedwater travels through the boiler it becomes high

pressure, high temperature steam known as superheated steam. The superheated steam is now in a gaseous state.

Superheated steam exiting the boiler is piped to the control valve/s (or throttle valve/s). The control valves regulate

admission of steam to the turbine depending upon load. Once

the superheated steam enters the turbine it expands and gives up heat causing the turbine rotor to rotate.

Once the superheated steam has exhausted its energy it exits the turbine and enters the condenser. The condenser has




circulating water passing through tubes installed in the

condenser. As the exhaust steam comes in contact with these

circulating water tubes it is cooled and changes from a gaseous state back to a liquid. It then gravitating to the

bottom of the condenser and collects in the condenser hotwell

ready for pumping once again around the water/steam cycle.

For efficiency reasons bled steam (or extraction steam) is

drawn off from the turbine at various stages. This bled steam

containing heat is piped to the various low and high pressure heaters and is used to preheat the condensate/feedwater.

Upon entering the LP or HP heaters the bled steam releases

its heat energy preheating the condensate/feedwater. In

giving up this heat it changes from gaseous to liquid form. This liquid form is known as drainate and passes to the

condenser for reuniting with the condensate.




Figure 21: Basic steam cycle

Condensate Extraction

Pump

Feedwater Pump

Condenser

Generator

Inlet

Canals

Outlet

Turbine

Stack

Boiler

Precipitator

or fabric filter

Fuel

Air

HP Heater

Circulating

Water Pump

LP Heater

Deaerator

Control valve





Attempt the following trainee exercises to gauge how you are

progressing. Your answers can then be compared with the model answers at the end of this module.

1. Starting at the condenser hotwell explain the passage of water and steam around the basic water/steam cycle:

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................




6.7 Turbine efficiency and wet steam

As with any machine it is important to operate in the most

efficient manner. To achieve this with a steam turbine we must extract the maximum possible energy from the steam as

it passes through the turbine.

The factors that affect turbine efficiency are:

Steam inlet conditions

Steam exhaust conditions

Type and stages of feed heating

Turbine efficiency losses due to:

Inaccuracy in blade profile or worn parts

Deposits on blades

Clearances between fixed rows of blades and/or nozzles and the moving rows of blades or nozzles

Radiation of heat from the casing

Bearing and gland friction

Steam leakage at valve glands, turbine glands and joints

A number of the above factors are design features and are out of the control of operating staff. There are however a few that

affect turbine efficiency that are under the control of

operating staff:

Deposits on blades

Steam inlet conditions

Steam exhaust conditions

6.7.1 Deposits on blades

If we have contaminants dissolved in our boiler water this will

tend to carryover from the boiler with the steam and deposit

on the turbine blading. The principle element that deposits

on turbine blading is silica. This silica is brought into the boiler during filling or as make-up using contaminated water.




To prevent silica deposits occurring on the turbine blading we

must ensure that any water entering the boiler is of a pure

nature.

Silica deposits affect the efficiency of the turbine blading and

therefore all precautions must be taken to prevent their

formation.

Silica deposits can be removed from the turbine blading by

what is called washing. To achieve washing the inlet steam temperature to the turbine is reduced. In doing this the

steam quickly becomes wet steam as it passes through the

turbine. This wet steam has a tendency to wash the silica deposits from the blading. The down side to this is that

impinging upon the turbine blades takes place causing

erosion which gives us a permanent efficiency loss.

Another problem is that when silica is washed from turbine

blades it goes back into solution with the condensate and is

returned to the boiler. Once returned to the boiler it can only be removed by blowing down or it will once again redeposit

itself onto the turbine blades.

6.7.2 Steam inlet conditions

As we have just mentioned if we have lower than design

steam temperature and pressure at the turbine inlet then the

steam tends to condense prior to exiting the turbine. If this occurs we once again have wet steam and this wet steam

erodes our turbine blades. Particular attention must be made

to ensure that turbine inlet steam conditions are maintained at correct design values.

6.7.3 Steam exhaust conditions

To gain the maximum energy transfer from the steam passing through the turbine it is common practice with modern

turbines to have the condenser under a vacuum. From

studying the boiler manual you are aware that the boiling

point of water increases as pressure increases. Conversely the condensing point of steam is lowered by lowering the

pressure. A typical steam turbine exhaust temperature of 33

- 35oC is quite common in modern turbines that are operating with a condenser vacuum of 5-6kPa absolute.




By operating the condenser under a vacuum the steam

condenses at a lower temperature and therefore we are able to extract additional work from the steam. This gives us an

efficiency improvement for the turbine.

Condenser vacuum is often called condenser back pressure and may be expresses as:

kPa absolute, or

kPa gauge (reading a minus pressure below

atmospheric)

eg: 5kPa absolute = 96.7kPa gauge

where atmospheric pressure = 101.7kPa (or1 bar)

It is important to maintain condenser vacuum at design

values to prevent the turbine exhaust steam condensing within the turbine and causing an efficiency loss along with

blade erosion.

Most modern turbines are designed to operate with a small

percentage of wetness factor to improve the energy extraction

from the steam.

Wetness factor is the quantity of moisture contained within

the steam expressed as a percentage. Normal wetness factor for a modern turbine is in the vicinity of 10-15% when

operating at low loads.

When operating a turbine with a slight wetness factor it leaves the final few rows of blades in the low pressure section

of the turbine exposed to blade erosion. To minimise this

erosion on the final few rows of blades they are installed with stallite tips on the leading edge. Stallite is an extremely hard

material and resists the erosion process.




6.7.4 Factor affecting condenser back pressure.

Back pressure in a condenser can be affected by a number of

factors:

Loading on the turbine

Circulating water inlet temperature

Circulating water quantity passing through condenser

Cleanliness of condenser tube surfaces

Air entrainment in the circulating water

Air in the steam side of the condenser

Operating personnel have varying degrees of control of all of

the above factors.

Loading on turbine

The load on any turbine is usually at the discretion of system

control but as an operator you can ensure that steam inlet

conditions are at their optimum for that prescribed load.

Circulating water inlet temperature

If lake, river or ocean water is used it is normally seasonally

dictated and beyond the control of the operator. If cooling

towers are employed ensure fans are operating correctly, correct distribution of circulating water throughout cooling

tower and correct quantity of circulating water contained

within the system.

Circulating water quantity passing through condenser

Operators can ensure that trash racks are clean, no

backwash valves inadvertently left open, canal level is correct and circulating water screens are operating in a clean

condition. If cooling tower employed ensure correct quantity

of circulating water contained within the system and bebris screens are clean.




Cleanliness of condenser tube surfaces

Ensuring correct chemical dosing of circulating water to

prevent algae growth, that condensers are back washed at

regular intervals and/or condenser ball cleaning plant operating correctly.

Air entrainment in the circulating water

Ensuring a tight circulating water system by checking all

valves are fully closed to prevent air being drawn into the system. Canal level is correct so as air is not entering the

system through the suction of the pumps.

Air in the steam side of the condenser

Air leaks at valve glands, out of service plant not isolated

correctly, valve gland sealing not in service, valves open on

out of service plant. Air ejector equipment malfunctioning or not being operated correctly.

Further information about the above factors contained within this module and volume 6 covering External Plant.


Attempt the following trainee exercises to gauge how you are progressing. Your answers can then be compared with the


1. Name three factors affecting turbine efficiency that operators have control over:

a) ......................................................................................

b) ......................................................................................

c) ......................................................................................




2. What six factors influence condenser back pressure:

a) ......................................................................................

b) ......................................................................................

c) ......................................................................................

d) ......................................................................................

e) ......................................................................................

f) ......................................................................................

3. If a condenser was operating at a back pressure of 8.7kPa

absolute what would this be displayed as gauge pressure:

.........................................................................................

.........................................................................................

.........................................................................................

.........................................................................................




7. Components of a Turbine

We have up to now been talking about steam flow through a

turbine, the effects the steam has on the turbine blades and

how it forces them to rotate. It is now time to discuss the components that go together to construct a complete and

functional turbine.

As mentioned earlier most modern turbines are constructed

of multiple cylinder coupled together to achieve the desired

output. We will focus on this type of turbine construction in our explanations. Smaller turbines are constructed using

fewer cylinders but their construction philosophy is the same.

The construction of a modern turbine employs the following

components:

Turbine cylinder(s)

Turbine rotor

Turbine glands

Bearings

Lubricating oil system

Turbine thrust

Governor

Condenser

Air extraction equipment

Circulating water system

Turbine couplings

Turbine turning gear

Steam chest(s) (containing emergency and control valves)

Drains




7.1 Turbine cylinder(s)

The casings of turbine cylinders are of simple construction to

minimise any distortion due to temperature changes. They are constructed in two halves (top and bottom) along a

horizontal joint so that the cylinder is easily opened for

inspection and maintenance. With the top cylinder casing removed the rotor can also be easily withdrawn without

interfering with the alignment of the bearings.

Most turbines constructed today either have a double or

partial double casing on the high pressure (HP) and

intermediate pressure (IP) cylinders. This arrangement

subjects the outer casing joint flanges, bolts and outer casing glands to lower steam condition. This also makes it possible

for reverse flow within the cylinder and greatly reduces

fabrication thickness as pressure within the cylinder is distributed across two casings instead of one. This reduced

wall thickness also enables the cylinder to respond more

rapidly to changes in steam temperature due to the reduced thermal mass.

A cutaway diagram of a HP cylinder is shown in Figure 22. The HP cylinder is a single flow cylinder with steam entering

the inner casing, passing through the blading and then

exhausting to the outer casing before passing to the reheater.

Figure 23 shows a double flow IP cylinder. Steam enters the

centre of the cylinder where it divides into halves before

passing through blading and exhausting at each end of the cylinder.

Low pressure (LP) cylinders are manufactured of either cast iron or fabricated steel and are shaped to allow smooth

passage of steam as it leaves the last row of blades and

enters the condenser that is usually situated directly below the LP cylinder(s).

Two double flow LP cylinders are shown in Figure 24 with a

cutaway section on one of the cylinders. Steam enters each cylinder in the centre dividing into halves before passing

through blading and exhausting at each end of that cylinder.

The condenser (not shown) is installed directly below the two LP cylinders and receives the exhaust steam.




Figure 22: Cutaway of a single flow HP Cylinder




Figure 23: Cutaway of a double flow IP Cylinder




Figure 24: Cutaway of two double flow LP Cylinders




In the HP, IP and LP cylinders casings are constructed,

suitable spaces or belts to provide exit apertures for bled

steam used in the LP and HP heaters.

7.1.1 Casing flanges

One method of joining the top and bottom halves of the

cylinder casing is by using flanges with machined holes. Bolts

or studs are insertion into these machined holes to hold the top and bottom halves together. To prevent leakage from the

joint between the top flange and the bottom flange the joint

faces are accurately machined. A typical bolted flange joint is shown in Figure 25.

Figure 25: Bolted cylinder joint

Bolted turbine flanges for a HP cylinder can be seen in Figure 22 while the IP cylinder and LP cylinders may be seen in

Figure 23 and Figure 24 respectively.

The bolts or studs holding the flanges together must be

tightened to precise values to effectively maintain their

integrity once the cylinder is exposed to high temperatures.

This is achieved by using a bolt or stud with a hole drilled through the centre. A carbon heating rod is inserted into




these holes in the bolt or stud to heat the assembly during

tensioning. This can be seen in Figure 25.

Another method of joining the top and bottom cylinder

flanges is by clamps bolted radially around the outer of the

cylinder. The outer faces of the flanges are made wedge-

shaped so that the tighter the clamps are pulled the greater the pressure on the joint faces. This method of joining top

and bottom casings is shown in Figure 26.

Figure 26: Clamped cylinder joints

With this method heating rods are insertion into the clamps

during the tensioning process. The holes for these heating

rods can also be seen in Figure 26.




7.1.2 Flange warming

As the flanges on a cylinder are relatively thick with respect

to the thickness of the casing there is a tendency for the

flanges to lag behind when temperature changes occur. A cross section of a turbine cylinder showing the relationship

between the casing and flange thickness is displayed in

Figure 27.

Figure 27: Cross section of simple turbine cylinder

With casing flanges being much thicker than the casing itself

they are slower to cool than the casing and are also slower to warm when the casing is heated. When rapid temperature

changes occur the casing temperature changes much faster

than the flange temperature thus subjecting the casing to abnormal and unwanted thermal stresses. These thermal

stresses reduce the expected working life of the material.

The most critical time when the greatest thermal stress occurs is when the turbine is being returned to service and

the steam to metal temperature differences are at their

greatest.

To minimise the thermal stress occurring on the casings a

system of flange warming is employed. The flange warming system supplies a regulated flow of steam through ducts or

holes in the flanges and/or flange bolts/studs. Flange

warming through flange ducts is shown in Figure 28. With this method warming steam passes through the flange and

into the bolt/stud hole, it then passes along the bolt/stud

outer shaft transferring heat to the casing and bolt/stud. It

Thicker casing

flange

Thinner casing

Flange joint

Turbine

rotor

Flange

bolt/stud




then passes through the flange to the next bolt/stud to

continue the warming process.

Figure 28: Cross section side view of casing flanges

Another method of flange warming is shown in Figure 29. With this method a small hole is drilled at an angle through

the centre of the bolt/stud to allow steam passage from one

flange duct to the next. During assembly accurate alignment of the bolt/stud is required to ensure that the flange and

bolt/stud holes line-up.

With both methods of flange warming we regulate the flow of steam through these ducts or holes to maintain design

temperature differential limits between the casing and the

casing flanges.

In reducing the temperature differential, the expansion

differentials of the varying thickness of casing and flanges along with the rotor are kept to a minimum allowing turbine

start and run-up time to be reduced. More about this when

we discuss turbovisory equipment covered later in this module.

Flange

bolt/stud

Casing

flanges

Flange

joint Flange warming steam entering

flange Flange warming

steam exiting

flange From

auxiliary

steam

To Condenser via turbine

drains

Holes drilled

through flanges




Figure 29: Cross section side view of casing flanges with drilled bolts/studs


Attempt the following Trainee exercises to gauge how you are progressing. Your answers can then be compared with the


1. Why are most modern turbine casings constructed in two

halves:

.........................................................................................

.........................................................................................

.........................................................................................

.........................................................................................

Flange

bolt/stud

Casing

flanges

Flange

joint Flange warming steam entering

flange Flange warming

steam exiting

flange From

auxiliary

steam

To Condenser via turbine

drains

Holes drilled through flanges

Holes drilled through bolt/stud




2. What is the advantage of constructing a turbine cylinder

with a double casing:

.........................................................................................

.........................................................................................

.........................................................................................

.........................................................................................

3. What are two methods of joining the top and bottom

cylinder casings together:

a) ......................................................................................

b) ......................................................................................

4. What procedure is employed to ensure correct tensioning

of turbine casing flange bolts or studs:

.........................................................................................

.........................................................................................

.........................................................................................

.........................................................................................




5. Why are turbine casing flanges slower to heat than the

casing itself:

.........................................................................................

.........................................................................................

.........................................................................................

.........................................................................................

6. How is the thermal stress of a turbine casing and casing

flanges kept within limits during turbine run-up:

.........................................................................................

.........................................................................................




7.2 Turbine rotor

As the name suggests the turbine rotor is the component of a

turbine that rotates. Most modern turbines operate at either 1800rpm when driving a 60Hz 4 pole generator, 3000rpm

when driving a 50Hz 2 pole generator or 3600rpm when

driving a 60Hz 2 pole generator.

Special attention must be given to the construction of a

turbine rotor due to the centrifugal force generated by the high speed operation.

Turbine rotors are constructed by the following methods:

Forged steel drum rotor

Solid forged rotor

Disc rotor

Shrunk and/or keyed to the shaft

Welded construction

7.2.1 Forged steel drum rotor

Drum rotors as they are commonly referred to are a single

steel forging for the high pressure steam inlet end rotor (drum) with another separate forging for the exhaust end

disc. After machining the drum is shrunk onto the exhaust

end disc forging and secured by bolts and driven dowels.

Grooves are machined in the body of the drum to accommodate the blading. A diagram of a drum rotor

construction can be seen in Figure 30

The drum type rotor has limitations in its application due to

the excessive stresses encountered if manufactured in large

sizes. For this reason its applications are limited to small machines or the high pressure cylinder of multiple cylinder

machines.

The main advantage of this type of construction is that there

is approximately the same mass of metal contained within

the rotor as in the cylinder casing. With their mass being

almost equal the same response to a change in temperature conditions occurs for both the rotor and the casing. By

having similar response characteristics the internal working




clearances can be kept to a minimum thus improving

efficiency.

Figure 30: Forged steel drum rotor construction

7.2.2 Solid forged rotor

Solid forged rotors have wheels and a shaft machined from

one single solid steel forging. This type of construction is

extremely rigid and eliminates the problems of looses wheels

that other types of construction can experience. Groves are machined into the wheel rims to accommodate the necessary

blading. A diagram of a solid forged turbine rotor is shown in

Figure 31.

Solid forged rotors of creep resistant alloy steel are

predominately used in the HP and IP cylinders employing impulse type blading and the IP cylinder for reaction type

blading. The modern trend is to bore a hole through the

entire length of the shaft to permit inspection by video camera or other viewing method. This hole through the centre

Rotor

blades Driven

dowels

Exhaust end shaft

and disc Shrink

fit

HP steam

inlet end




of the shaft also relieves stresses during the heat treatment

process.

Gland rings are machined between the discs to align with the

diaphragm glands. The outer faces of the first and last discs

have machined slots which allow the attachment of balance

weights

Figure 31: Solid forged turbine rotor




7.2.3 Disc rotor

Shrunk and/or keyed to the shaft

Construction of the disc rotor type is made up using a central

shaft with separately forged discs or wheels and the hubs of

these wheels shrunk and keyed onto the central shaft. The outer rims of the wheels are suitably grooved to allow for

fixing of the blades. The central shaft is usually stepped so

that the wheels hubs can be easily threaded then pressed

and shrunk or welded into their correct position. A shrink fit disc rotor is shown in Figure 32.

Suitable clearances are provided between the hubs to allow for expansion axially along the line of the shaft.

Figure 32: Shrink fit disc rotor

The disadvantage with this type of construction is that if the rotor is subjected to a rapid temperature rise in excess of

Rotor shaft

Hole through

shaft

Wheel

Blades

Locking

ring Weights




manufacturers recommendation the wheels being much

smaller in mass than the shaft expand quicker and can

become loose on the shaft.

Disc rotor balance is achieved by adjusting the position of the

weights in a channel machined in the outer face of the first

and last disc. When the rotor is balanced the weights are locked in position in the channel by grub screws.

Welded construction

Welded rotors are assembled from a number of discs and two shaft ends. The discs are joined together by welding at the

circumference. Figure 33 shows this type of construction

prior to welding while Figure 34 shows the rotor after being welded and the blading installed.

Figure 33: Rotor showing discs before welding

Discs




Figure 34: Welded rotor construction after assembly

Blades




7.3 Turbine blade fixing

Various root fixing shapes have been developed for turbine

blading to suit both construction requirements and conditions under which turbines operate. The most popular

types of blade root fixing available are:

groove

straddle

rivet

Groove construction

The groove type of root fixing fits into a machined grove

around the circumference of the rotor wheel or disc. Some examples of typical groove type blade root designs are shown

in Figure 35 while a rotor disc with a machined groove

arrangement is shown in Figure 36.

Figure 35: Groove type root fixing

Cut-off blade

section

Blade root

Annular Fir-tree Axial Fir-tree Inverted 'T'




Figure 36: Disc periphery for annular fir-tree root blades

Blade roots are installed through the closing blade window and then slid around the circumference of the disc into their

desired position. The last blade root is installed in the closing

blade opening and secured in position by dowel(s).

Straddle construction

Straddle construction is where the blade root fits over the

machining on the outer periphery of the rotor wheel or disc.

An example of straddle fir-tree blade root construction is shown in Figure 37. while the disc peripheral machining is

shown in Figure 38.

Closing blade

window

Dowel

hole

Rotor

disc




Figure 37: Two shoulder straddle fir-tree blade root

Figure 38: Disc periphery two shoulder fir-tree root anchor

Once again with this type of construction the blade roots are installed through the closing blade window slid around the

circumference of the disc into position, then the last blade

inserted is doweled in the closing blade window location.

Dowel

hole

Closing blade

window




Rivet construction

Rivet construction is where the blade root either inserts into

a groove or straddles the disc and all blades are doweled into

position.

Peripheral blade fixing

On larger blading where the blade length is relatively long a

system of lacing wire or shroud rings are installed to give the

blading additional support and reduce vibration.

The lacing wire is installed a small distance from the outer

ends of the blades while the shoud rings are fitted to tangs on the outer edges of the blades and secured by peening the

tangs. A section of blading showing the installation of the

lacing wire is shown in Figure 39 while a section of blading showing shroud ring installation is shown in Figure 40.

Figure 39: Blading supported with lacing wire

Reaction blading

Overlap of lacing wire at start and finish

Lacing wire




Figure 40: Shroud ring installation

Often gland sealing is installed around the outer circumference of the shroud ring to minimise pressure

leakage around the outer tips of the blades. A shrouding

single baffle ring gland can be seen in Figure 41. while a

shrouding side baffle gland can be seen in

Shroud ring

Tang

Blades

Tang peened

over




Figure 41: Shrouding single baffle ring gland

Figure 42: Shrouding side baffle gland

Casing

Gland

Casing

Gland




7.4 Couplings

With multi-cylinder turbines it is necessary to have some

method of connecting individual cylinder rotors. It is also a requirement to connect the turbine to the alternator rotor. To

achieve these connections we use a device known as a

coupling. These couplings must be capable of transmitting heavy loads and in some turbines are required to

accommodate for axial expansion and contraction.

The types of couplings generally employed in power plants

are:

Flexible coupling

Solid shaft coupling

7.4.1 Flexible couplings

Where axial shaft movement is required a flexible coupling is

employed and these are either:

Sliding claw (or tooth)

Flexible connection (between the two flanges)

With both of the above flexible couplings it is necessary to

have a separate thrust bearing for each shaft to maintain the same relative position between rotor and cylinder casing.

Sliding claw (or tooth)

Sliding claw couplings consists of an inner gears or tooth coupling half. The inner half is shrunk onto its respective

shaft and secured by keys or driven pins. The outer coupling

half; machined in the reverse shape is installed onto the other shaft.

The gear or teeth coupling is positioned inside the outer coupling half where it is able to slide back and forth to allow

for expansion or contraction. A diagram of a sliding claw

coupling prior to the inner claw section being inserted into

the outer half is shown in Figure 43 while a gear tooth coupling is shown in Figure 44




Figure 43: Claw coupling

Figure 44: Gear tooth coupling

Flexible connection coupling

Flexible connections such as the bibby coupling are

constructed in two halves. Each half is shrunk onto their

respective shaft and secured with keys or driven pins. The halves are machined with groves parallel or nearly parallel to

that of the alignment of the shaft. Flexible spring steel grids

are inserted into these machined groves and held in place with an outer cover. This type of coupling is effective in

allowing axial expansion and contraction along with the

ability to tolerate minor misalignment. A bibby coupling is shown in Figure 45.

Inner

claw

Outer half of coupling

Shaft




Figure 45: Bibby coupling

The flexible couplings just mentioned are by no means the only flexible couplings available but they are the preferred

choice for high load applications.

Solid shaft coupling

When shaft movement is not required it is usual to install a

solid type coupling. Two flanges are installed onto their

respective shafts and then the two flanges are bolted together to form a solid joint as shown in Figure 46.

Often teeth are machined on the outer rim of these couplings and used as a point for barring the turbine shaft. (more

about barring the turbine later). Figure 47 shows a solid

shaft coupling with a barring gear fitted.




Figure 46: Solid shaft coupling




Figure 47: Solid shaft coupling fitted with hand barring gear




8. Turbine gland sealing

Function of the gland sealing system falls into two categories:

Seal the turbine glands under all operating conditions

Extract leak-off steam from the turbine glands

The gland sealing section of the system is constructed of an

inlet pressure regulating valve and a dump valve. Under low

load conditions gland sealing steam is supplied via the inlet regulating valve from the auxiliary header to seal the turbine

HP, IP and LP glands which are all operating under different

pressures. As the load increases the leakage back through the glands of the higher pressure areas of the turbine is

adequate to seal the lower pressure glands and the inlet

regulating valve closes. With a further increase in load the leakage from the HP glands continues to increase and

pressure increases within the gland sealing system. This

pressure needs to be dissipated or it will over pressurise the gland sealing system. To alleviate this pressure the dump

valve begins to open and regulates the gland sealing steam

system by dumping this excess pressure.

This dumped gland sealing steam and any leak off steam

from the lower pressure glands is not wasted but piped under

a slight negative pressure back to the gland steam condenser. Condensate flowing through the gland steam condenser is

heated by the condensing steam which is drained back to

condenser via the condenser flash box to join the condensate. As the extraction system is operating under a slight negative

pressure air can be drawn across the outer section of the

glands and into the system. This air becomes entrained with the extraction steam and travels to the gland steam

condenser where it is removed by the gland steam condenser

extraction fan.

8.1 Gland steam condenser

The gland steam condenser is utilised as a low pressure non contact feedwater heater with the discharge drainate flowing

to the condenser via the condenser flash box. The gland

condenser is fitted with a gland condenser extraction fan to

remove any air that accumulates in the top of the gland stream condenser after the steam air mixture is separated.




9. Lubrication Systems

9.1 Function

The function of lubrication is to interpose a film of lubricant such as grease or oil between the moving surfaces in a

bearing. Lubrication reduces friction, minimises wear,

provides cooling and excludes water and contaminants from bearing components. The protection of rotating heavy

machinery depends greatly on the effective operation and

supervision of lubricating oil systems and bearings.

9.1.1 Oil Properties

Oxidation Stability

Oxidation stability is the property of oil resistant to oxidation.

When oil oxidises it‟s lubricating and cooling properties

significantly reduces, placing the bearings at risk. Oxidation will take place due to the affect of heat when in the presence

of water and air. As oil oxidises it becomes darker in colour

and forms sludge which causes corrosion of the oil pipe-work and bearings. Oxidising agents or inhibitors, can be added to

the oil to reduce the oxidising affect and increase the oil life.

Demulsibility

Demulsibility is the property of the oil to separate rapidly

from water. Water contamination not only contributes to

oxidation but also leads to the oil emulsifying. When oil

emulsifies with water it appearance changes to a white milky colour and loses it‟s lubricating properties. Considerable

precautions must be taken to prevent the contamination with

water or remove the water before emulsification can occur. Water may enter an oil system through the atmosphere,

coolers, or through turbine glands.

Rust Prevention

Corrosion can occur on any metal surface in contact with the

oil. Oxidation of oil results in the formation of oil acids which

attacks the bearing and lube pipe-work metal surfaces. Generally, rust or corrosion inhibitors are added to the oil to

provide greater protect.




Viscosity

Viscosity is one of the most important properties of an oil as a

lubricant. It is the ability of the oil to flow into spaces or gaps

between rotating bearing components, without shearing or breaking down. High viscosity oil is thick oil, which does not

flow easily and is used for heavily loaded or high-speed

bearings. High viscosity oil also produces greater heat due to

the higher frictional forces generated by the oil shearing and requires greater cooling to maintain normal operating

temperatures. Low viscosity oil would be used for lightly

loaded low speed bearings or in cold climatic conditions. Care is required with low viscosity oil as lubricating properties can

be lost under high temperatures causing loss of the oil film

and metal to metal bearing contact and subsequent failure.

The viscosity of the oil is greatly influenced by the oil‟s

operating temperature. The viscosity of the oil is greatly reduced with increasing temperatures and increased when

cold. For these reasons oil temperatures are critical. Hot oil

causing low viscosity can lead to loss of lubrication, while

similarly, cold oil causing high viscosity can also lead to loss of lubrication under cold climatic conditions or when first

placing the turbine in-service. This is the reason behind oil

pre-heating systems, such as electric heaters, to maintain oil within a defined operating temperature in order to maintain

the correct oil viscosity.

Nominal Turbine Oil Operating Temperatures

Normal Operation 38 – 45 Deg Celsius

Turning Gear 25 – 35 Deg Celsius

Turning Gear Permissive 25

High Limit 48




9.1.2 Causes of Oil Deterioration

High Temperature

Oil is subject to high temperatures due to the heat developed

from the loaded bearings, internal bearing friction and in the case of steam driven turbines, heat transfer along the shaft.

The heat must be removed by oil coolers to maintain the oil

within a pre-defined range ( usually 40 – 45 degC ) in order to

maintain correct viscosity and to minimise oxidation which accelerates at high temperatures. The rate of oil deterioration

from excessive temperature is doubled for each 10 degrees

Celsius rise.

Water

Water adversely reacts with the oil to aid oxidation and cause

emulsification which breaks down the oil‟s lubricating properties. The presence of water increases the mechanical

wear of contact bearing components by displacing the

lubricant from the bearing surfaces. Additionally, and generally during out of service conditions when oil

temperatures are low the water can combine with impurities

in the oil to form sludge which can settle in the oil tank or block filters and strainers. Water is usually removed by

draining accumulated water off the oil tank or through oil

separator centrifuges.

Oxygen

Entrained air (oxygen) into the lube oil causes oxidation of

the oil and contribute to foaming of the oil. It is difficult to

eliminate or prevent totally all air from being drawn into the oil system. Air is usually drawn in along the shaft at the

bearings and via the oil tank breathers as the oil tank is

maintained under a slight vacuum to prevent oil leakage along the shaft and to remove oil potentially explosive oil

vapour's from the oil tank.

Contaminants

Foreign material can enter the lube oil system as dirt or dust

from the atmosphere, sludge from oxidation or from debris

remaining after maintenance. This matter can be highly

abrasive and when carried with the oil to the bearings can




cause unnecessary bearing wear or damage leading to

bearing failure. In-line lube oil strainers / filters and oil

centrifuges / purification units are utilised to remove entrained contaminants.

9.1.3 Establishment of Oil Film

Oil lubricated bearings rely on the physical separation of the two bearing surfaces by a thin film or wedge of oil. In order to

establish and maintain this oil film the following conditions

must be established.

1) There must be relative motion between the two bearing

surfaces to build up sufficient pressure within the oil to

prevent the film breaking down.

2) There must be an uninterrupted supply of oil available to

the bearing.

3) The bearing surfaces must not be parallel and need a narrow angle between them. This is to enable the oil to be

shaped into a thin wedge tapering off in the direction of

the motion.

Oil Film Dynamics

Refer Figure 48

1) With the shaft at rest the journal lies in the bottom of the bearing. The weight of the shaft tends to squeeze the oil

out of the bearing so that metal to metal contact occurs.

2) As the shaft commences to rotate the first action of the journal is to climb up the bearing wall until it begins to

slip and some metal to metal contact occurs.

3) As the shaft continues to increase in speed the oil is dragged around by virtue of it‟s viscosity until it forms a

thin oil wedge.

4) With the shaft now at final or rated speed the increased pumping action on the oil increases the journal internal

oil pressure. This displaces the journal from the central

position in the bearing enabling an ideal oil wedge to be

created.




1) Shaft at rest 2) Shaft as rotation commences

Oil

Line of Contact Line of Contact

3) Increasing shaft speed 4 ) Shaft at full speed

Minimum oil film

Minimum oil film ( oil wedge established )

(film being established )

Figure 48: Establishing oil film




9.2 Components of a Turbine Lubricating Oil System

Refer Figure 49

Main Oil Tank

Oil Purification / Centrifuge Systems

Oil Pumps

Oil Coolers

Strainers / Filters

Instrumentation

Jacking Oil Pumps

Hydraulic Accumulator




Bearings Lube Oil Header Pressure Switches

Sight Glasses Seal Oil Power Oil

Temp Tx Temp Transmitters

Lube Oil Coolers

CW IN

CW OUT

Accumulator Oil Filters

DP Alarm

Change Over V/v

Vapour Extraction Fans

Jacking Oil DC Emergency AC Oil Pump Shaft Driven Oil

Oil Pump Pump

AC DC

Oil

Centrifuge Leve

Drain Heater Main Oil Tank Level

Alarm

Figure 49: Typical turbine lubrication system




9.2.1 Dissipation of Heat from Bearings

Friction is the primary cause of heat generated in a bearing. The oil is continuously undergoing shearing action which results in the

dissipation of heat within the oil. In addition to friction, heat is also

delivered to the bearing by conduction along the shaft on steam

turbines, ID Fans and any auxiliary operating at elevated temperatures. In these cases oil not only acts as a lubricant but also

as a coolant to extract the heat and maintain bearing temperatures

below trip or damage values. On steam turbine for instance the oil flow is ten times greater than necessary for normal lubrication.

In order to remove this heat oil coolers are usually provided to maintain the oil at safe working levels ( approx 40 Deg C ). Several

combination of water cooled oil coolers can be used for this purpose,

with either two by 100 % duty coolers or three by 50 % coolers for redundancy. Oil temperature exiting bearings is usually in the range

of 60 – 70 Deg C and oil temperatures exit coolers in the range of 38 –

45 Deg C.

The oil temperature can be controlled by either automatically

regulating the flow of Cooling Water supplied to the in service coolers

or by a thermostatically controlled oil regulating valve which by-passes hot oil around the coolers.

Operation

Whether the turbine is in service or on turning gear, extreme care

must be taken when placing coolers in-service to ensure the supply of

lubricating oil is NOT interrupted. Out of service coolers must be fully primed and vented on the oil side to remove any entrapped air in the

cooler ( particularly after maintenance ) and pressurised to full

working pressure before the cooler outlet valve is opened. This is to not only prevent a interruption to flow but also avoid pressure

disturbances which can equally cause a turbine trip or bearing

damage. Similarly, the Cooling Water side of the heat exchanger must

also be primed to prevent air locking when placing in-service. Out of service coolers, when not isolated for maintenance, are kept in stand-

by mode in preparation for a quick return to service if needed. In this

mode both Oil and CW inlet valves remain open with outlet valves closed. The coolers are fully primed and at working pressure.




Figure 50: Oil cooler arrangement

A CB

CW in

Oil Out

Oil in

CW Out

Three by 50 % Oil Cooler Arrangement with thermostatically controlled by-pass

A CB

CW in

Oil Out

Oil in

CW Out

Three by 50 % Oil Cooler Arrangement with auto controlled CW Regulating Valve




Oil Purification Units

Once oil is allowed to settle over a period of time water and solid contaminants will eventually settle at the bottom of the oil tank. This

forms a layer of sludge and water below the oil, which can be

manually drained off once detected. Main Oil Tank sight glasses with

manual drain cocks or valves are usually provided for manual level monitoring and detection of water. A separate sludge compartment or

settling section is sometimes provided to separate the contaminated

oil from healthy working oil. Gravity separation alone is not an effective means of oil purification as it cannot remove all impurities.

For this reason additional oil purification systems are usually

employed to clean on line the main turbine lubricating oil.

Oil Centrifuge : Figure 51

An oil centrifuge operates on the principle of centrifugal forces acting

on the different densities of oil and water / impurities. In much the same way as impurities separate out naturally by the force of gravity.

A centrifuge imparts rotating centrifugal forces to speed up the

separation process. Water and impurities, because of their higher

densities compared to oil will separate or be thrown out from the oil in the centrifuge.

Operation

Centrifuges may operate on a continuous “on line“ basis or intermittently “as necessary”. Centrifuges usually consist of a motor

driven high-speed bowl, a heater to elevate oil temperatures, and a

small pump, which draws from the main oil tank. Contaminated oil is admitted to the centre of a rapidly rotating bowl where the denser

impurities and water are thrown out to the outside of the bowl

section. Firstly, sludge or the heavy contaminants are thrown out and then the water forms a layer over the solid sludge/contaminants

waste. The purified oil settles out in the centre of the spinning bowl,

which is directed back to the main oil tank. The water and clean oil

are separated using a disc known as a gravity or dam ring and then discharged to separate outlets. Clean oil is discharged back to the

main oil tank, whilst the water is discharged to waste. The heavy

impurities must be periodically removed and will be either flushed out automatically or cleaned manually through scheduled routine

maintenance. When first starting the centrifuge it is necessary to

prime the bowl with water. The water is necessary to establish a seal between the dam ring and the oil level. Without this, oil will be

thrown out of the water discharge to waste, until a water seal

interface has been established. Care must be taken as it is possible for the oil centrifuge to attempt to pump out the main oil tank

through the waste water discharge. Additionally centrifuges from time

to time need to be topped up with water to make up for loss of water during operation. The discharge of the waste is usually directed to a




small containment tank which is level alarm protected to monitor

excessive waste or abnormal flows.

Figure 51: Oil Centrifuge




Lube Oil Filters and Strainers

Filters and strainers are installed in main turbine lube oil systems

and large auxiliary drive oil systems to provide on line oil filtration by

removing solid contaminants and impurities. The filters or strainers

are usually always duplicated to provide redundancy when the duty strainer is required out of service for cleaning or maintenance, in

order to prevent down time. The filter material is usually a fine wire

mesh or for smaller systems absorbent filters. Differential pressure gauges providing local DP measurement and remote alarming are

usually provided as indication of the filters cleanliness. By-pass relief

valves acting on high pressure by-pass oil around blocked filters in order to prevent the an interruption to the flow of oil.

A common filter type is an auto-clean strainer. Figure 52. This strainer consists of stack of metal discs or strainer plates separated

by thin spacers, which provides a gap between adjacent discs. The

gap distance determines the fineness of filtration as solid impurities

become lodged and stuck in the gaps between the strainer plates. The advantage of auto clean strainers is that the strainer can be cleaned

in-service without the need down time. By rotating an externally

mounted handle connected to the strainer plates accumulated solids are scrapped off by scraper plates and collect in the bottom of the

filter casing. Periodically the filter casing will need to be removed to

clean out accumulated sludge and contaminants.




Figure 52 : Oil Filter

Oil Pumps

There are many possible combinations of lubricating oil pumps for turbines. Typically a turbine will have it‟s oil supply met by a shaft

driven oil pump, one or possibly two AC oil pumps and a DC

Emergency Oil pump. The pumps are normally high volume low head

centrifugal pumps arranged as per diagram 2. In addition to supplying normal lubrication needs for start-up, running and shut-

downs the oil system may also supply the oil requirements for the

Power and Governor oil systems ( stop and throttle valves ), Seal oil system ( hydrogen sealing system ) and Jacking Oil ( for lifting /

floating the turbine shaft prior to turning gear being placed in-service.

Shaft driven oil pumps do not start delivering sufficient oil until the turbine speed is above 2200 – 2500 rpm. Thus AC bearing oil pumps

are required during start-up or shut-down ( provided AC is available )

to supply turbine lubricating oil until the turbine is close to rated speed. Additionally should the shaft driven oil pump fail ( low

pressure ) the duty AC bearing oil pump will automatically start.

Should the AC bearing oil pump fail or should the pressure continue

falling the DC Emergency oil pump will automatically start.




Typical Oil Pressure Settings

Normal Lube Oil Pressure 2.5 – 3.0 Bar

AC Bearing Oil Pump ( auto start pressure ) 2.3 – 2.5 Bar

DC Bearing Oil Pump ( auto start pressure ) 2.0 – 2.2 Bar

Jacking Oil 150 – 170 Bar

Power Oil 10 – 12 Bar

Low Lube Oil Pressure Alarm 2.0 Bar

Low Lube Oil Pressure Trip 1.5 Bar

Greasing Systems

Not all bearings are lubricated using oil. Small motor or fan or gear rings

can also be lubricated using grease. Greases are solid or semi-solid lubricants at normal ambient temperatures and can be divided into three

broad categories.

a) Soda Base ( sodium carbonate )

b) Lime Base ( calcium carbonate )

c) Lithium Base ( alkali metal )

Soda Based Grease

Soda based grease is suitable for high temperature operation for non-

friction high-speed bearings. ( typically, ball and roller type bearings )

Lime Base Grease

Lime base grease is suitable for low temperature operation only. As it is in-soluble in water it is suitable for bearings exposed to the weather.

Lithium Based Grease

Lithium base grease is suitable for the majority of Power Station auxiliary applications. It is resistant to high temperatures and where moisture may

be experienced.




Grease Additives

Special additives can be added to grease to improve their ability to resist

rust, oxidation and adhesiveness. Each grease type has a specific application and it is important that the correct grease is applied.




Figure 53: Manual grease system

Nipple Types

Grease gun

Grease gun




Grease Lubrication Systems

Generally grease are typically applied by two systems. Most common is the

application of grease using grease gun and secondly grease pumps.

Grease Gun (Figure 53)

A grease gun is used to apply grease to individual points or nipples at

various items of the plant such as bearing or valves. This needs to be

applied routinely as per maintenance or operation schedules. Co-ordination is recommended when applying grease or purging grease lines to bearing.

As the density of the new grease is higher, compared to the old grease, a

rise in temperatures will at first occur immediately following the application of the new grease. Caution will be required as the bearing temperature

could actually rise to recommended or automatic trip values.

Grease Pumps (Figure 54)

Grease pumps are used when the grease requirements are high or

automatic lubrication, for plant safety, is recommended. Automatic grease

pump systems are usually employed on the turbine sliding feet, main turbine stop and throttle valves and large ring gear and pinion of ash

crushers & PF Mills.




Figure 54: Grease pumping system




10. Thrust bearing




11. STEAM TURBINE SPEED CONTROL

11.1 The Principles Of Governing

During operation of a Turbine-Generator Unit the Load carried by the Generator may vary over time. In order to respond to

changing System Load demands the amount of steam directed

to the Turbine must be varied in proportion to each demand. The function of a governor is to provide rapid automatic

response to load variations.

Figure 55 Turbine Speed-Load Characteristic for Single Turbine with Manual Throttle Control

Consider a Turbine-Generator operating with the most basic form of manual throttle control. As Load is increased the

turbine speed will drop due to the increased electrical output

demanded for the same steam input. On sensing the decrease in speed the operator will manually increase the throttle valve

Steam to Turbine

Turbine

Condenser

Manually Operated

Throttle Valve

Turbine Load

Tu

rbin

e S

pee

d

Turbine Speed

versus Load

Characteristic

for each throttle

valve setting

Throttle valve setting manually adjusted

following each speed reduction due to Load

increase

0 Max

Generator

Variable Load




opening to increase steam flow and restore the turbine to the

correct speed Figure 55 shows a hypothetical Speed-Load

Characteristic for such a Turbine-Generator. Each time the throttle valve is adjusted the turbine settles at a new speed-load

characteristic, if left on a single setting the turbine speed would

fall as load was increased in line with that shown on the graph

(Figure 55). For every new setting of the manual throttle valve there would be a new speed load characteristic each

approximately parallel to each other.

While manual operation may be suitable for a turbine operating under steady load condition the response of an operator

controlling the turbine manually is not sensitive enough to

cater for a constantly varying load. An automatic control system is required that can both sense changes in turbine speed and

make appropriate adjustments to the steam flow to the turbine

in order to return the turbine speed to the required set point.

Figure 56 Droop Curve for a Turbine with Flyball Governor Controlled Throttle Valve

Steam to Turbine

Turbine

Condenser

Throttle Valve Position

Controlled by Governor

Turbine Load

Tu

rbin

e S

pee

d

Throttle valve automatically adjusted following each speed

reduction due to Load increase

0 Max

Generator

A

C

B

% Droop

Variable Load




A simple flyball governor is connected to the turbine through a secondary drive. As the turbine speed increases the speed of

the governor also increases proportionately. The increased speed causes the flyballs to swing out further with increased

centrifugal force and in so doing operate a mechanism to close

in on the throttle valve setting, reducing steam flow to the

turbine and reducing speed. As speed decreases the opposite effect is achieved.

In Figure 56 a simple flyball governor has replaced the operator manually controlling the turbine speed. The flyball governor will

be more responsive to speed variation and adjustments will be

made far more frequently than in the case of the operator.

Speed is regulated within a narrow band with A and B being the bounds of the upper and lower speed limit (The speed band

between A and B is shown magnified in the figure for emphasis,

however in practice the bandwidth is so small that it is usual to consider the two lines A and B as coincidental forming one line

C as shown)

The smaller the speed deadband (between A and B) and the smaller the slope of the governor speed-load characteristic, the

more sensitive the governor.

The drop in speed from no load to full load expressed as a

percentage of the desired or no load speed is referred to as the

governor “droop characteristic”.

All governors of machines, which are to operate in parallel,

should have some droop for reasons of stability and the droop should be identical if they are to share load in direct proportion

to their capacity. This ensures stability and is desirable when

two or more turbines are operating in parallel.




Figure 57 Synchronising and Loading Two Turbo-Generators in Parallel

Generator A placed on line and partially loaded to L1A

Turbine Load

Tu

rbin

e S

pee

d

0 Max

Generator B Speed-Load

Steam to Turbine

Turbine

Condenser



Generator A

Steam to Turbine

Turbine

Condenser



Generator B

Common Load

L2A L2

B

L1A L1B = 0

L3B L3A

Generator A Speed-Load




11.1.1 Turbo-Generators Operating in Parallel

Two similar Turbo-Generators (A and B) fitted with simple

flyball type governors, each with a slightly different speed-load

characteristic, are to be placed in service and operate in parallel.

Turbo- generator A is placed on the line first and partly loaded

to point L1A.

Turbo-generator B is then placed in service and synchronised

to Turbo-generator A (represented by the No Load point L1B on

Turbo-generator B Speed-Load Characteristic).

The synchronisation of B to A can only take place at this one

point. At any other loading on machine A it would be impossible to synchronise B with A.

If machine B was placed in service first, then machine A could

not be synchronised with it. Once the two machines are synchronised they must operate at

the same speed if they are to share load. Each will act either as

a generator and generate power, or a synchronous motor and absorb power. If turbine A was to run faster than turbine B

then turbine A would supply power to the system load and

power to generator B causing it to rotate at the same speed as turbine A. The division of load between the two machines can

be determined from Figure 57 Machine A Load is given as the

intervals L1A, L2A and L3A, Machine B as 0 at synchronisation, L2B

and L3B respectively. No other division of load for each speed would be possible.

The simple flyball governor has several limitations:

The Load demanded of the generators determines the point

on the speed-load curve at which the machine will operate.

The system frequency must change with load

It is not possible to add or remove a generator from service

without departing from the standard frequency

The synchronisation of further units to the system would

need to be done in an order dependent on individual speed-load characteristics




11.1.2 The Speeder Gear of a Turbine Governor

In order to maintain the system frequency constant and at the

same time allow load variation to occur, it is necessary to be

able to compensate for the loss of speed experienced with increasing load and the speed increase which accompanies

load rejection. To achieve this a device is fitted in conjunction

with the governor which effectively changes the speed-load

characteristic of the turbine in such a way that speed effectively becomes independent of load. The device is known

as the speeder gear.

Figure 58 shows a turbine flyball governor fitted with speeder gear. The flyballs move out under centrifugal force as the speed

increases against the restraining action of Spring A located

between the flyballs. An addition adjustable Spring B connects the speeder gear to the governor linkage.

It is not possible to make adjustments to the flyball spring

while the device is rotating, however, the adjustable spring B attached to the speeder gear tends to govern the movement of

the sleeve X in conjunction with spring B. With the operation of

the linkage to the governor valve the effects of spring B and spring A are additive.

The overall effect of altering the tension in spring B is the same

as altering the tension in spring A of a governor which had no speeder gear, that is, to shift the speed load characteristic to a

new position approximately parallel to the original position.




Figure 58 Flyball Governor with Speeder Gear

11.1.3 Load Sharing Between Units Fitted with Governors Having Speeder Gears

Once units are fitted with speeder gear governor control frequency and load control becomes variable and Load sharing

between generators is variable rather than tied to a single

speed-load characteristic.

In Figure 59 lines A and B represent the speed-load

characteristics of two machines (A and B) operating in parallel, with speeder gear compensated governors. Operating at initial

speed X1, the load on each machine is given by the intervals

LB1 and LA1.

Flyball Restraining Spring A

Speeder

Gear

Motor

Shaft Movement

transferred to

Throttle Valve

Control

Driven from Turbine Shaft

Clutch

Handwheel

Fixed Nut

Spring B

Moveable Sleeve X




Figure 59 Flyball Governor with Speeder Gear

The speeder gear on machine B only is operated to increase its speed to X2 the machine will adopt a new speed-load

characteristic B2. The governor setting on machine A remains

constant

Because both machines are synchronised to each other the

speed of machine A will also rise to the new value X2. In

increasing speed machine A must lose a portion of its load

Machine B now carries a higher load LB2

The addition of a speeder gear to turbines governors in a

combined system allows the load sharing between units to be controlled by the operating staff so that the load on any

particular machine can be reduced to zero in order to take the

machine out of service. By a similar arrangement it is possible for any machine to be synchronised with the rest of the

running system and hence machines can be placed in service

in any chosen order. Further, the system frequency can be controlled.

Turbine Load 0

Generator A Speed-Load Characteristic

Generator B Initial Speed-Load Characteristic

LB1

LB2

LA1

LA2

Generator B Speed-Load Characteristic after

Speeder Gear Operation

A

B2

B1

Tu

rbin

e S

pee

d

Max

X1 X2




11.1.4 Relays

In all but the smallest turbine, it is necessary to use some

means of amplifying the power of the governor in order to

maintain a small sensing and control device and yet still have the motive force to position large sized throttle valves. The

devices used as amplifiers are known as relays.

The most common type of relay uses an oil system employing a pilot valve and a power piston. There are two types of these

relays in use:

double acting

single acting

Figure 60 shows a primary relay of the double-acting type, when

A is raised by the governor, C is held stationary by the fixed

volume of oil above and below the piston and B consequently raises the pilot bobbin, the pressure forces on which are

balanced. Oil is thus drained from the bottom of the power

cylinder and the piston moves down under oil pressure. There

is no further motion of A and the pilot valve is reset to its neutral position. Since the pilot valve begins and ends in this

position the lever may be regarded simply as having its fulcrum

at B. The high pressure oil is always connected to the centre of the pilot bobbin to avoid the need for glands.

Figure 60 Double Acting Relay




Figure 61 shows a power relay for operating the turbine

governing valves of the single-acting spring return type. The

spring provides a reserve of energy, which, in the event of a failure of the oil pressure, will close the valves automatically.

Only one of the bobbins on the pilot valve is used as a valve,

the function of the other being to balance the pressure force. With this type, the pilot valve is always slightly open since the

pressure under the piston has to be maintained in spite of

leakage.

Figure 61 Single Acting Relay




11.2 Overspeed Control Of A Turbine

11.2.1 Development of Speed Control Systems

For typical turbine generators up to approximately 50

to 60 MW capacity, adequate speed control is obtained by exercising control over the admission of

the high pressure steam to the turbine from the

boiler. Supplementary control is provided by conventional flap or piston type non-return valves in

the bled steam lines to prevent a back feed of bled

steam into the turbine from the heaters after the HP inlet steam is shut off.

The main speed control system (excluding emergency

tripping functions) operates as a proportional controller and is sensitive to turbine speed only.

Such a system is capable of handling all normal load

variations imposed on the unit including severe transient conditions such as full load rejection

without an excessive rise in Speed.

With larger capacity units coupled with advanced

steam conditions, however, and particularly when a reheat turbine cycle is employed, a more sophisticated

control system with supplementary control functions

is required to control the speed adequately under transient loading conditions.

This situation is brought about by the increased

quantity of steam contained at any instant in the turbine, reheater and connecting pipework, which is

beyond the immediate control of the HP inlet steam

valves. As a consequence sufficient energy is available as the trapped steam continues to expand through

the turbine after the HP inlet steam has been shut off

to cause an excessive speed rise of the unit.

This potential overspeed may be counteracted by incorporating into the following into the system:

A fast response governor system, which may include an acceleration sensitive control function

(i.e. a derivative control action), to increase the rate

of closure of the HP steam valves.

Interceptor valves to control the admission of steam to the turbine IP cylinder.




An anticipatory control action in the form of a Secondary Governor, which is sensitive to loss of

load and is able to initiate action before an actual

speed rise occurs.

Forced Closed Non Return Valves in the bled steam

supply to the feedwater heaters. Forced closure

ensures the valves can be closed more rapidly than if they relied on the reversal of steam flow for their

operation (as with conventional non-return valves).

11.2.2 Summary of Speed Control Systems

For convenience the speed control systems installed on turbine

generators may be grouped according to unit capacity and

whether a "straight through" or reheat turbine cycle is employed.

For turbine generators up to 50 to 60 MW a non-reheat cycle

may be assumed and a typical speed control system will comprise:

A main speed governor

Governor control valves

An overspeed or emergency governor

Emergency (or runaway) stop valves

Non-return valves in the bled steam lines.

11.2.3 Speed Governor

The speed governor is sensitive to turbine speed only and is provided for synchronising duties to handle the normal load

variations imposed on the unit and to limit the speed rise to

below 10% above normal in the event of the most severe load rejection.

11.2.4 Governor Control Valves

These valves are under the control of the speed governor and exercise control over all HP steam admitted to the turbine.




11.2.5 Emergency Governor

The Emergency Governor is sensitive to turbine overspeed and

acts independently of the speed governor. At 10% overspeed it

will trip the emergency stop valves and in most cases cause the immediate closure of the governor control valves.

Modern units normally have facilities for routine on-load

testing of the Emergency Governor. This permits the tripping

action (but not the adjustment) of the mechanism to be tested without actually tripping the unit. The method usually

involves by-passing the trip valve and injecting high pressure

oil into the tripping mechanism so that it operates at normal synchronous speed.

11.2.6 Emergency Stop Valves

In addition to being tripped by the emergency governor the emergency stop valves may also be tripped manually or

automatically in an emergency.

11.2.7 Bled Steam Non-Return Valves

When the emergency stop valves trip the pressure within the

turbine immediately begins to decay toward that of the

condenser. The non-return valves therefore prevent steam from entering the turbine as a result of a backflow from within the

bled steam line or as a result of drainate flashing to steam as a

result of the pressure drop in the feedwater heaters. For all reheat units which normally exceed 100 MW capacity

and for many large non-reheat units a typical speed control

system will incorporate the following additional features:

A secondary governor

IP Interceptor valves and IP emergency stop valves

Forced closure of bled steam valves.

11.2.8 The Secondary Governor

The secondary governor is a fast acting governor sensitive to heavy load rejection, its purpose being to hold the speed rise

down below the setting of the emergency governor. It acts independently of speed and exercises overriding control from

the speed governor. Under normal operation the speed

governor would take approximately 0.5 seconds to close the




governor valves whereas the secondary governor takes

approximately 0.2 seconds.

On non-reheat units without interceptor valves a form of secondary governor (or overspeed limiting device) may be

arranged to initiate a momentary closure of the emergency stop

valves when a large electrical load loss is detected. After remaining closed for several seconds the emergency valves

reopen and speed control reverts to the speed governor.

Large non-reheat units around 100 MW and all reheat units

normally have a secondary governor, which acts on the governor, control valves and the IP interceptor valves. The

governor, which is initiated electrically, comprises an electrical

circuit which is triggered by a "loss of electrical load" signal. This in turn operates on the governor system to effect rapid

closure of the governor and interceptor valves.

In due course when the steam pressure in the turbine falls the secondary governor action ceases, the governor and interceptor

valves reopen and control reverts to the speed governor. The

unit is then running close to synchronous speed and is ready again to accept load.

11.2.9 The IP Interceptor Valves

These valves, which are installed at the IP cylinder inlet control the steam received direct from the HP cylinder on a

non-reheat unit or from the reheater on a reheat unit. Both of

the interceptor valves are controlled by the speed governor and both will close instantly on operation of the emergency

governor. When under the control of the speed governor the

system is arranged so that the closure of the governor valve leads by a small margin the closure of the interceptor valves

and conversely the opening of the interceptor valves precedes

the opening of the governor valves. This phasing ensures that no steam will pass into the reheater after the interceptor

valves have closed and will also allow any steam trapped in

the reheater to escape gradually before the governor valves commence to open.




11.2.10 The IP Emergency Stop Valves

The closure of these valves is initiated under the same

conditions as for the HP emergency stop valves.

11.2.11 Bled Steam Valves

The forced closure of the bled steam valves is initiated by

operation of either the secondary governor or the emergency

governor. One form of these valves is held open by compressed air against the force of a spring and is tripped by operation of a

trip valve, which releases the air pressure. Usually due to the

large water storage at saturation temperature the deaerator bled steam valve only is affected.

11.2.12 Governor Control Valves

The governor control valves may be arranged to regulate the admission of steam to the turbine by either throttle control or

nozzle control.

11.2.13 Throttle Control

With throttle control the steam is admitted around the full

periphery of the steam inlet belt of the HP cylinder. Usually two or four throttle control valves are employed which operate in

parallel.

11.2.14 Nozzle Control

Nozzle control employs a number of nozzle control valves each

of which controls the admission of steam to separate groups of

nozzles which are located in segments around the HP steam inlet belt. The nozzle control valves are opened and closed in

sequence by a series of cams and levers. The camshaft is

rotated by a servo-motor under the influence of the speed governor.

Practically all modern turbines of large capacity employ throttle control. The throttle control valves and the emergency stop

valve are located in a steam chest interconnected by a short

pipe to the turbine inlet belt. Usually two steam chests are

installed, one on either side of the turbine.




On some turbines a by-pass system is used whereby one

throttle valve takes the turbine up to an economic load (say 80% MCR) whilst the second valve opens to pass steam into a

later stage in the HP cylinder and take the turbine up to full

load. It is more usual now to make full load the economic

load and to dispense with any by-pass system.

11.2.15 HP Emergency Stop Valves

The emergency stop valves are designed primarily to be either

fully open or shut. They are held open by oil pressure against the force of a strong spring. In an emergency the oil pressure

can be released and the valve closes instantly thus shutting off

all HP steam to the turbine.

Emergency stop valves are opened manually and may be closed

manually at any desired rate provided the governor oil pressure

is established. Controlling the steam flow to the turbine during running up may be performed by slowly opening the emergency

stop valve or an integral or separate by-pass valve, which is

sometimes provided.

On large units it is usual to provide an automatic recovery

system which is arranged to automatically reset the emergency

stop valves following an overspeed trip provided no fault condition exists within the unit. By this means the unit is

prepared to accept further load more rapidly than is possible

when the emergency stop valves have to be reset manually.

11.2.16 Load Pay Off or Unloading Gear

The unloading gear is provided to reduce the load progressively

under conditions of high condenser back pressure or low steam pressure. Devices sensitive to these conditions act

automatically on the speed governor in a similar manner to the

speeder gear.




11.2.17 Summary of Functions Performed by a Speed Control System

The speed control system has the following functions to

perform:

To hold the unit at the desired speed prior to the generator being synchronised to the high voltage distribution system.

To provide a means whereby the speed of the unit can be

varied to permit the generator to be synchronised to the distribution system.

To synchronise the generator the speed of the unit must be

adjusted until the frequency of the generator voltage is equal (or very nearly equal) to the frequency of the system, this

being one of the conditions which must be satisfied before

the generator circuit breaker can be closed safely

To enable the generator load to be varied in the desired

manner from zero to maximum load after the unit is

synchronised.

When synchronised the speed of the unit is proportional to

system frequency, which normally remains practically

constant. Hence the control system must be capable of varying the load without a significant corresponding

change in speed.

To assist in maintaining automatically a practically constant

system frequency when variations occur in the electrical

load-imposed on the distribution system frequency to normal.

To limit the speed rise of the unit to an acceptable value if

the generator should suddenly lose its electrical load.

To shut off immediately the energy input to the turbine if, for any reason, the speed should rise to 10% above normal

synchronous speed.

To reduce the unit load progressively and automatically to

alleviate the effects of certain abnormal operating conditions. Such conditions include the condenser back pressure

rising above and the steam pressure falling below pre-

determined values.

To shut off immediately the energy input to the turbine at

any time should an emergency arise.




This action may be initiated manually by operating an

emergency trip switch, or it may be initiated automatically

under the following conditions:

High condenser back pressure

Low bearing oil pressure

Low bearing oil tank level

Wear or failure of turbine thrust bearing

Electrical fault in generator, generator transformer, or

elsewhere requiring the immediate shut down of the

unit

High boiler water level.




12. Condenser

12.1 Function of the Condenser

Modern Steam Driven Power Stations operate on the

Regenerative Rankine Cycle in which the working fluid

(usually high quality feedwater) is admitted as a liquid to the condenser (for deaeration before it passes through the

feedheaters and economiser), changed into a superheated

vapour (within the boiler) and returned to a liquid within the

condenser (after converting a major portion of its heat to work in the turbine). The working fluid is retained and re-

used continuously.

The primary function of the Turbine Condenser is therefore to

retain and recycle high quality feedwater by condensing the

turbine exhaust steam and providing a storage area from which the condensate can be drawn for re use in the boiler.

The design of a condenser should ensure that the total steam flow through a turbine at maximum continuous rating can be

effectively condensed. The conditions under which the

working fluid is condensed, however, have a significant

bearing on the efficiency of the cycle.

During the condensation of the steam of steam within the

condenser, the following processes occur:

The exhaust steam from the turbine is collected and

contained within an enclosed vessel (the condenser steam

space)

A cooling medium is introduced into the condenser (within the tube nest).

The transfer of heat from the steam to the cooling medium

results in the condensation of the steam.

The mass flow, the inlet and outlet temperature of the cooling medium and the temperature differential between

the inlet and outlet temperature of the cooling medium (ie

the amount of heat transferred to the cooling medium) determine the saturation temperature of the steam.

A reduced pressure is created within the condenser steam

space equal to the vapour pressures exerted by the

contents of the space.




Provided there is no air or other non-condensable gases

within the steam space the resultant vapour pressure will

be equal to that of the steam alone. (Steam as a saturated

vapour at 38 deg C has a vapour pressure of approximately 7 kPa absolute)

In the process of condensing the steam it can be seen that the condenser performs a second function: that of lowering

the back pressure within the condenser.

This decrease in backpressure has the following effects on the

steam flow through the Turbine:

increases the work available to the turbine

increases the plant efficiency

reduces the total steam flow required for a given plant

output.

The lower the cooling water temperature, the lower the back pressure, therefore it is important to maintain the cooling

water temperature at the lowest possible value within design

limits.

12.2 The Condenser as a Deaerator

It is important to remove the non-condensable gases that would other wise accumulate in the Steam/Feedwater/

Condensate system.

The noncondensables are mostly air that leaks in from the

atmosphere through components of the cycle that operate

below atmospheric pressure, such as the condenser. Other

non-condensable gases can also be generated within the Steam/Water cycle, these include:

gases released by the decomposition of water into oxygen

and hydrogen by thermal action

gases produced by chemical reaction between water and

the materials of construction.

gases generated by the decomposition of chemicals used

in the feedwater treatment protocol, which are carried over with the steam




The presence of non-condensable gases in large quantities

has the following effects on equipment operation:

They raise the total pressure of the system because the

total pressure is the sum of the partial pressures of the constituents. Thus in the condenser the pressure will be a

sum of the saturation pressure of steam, determined by its

temperature, and the partial pressure of the non-condensables. (An increase in condenser pressure lowers

plant efficiency).

They blanket the heat transfer surfaces of the condenser

tubes resulting in a decrease in heat-transfer coefficient and further reduce condenser efficiency.

The presence of some non-condensables results in various

chemical activities. Oxygen causes corrosion, most severely in the steam generator (boiler). Hydrogen, which

is capable of diffusing through some solids, causes

hydriding. Hydrogen, methane and ammonia are also

combustible.

The process of removing dissolved oxygen by reheating the

condensate or feedwater is called deaeration.

Most power stations include a regenerative deaerating

feedwater heater within the steam /feedwater cycle but whether or not a plant has such a dedicated feedwater

deaerator it is essential that the condenser, as the primary

point of feedwater makeup, carries out initial deaeration.

In order to effectively deaerate the condensate within the

condenser three basic criteria must be met:

Sufficient dwell time of the condensate within the

condenser must be available to allow the process to be

carried out effectively

The distribution of the steam and falling condensate must

allow intimate mixing of the two separate phases. The cold condensate falling from the lower condenser tubes must

have sufficient falling height to the hotwell to allow

scrubbing steam to reheat and deaerate the condensate.

An effective means of removing the air and non-

condensable gases without compromising the condenser

backpressure must be provided




Figure 62 shows a typical path for the air and non-

condensable gases.

Steam enters the top of the condenser and begins to

condense liberating non-condensable gases. The air and

gases continue to flow toward the cold end of the condenser.

A portion of the steam entering the condenser is directed

away from the tube nest to the bottom of the condenser

where it then comes in contact with the falling condensate. The condensate is reheated and releases further dissolved

oxygen, which combines with the air and gas passing through

the air cooling section before entering the vent duct leading to the air extraction equipment. Between 6 and 8% of the tubes

in the centre of the tube nest form the air cooler section,

which is partitioned from the main steam flow.

Figure 62: Schematic Diagram of Condenser Showing Air and Non-Condensable Gas Path




12.3 Condenser Air Extraction system

The functions of the Air Extraction System are to:

extract air and non-condensable gases from the condenser

prior to admission of steam to the turbine

continuously remove air and non-condensable gases from

the condenser during operation of the turbine.

Steam is not admitted to the Turbine until after the Turbine

glands have been sealed and condenser vacuum has been established. To establish condenser vacuum, the air present

in the condenser is normally evacuated in two stages.

Initially, the Hogging or Quick Start ejector (a low efficiency,

high capacity unit) is placed in service to quickly remove the bulk of the air from the condenser steam space. The Hogging

Ejector typically establishes a backpressure in the order of

20kPa absolute before the main vacuum unit is placed in service to establish and maintain an operating vacuum of

approximately 6kPa absolute. The Hogging Ejector may then

be taken out of service.

To carry out the above tasks Turbine Condensers are usually

fitted with two air extraction units each having a distinct duty:

A low efficiency, high capacity unit used to quickly

establish an initial vacuum of approximately 20 kPa (abs).

Often called any of the following:

Quick Start Ejector

Booster Ejector

Hogging Ejector

One or more higher efficiency, low capacity units capable

of establishing and maintaining a vacuum of

approximately 6 kPa absolute while ever the turbine is in

service.

12.4 Types of Air Extraction Unit.

Air Extraction Units may be either steam operated (Steam Jet Air Ejectors) or mechanical (Vacuum Pumps)




The Steam Jet Air Ejector

The Steam Jet Air Ejector consists of a venturi nozzle through

which a jet of high velocity steam is directed, creating a

vacuum at the throat, and drawing air from the condenser into the steam jet stream through ports in the wall of the

throat.

A single stage non-cooling type Steam Jet Air Ejector, consisting of a single venturi nozzle is commonly used as a

Hogging Ejector. The steam air mixture is ducted through a

silencer directly to atmosphere. As the steam is also passed directly to atmosphere this type of air ejector has poor

efficiency.

A main air ejector usually consists of two or three steam jet

ejector, mounted in series on a surface type condenser cooled

by a flow of condensate. The ejector steam and extracted air vapour mixture passes over the surface of the tubes where

the steam vapour is condensed and returned to the

condensate system while the air is cooled and vented to the

next stage of air ejection or to atmosphere in the case of the final stage. As each successive stage of air ejection discharges

into the suction of the next a lower final vacuum can be

created.

Figure 63: Single Stage Steam Jet Air Ejector

Steam In

Air In

Steam and Air Mixture Out




Figure 64: Section through Two-Stage Steam Jet Air Ejector

Vacuum Pumps

Mechanical vacuum pumps provide an alternative to the

Steam Jet Air Ejectors and have a number of advantages

including:

Independent of steam supply

quieter in operation

can be operated in automatic mode

similar operating cost to steam jet air ejectors.

Disadvantages include higher initial and ongoing

maintenance costs.




Vacuum pumps may be of the reciprocating (piston or

diaphragm) or rotary type (sliding vane, liquid ring, or

eccentric rotor). Two 50% duty pumps may be provided with both being used to for hogging duty and a single pump being

used to maintain vacuum once it is established.

From Figure 65, which shows the relative performance of steam jet and vacuum pump air ejectors it can be seen that

vacuum pumps have good hogging capacity at start up.

Figure 65: Typical Air Ejector and Vacuum Pump Performance Curves

12.5 Condenser Construction

With the circulating cooling water load as well as the

condensate storage in the hotwell the condenser carries a considerable weight. The condenser also has to withstand the

external force exerted by atmospheric pressure while ever the

condenser is operating under a negative pressure. The construction of the condenser must therefore be quite robust.

The main shell of the condenser is generally of welded

fabricated steel plate construction suitably stiffened by internal and external ribs to form a self supporting

construction capable of withstanding the external air

pressure. The shell may be mounted on support springs

Pressure in kPa Absolute

101 10 3.5 0.35 1.7 35

950

700

470

235

Volumetric Capacity in l/sec

Vacuum Pump

Hogging Ejector

Main Ejector

Start Up Range

Operating Range




between the condenser feet and the foundation plate to

prevent adverse forces being applied to the turbine or

supported from the sides. Jacking blocks may be fitted as part of the spring assembly to allow the weight of the

condenser to be rigidly supported when subjected to

condenser flood checks in which the water level is raised

considerably higher than normal operating level.

Most condensers are underslung with the turbine exhausting

downward into the condenser, however axial exhaust turbines with the condenser mounted after the final stage of

the turbine are not uncommon.

Smaller condensers tend to be cylindrical in shape to

maximise strength (the condenser being a pressure vessel)

however as size increases the shape tends toward a rectangular design in order to maximise space.

Condenser Tubes

In general, the layout of the condenser tubes is determined

by the manufacturers‟ design philosophy with emphasis on minimising pressure losses from turbine exhaust to the air

offtake and maximising heat-transfer rates.

The choice of material for condenser tubes is normally based

on the quality of the water passing through the condenser

and a compromise between high initial cost and reduced downtime due to tube failure. Lost revenue due to downtime

caused by tube leaks or other causes, particularly in larger

units, can usually justify the use of more exotic and expensive materials.

In addition to having corrosion resistance, good heat transfer characteristics and strength to withstand external steam and

water impingement, the tubes must also be designed to

withstand pressure being exerted from within the tubes

(pressures of 400-550kpa being common within closed cooling water systems and pressures of 140-200kpa within

syphon assisted open systems).

For freshwater service Admiralty Metal is regularly used while

for seawater; copper-nickel, titanium or specially formulated




stainless-steel tube materials can be used dependent on

allowable initial cost.

Condenser Tube Supports

Tube supports are provided within the condenser to prevent

excessive tube vibration, which can cause rubbing between

tubes, circumferential cracking on individual tubes and

ultimate tube failures if the tube support system is inadequate. Vibration is most likely to occur during low water

temperature operation, when the steam entering the

condenser can reach sonic velocities, causing severe flow-induced vibration.

Where provision exists to bypass steam around the Turbine directly to the condenser during start up and shut down the

condenser must be designed to accommodate the high-energy

steam without damage to condenser tubing, structural members, or the low-pressure end of the turbine. Baffles and

shrouding are often used to protect the tubes from direct

impingement of the steam and steam conditioning is carried

out by expansion and water spray drenching of the steam at the point of entry into the condenser.

Explosion Diaphragms

Condensers are normally operated at pressure at or below atmospheric and therefore are designed to resist implosion

rather than explosion. To prevent damage due to positive

internal pressure condensers are fitted with explosion diaphragms, normally designed to relieve at 35kPa above

atmospheric pressure.

The diaphragms can be of several different types including:

Water Sealed Lead Disc (designed to rupture and lift when

presure is exceeded)

Fixed Knife and Diaphragm (The diaphragm first bulges before driving itself onto the fixed knife which pierces the

membrane allowing it to rupture)

To ensure the condenser is maintained at or below atmospheric pressure the vacuum breaking valve should

remain open until the air extraction equipment is placed in

service and air extraction has begun.




Drainage to the condenser should be regulated and drains

cooling sprays should be placed in service prior to placing the

turbine in service.

Flexible Connections

A marked temperature difference can occur between the

turbine and the condenser and differences in movement due

to differential expansion between the two can occur. For small units the condenser may be supported on springs and

rigidly connected to the turbine. As size increases movement

due to temperature difference between turbine and condenser is usually accommodated by a stainless-steel bellow or

rubber belt-type expansion joint. To accommodate differential

expansion between condenser shell and tubes, a flexible diaphragm or other expansion elements can be installed.

Flexible diaphragms are also common as part of the

connection between external pipework and the condenser (Cooling Water Inlet and Outlet Conduits and Condensate

pump to hotwell connections)

Condenser Cooling Water Flow

Condensers may be of a number of different flow configurations dependent on the maximum quantity of steam

flowing through the turbine and the cooling medium flow and

temperature. Common configurations include:

Single Pass

Multiple Pass

Divided Water Box

Single pass condensers with small diameter tubes are more

suited for sites where there is no shortage of water while two

pass condensers with large diameter tubes are more suited to sites where water supply is limited.

A divided water box allows the cooling water to be directed

into parallel flow paths each of which can be independently isolated for inspection and maintenance while the turbine

and condenser remain in service.




Figure 66 shows a simplified diagram of a single pass

condenser. The flow path is simple and the design can be

used in transverse or parallel configuration.

Figure 62 shows a divided water box condenser with two

individual passes.

Figure 66: Simplified Diagram of a Single Pass Condenser

12.6 Condenser tube fouling and use of ball cleaning system

Water quality and tube cleanliness are major factors affecting turbine performance. Two common problems reducing

cooling water flow through the condenser tube nest are:

Plugging

Fouling

Plugging

Marine life and debris such as leaves and plastic sheeting

carried into the cooling water system can deposit on the face

of the inlet waterbox tube plate effectively plugging individual or sections of tubes. Effective screening of the water supply

Tube Support

Plates Tube Plate

Outlet

Water Box

Cooling Water

Inlet

Cooling Water

Outlet

Steam Inlet

Inlet Water

Box




inlet can reduce the incidence of plugging while using a

suitable system of valving to carry out backwashing or

flushing of the tube plate can remove material covering the tube plate.

Fouling

Fouling, a build up of a surface layer of various substances

on the inside of the cooling water tubes, will reduce the ability of the tubes to transfer heat effectively. Fouling can be

caused by a number of different mechanisms including:

silt

marine or freshwater crustaceans

algae and slime

products of corrosion

scaling

To regain the necessary heat transfer rate, fouled tubes must

be cleaned by forcing a plug or brush through each tube to

scour the fouling material from the tube surface. Normally this would require the condenser pass to be taken out of

service. An alternative solution is to ensure that excessive

fouling does not occur by carrying out in service cleaning on

a regular basis using a recirculating ball cleaning system. In such a system a large number of sponge rubber balls with an

abrasive coating are fed into the cooling water inlet conduit,

carried through the tubes by the water flow, collected at a specially designed strainer in the cooling water outlet conduit

and pumped by a retrieval and recirculating pump back into

the inlet conduit to be used again. Continual use of the recirculating ball cleaning system, however, will shorten tube

life and therefore the systems are generally used

intermittently.

12.7 Access to Condenser

The condenser consists of two separate sections the steam space and the water space. Each is classified as a confined

space and access to each requires specific procedures to be

adopted prior to and during entry.




12.8 LP Turbine Exhaust Spray Cooling System

During periods of low load and when coming into service

there is reduced steam flow through the LP cylinder. This reduced steam flow causes the last few rows of blading to do

work on the steam and not the other way around. Due to this

fact of imparting work on the steam the last few rows of blading can overheated and premature failure is likely. To

prevent this overheating a system of sprays have been

installed around the circumference of the LP turbine exhaust. This system of sprays is referred to as hood sprays and they

direct spray water (from the condensate extraction pump

discharge) onto and around the last few row of LP cylinder

blading keeping them within normal temperature range.

The hood spray system is fully automatic and cuts in when

the exhaust steam temperature of the LP cylinder reaches the predetermined value. The system is also fitted with a manual

bypass valve should the automatic system fail.




13. Condensate System

During normal operation of a Steam Turbine Driven Power

Plant the working fluid, high quality feedwater, is

continuously recirculated through the components of the plant.

Feedwater is fed into the steam generator (boiler) where it is converted to steam. The steam flows to the turbine where its

heat energy is converted to mechanical energy in turning the

turbine rotor. Passing through the turbine the low pressure exhaust steam is condensed in the turbine condenser and the

condensate is returned to a storage vessel to provide a supply

for the feedwater pumps to continue the cycle.

The Condensate System comprises the items of plant

primarily involved in the removal of the condensate from the condenser hotwell and transportation of the condensate to

the feedwater storage vessel. The Condensate System must

be designed to carry the condensate flow demanded by the

Steam/Water Cycle at all loads up to and including maximum continuous rating (MCR) of the Steam Generator

and Turbine.

Typical components of the Condensate System may include

any or all of the following:

Condensate extraction pumps

Condenser level control system

Minimum condensate flow control system

Low pressure regenerative heat exchangers (including

moisture extractors, steam jet air ejector surface

condensers, gland steam condensers, low pressure feedwater heaters, deaerators)

Reserve feedwater tanks

Chemical dosing injection system

Water quality sample




In addition to transporting the condensate to the feedwater

storage vessel the condensate system also provides

condensate for a number of secondary functions including any or all of the following:

Condenser flashbox spraywater

LP turbine exhaust hood sprays

Turbine bypass steam to condenser spraywater

Condensate extraction pump gland sealing

Condenser vacuum breaking valve sealing water

LP turbine gland sealing steam attemperator

Condensate Extraction Pumps.

The level of condensate in the condenser hotwell should be such that operation of the condensate system can continue

for several minutes following a reduction of steam flow to the

condenser yet must not be so high as to effect the performance of the condenser by covering condenser tubes.

The duty of a Condensate Extraction Pump is unique in that

it must draw from the Condenser Hotwell, which is under a vacuum, and discharge against system resistance to the

feedwater storage vessel.

Multi stage centrifugal pumps are most commonly used for

the task. Pump glands must be sealed to prevent air ingress

into the condensate system (seen initially as a high dissolved oxygen content in the condensate).

Condenser Level Control

Several methods may be used to control the condensate flow from the condenser including:

Condensate Extraction Pump Speed Control

Condensate Extraction Pump Flow Control

Constant flow pumps discharging either through a pressure

sustaining and flow control valve to the feedwater storage

vessel or a recirculating line to the condenser (dependent on

condenser level) provide the most common configurations.




On rising condenser level the flow control valve will open to

forward condensate to the feedwater storage vessel.

Condensate dump valves may be fitted to the condensate

system where salt contamination of the condensate through

condenser tube leakage is considered likely. Where such a

valve is fitted to the system it may be forced open by the control system to dump condensate to waste should the

condenser level rise above normal operating limits.

On falling level the flow control valve will close and the

recirculating valve will open to the condenser to maintain the

level.

Minimum Condensate Flow Control System.

A minimum flow must be maintained through the

Condensate Extraction Pump to prevent the pump from heating up to the point where condensate may evaporate

within the pump body causing cavitation. Where such

elements as moisture extractors, steam jet air ejectors and

gland steam condensers form part of the condensate system a minimum flow may also be requires through these heat

exchangers to prevent damage or system failure.

To ensure the required minimum flow is always maintained

through the pump, the recirculating valve to the condenser

remains partially open at a preset value until such time as the flow downstream of the flow control valve is greater than

the minimum flow requirement of the pump.

13.1.1 Low Pressure Regenerative Heat Exchangers

Condensate can be used to provide the coolant in a number

of heat exchangers as it passes to the feedwater storage

vessel. Where the fluid being cooled is steam from the steam/water Cycle the heat exchangers are said to be

regenerative due to the fact that heat lost by the steam is

gained by the condensate and returned to the cycle.




Typical Regenerative Heat exchangers include:

Moisture extractors,

Steam jet air ejector surface condensers,

Gland steam condensers,

Low pressure feedwater heaters,

Deaerators

13.1.2 Moisture Extractors

As steam passes through the turbine it continually gives up

heat until, as it approaches the final low pressure stages of the turbine the wetness fraction of the steam is approaching

saturation point. The final blades of the LP Turbine are the

largest of all the blading and the tip speeds of these blades are the highest of the turbine. These blades can easily be

damaged by impact with free water droplets in the steam

flow. To prevent such damage the heavier water laden steam is drawn from the periphery of the last rows of blades and led

through large bore piping to a surface tube condenser cooled

by the flow of condensate through the tubes. The drainate from the moisture extractors returns to the condenser

through a barometric leg and the heat from the condensing

steam is transferred to the condensate.

13.1.3 Steam Jet Air Ejector Surface Condensers

Multi- stage Steam Jet Air Ejectors, used as vacuum

maintaining ejectors, incorporate interstage cooling. This

usually takes the form of a shell and tube heat exchanger with condensate flowing through the tube nest. The steam,

after passing through the air ejector nozzle and entraining

the air, is condensed on the outside of the tubes and the drainate is returned to the condenser. The heat from the

condensing steam is transferred to the condensate passing

through the tubes.

Gland Steam Condensers

The outer pockets of the Turbine Labyrinth Glands are placed

under a slightly negative pressure by an exhaust fan located on the body of the gland steam condenser and exhausting to

atmosphere. The exhaust fan draws air migrating from the

outside of the turbine glands and steam migrating from the

inside of the glands into the gland steam condenser where




the steam is condensed over a shell and tube type heat

exchanger. Condensate passes through the tubes, gland

steam is condensed on the outside of the tubes and the air is exhausted to atmosphere. The heat from the condensing

gland steam is transferred to the condensate passing through

the tubes and the gland steam drainate is returned to the

condenser.

13.2 Low Pressure Feedwater Heaters

Steam is drawn off (or bled) from the steam turbine for two

reasons:

To reduce the total amount of steam flowing through the

final stages of the turbine.

To allow regenerative heat transfer to take place between

the steam and the condensate. Regenerative heat transfer

is more efficient and reduces losses to the cooling water in

the condenser.

Low Pressure Feedwater Heaters are generally surface type

shell and tube heat exchangers. The condensate flows through the tubes and the steam bled from the turbine

condensers on the outside of the tubes within the shell.

Drainate formed by the condensing steam is returned to the condenser hotwell.

13.2.1 Deaerator

A Deaerator can be described as a special purpose low pressure feedwater heater. The deaerator:

Is the last feedwater heater in the condensate system

Forms an elevated feedwater storage area thereby

providing both the net positive suction head and the water supply demanded by the boiler feedwater pumps

Deaerators in general are heat exchangers of the contact

type. Steam, either from an auxiliary steam range or bled from the turbine, is admitted to the deaerator through

distributor manifolds while the condensate is sprayed into

the deaerator shell. This allows the steam and water to be intimately mixed greatly enhancing the deaeration of the

condensate. Air is vented from the deaerator shell to

atmosphere.




Being a contact type heat exchanger virtually all the heat

from the steam is transferred to the condensate.

13.2.2 Reserve feedwater Tanks (surge tank)

Where load demand may vary considerable during the

operation of a Power Plant the Condensate System may

include a Reserve Feedwater Tank (or sometimes called a surge tank). The function of this tank is to:

Absorb excess feedwater during periods of load rejection

when feedwater demand is reduced

Supply feedwater to the condensate system when demand

is significantly increased

Excess condensate is directed to the Reserve Feedwater Tank through a radial feed from the condensate system after the

flow control valve and prior to the Low Pressure Feedwater

Heaters.

Condensate from the reserve Feedwater Tank is returned to

the Condensate System through the Condenser to allow it to be deaerated before admission to the boiler (The Reserve

feedwater Tank being open to atmosphere through the tank

vent).

13.2.3 Chemical Dosing and Water Quality Sampling

Condensate drawn from the Condenser Hotwell is sampled to

determine the water quality. Normal parameters that are

analysed include:




13.3 HP Feedwater Heaters




14. Pumps and Heat Exchangers (Coolers)

14.1 Pumps

Pumps are used to move a volume of liquid from one point to another. The reasons for moving a volume of liquid from one

point to another are quite varied and, within a Power Station,

include the following:

circulating a liquid within a heating and/or cooling circuit

(Main Cooling Water System)

adding a liquid to a pressurised circuit (e.g. chemical

dosing, supplying feedwater to a pressurised boiler)

raising a liquid from a lower to a higher elevation. (moving

condensate from the Condenser Hotwell to the Deaerator

moving a liquid from one location to another (Ash and

Dust slurry discharge)

converting input energy into mechanical work (as in an

hydraulic system)

Basically a pump operates by converting the energy supplied by the pump‟s drive unit into kinetic energy within the fluid

being pumped in order to cause it to flow from one point to

another. This can be done in a number of different ways as shall be seen later in this segment.

Resistance to Flow

In raising a liquid above the pump datum point the pump

must overcome the potential energy inherent in the column of liquid being discharged. The potential energy in the column

of liquid is the same whether the pump is operating or not.

The pressure created by this column of liquid is referred to as the pump Static Head.

In forcing a liquid to flow through a circuit the pump must over come the resistance to flow in the form of friction and

mechanical losses caused by the components of the piping

circuit (such as the pump casing, valves, piping, bends and any other obstacles). This resistance to flow is defined as the

pump Dynamic Head.




The combined static and dynamic resistance to flow within a

system can be measured as a pressure at the discharge of the

pump and is referred to as the Pump Discharge Head.

Static Head

The Static Head acting on a pump is made up of two

components:

pressure exerted by the column of liquid contained within the discharge pipework from the pump to its new

destination

pressure being exerted on the liquid from an external

source. ( e.g. Steam or vapour pressure, hydraulic pressure)

For a given system, provided the pressure head component remains constant the static head itself will remain constant,

independent of flow rate.




Figure 67: Open Pump Circuit Discharging to an Open or Closed Vessel

Within a Closed System the Suction and Discharge Static Heads are the same, the required mass flow through the

circuit will determine the amount by which the discharge

pressure is increased above static head pressure

Discharge Head

Suction Head

Pressure Head (e.g. Steam pressure in

Boiler Drum)

Pressure




Figure 68: Closed Pump Circuit Incorporating Expansion/Make Up Head Tank

Dynamic Head

Dynamic Head is dependent on the actual flow rate within a system.

Figure 69: System Resistance to Flow

Static Head

Expansion/Head Tank

Pump

Cooler/Heater

P

Dynamic

Head

Head

Static

Head

System Flow 0 100%

Total Pump Discharge

Head




14.2 Types of Pumps

There are several different types of pump but basically they

can be broken into two categories:

Rotary Non-Positive Displacement Pumps

Positive Displacement Pumps

Rotary Non-Positive Displacement Pumps may again be divided into three main types:

Centrifugal (Radial)

Mixed Flow

Axial Flow

Each of these pumps produces a continuous flow when in

operation however the discharge volume differs with the

discharge head.

14.2.1 Centrifugal Pumps.

The centrifugal pump consists of an impeller, made up of a

series of backward curved blades or vanes, rotating within a closed casing. Liquid enters the centre or eye of the impeller,

which is rotating at speed. The rotating motion tends to

accelerate the liquid towards the periphery of the impeller. The backward curved impeller vane shape and the pump

volute act to change the direction of the liquid so that it

leaves the pump impeller periphery with a radial velocity in the direction of discharge flow.

The impeller itself is made up of several segments dependent

on the number of vanes. Each segment has an increasing cross-sectional area from the pump eye to the impeller

periphery. As the liquid is accelerated toward the periphery of

the impeller it is presented with an opportunity to occupy an increasing volume within the impeller segment. The result is

that a reduced pressure in created at the eye of the impeller,

which draws more liquid into the pump. The principle of operation of a centrifugal pump can be seen in Figure 70.




Figure 70: Principle of Operation of a Centrifugal Pump

A centrifugal pump must have an initial level of liquid at the

eye of the pump (ideally to at least the centre line of the shaft) to allow it to work. It is not self priming. Normal pump

configuration would include suction and discharge valves, a

non-return valve in the discharge of the pump and/or a foot

valve in the suction, and a pump casing vent.

The pump impeller is mounted on a drive shaft connected to

the drive unit. Glands are required to be fitted where the drive shaft passes through the casing.

The pumps may be mounted either horizontally or vertically to suit the location.

Liquid enters eye of

Impeller

Velocity is reduced and pressure

increased in volute

Liquid discharges

from pump

Liquid driven from impeller at high

velocity




Centrifugal Pump Performance

To determine the performance of a pump a number of criteria

need to be examined. These criteria include:

relationship between the developed pump head and the

pump flow

relationship between the power consumed by the pump

and the pump flow

efficiency of the pump throughout its range of developed

head and flow

The Net Positive Suction Head Requirements of the Pump

The relationships between head, flow and power demand differ for each type of pump.

Figure 71 shows a typical set of curves for a centrifugal pump

when pumping water.

Figure 71: Typical Pump Characteristic Curves for a Centrifugal Pump

Head versus Flow (H-Q)

Power versus Flow

Required NPSH

Efficiency

Power

Efficiency Head

Flow 0




An analysis of the Pump Characteristic Curves in Figure 71

will reveal that:

Flow varies in inverse proportion to the pump discharge

head

Required Net Positive Suction Head increases as flow

increases and Discharge Head reduces

Input Power increases with flow but shows a variation in

the rate of increase before and after maximum efficiency has been reached.

Efficiency is not directly related to flow or head.

Determining the Operating Point of a Pump.

From the pump performance curves it can be seen that, for a

given centrifugal pump, flow will be reduced to zero, as the

head increases to a maximum.

To determine the most suitable pump for a given task the

Flow versus Head characteristics of the pump must be

matched to:

required mass flow through the system

static head within the system and

dynamic head that will be generated in the system at the

required flow.

By plotting the pump head versus flow curves against the

system head curve a point will be found at which the two

curves intersect. This point is referred to as the Operating Point and it indicates the optimum flow and discharge head

conditions for the pump.

From the Performance Curve in Figure 72 the pump is best

suited to provide a flow of approximately 7 l/s against a

discharge head of 15m.




Figure 72: Centrifugal Pump Performance Curve

14.2.2 Axial and Mixed Flow Pumps

Whereas the flow through a centrifugal pump enters axially

at the eye and departs almost radially from the impeller, the flow through mixed and axial flow pumps enters axially and

departs part axially and only part radially. The liquid being

discharged is then directed through guide vanes, which promote a greater degree of axial flow.

The design of the axial flow pump impeller is such that it

tends to lift or propel the liquid through the pump. The impeller blade pitch can be altered in some pump designs to

limit starting current and to regulate flow.

This type of pump demands maximum power and generates

maximum head against a closed discharge and is best suited

to systems demanding a high flow against a low discharge head.

Pump Performance Curve

0

5

10

15

20

25

30

35

1 2 3 4 5 6 7 8 9

Flow (l/s)

Head (m

)

Pump Curve

System Curve

Operating Point




Axial flow pumps are not self-priming and must be immersed

in the liquid to be pumped in order to perform. They do not,

as a consequence, have suction valves and due to the high head generated against a closed discharge are normally

started with an open discharge.

Figure 73 shows the Head versus Flow (H-Q) Curve and the Power Curve of a typical axial flow pump.

Figure 73: Typical Axial Flow Pump Characteristics

14.2.3 Positive Displacement Pumps

A positive displacement pump operates by forcing a set

volume of liquid to flow by first trapping it and then

displacing it by reducing its containment volume to zero. This can be done by varying the volume of containment in a

number of ways. The methods employed to vary the volume

in a reciprocating pump include:

movement of a piston within a cylinder

meshing of pairs of teeth on two engaged gear wheels

flexing of a diaphragm within a closed cylinder

In theory the flow from a positive displacement pump is

unaffected by head and the head generated by the pump is

only limited by the power input to the pump.

Head

% Flow 0

Power

100




In practice, seal leakage on the pump may prevent the full

volume of liquid being pumped with each stoke or cycle, increased head causing increased leakage and reduced flow.

Figure 74: Typical Positive Displacement Pump Characteristics

The flow from positive displacement pumps may be regulated

by:

varying the pump speed

recirculating part of the flow to the pump suction

varying the length of the pump stroke ( piston type pumps)

Positive displacement pumps are normally fitted with suction and discharge valves and a discharge relief valve situated

between the pump and the discharge valve. The suction and

discharge valves must be opened to a positive displacement pump before it is placed in service as damage to the pump

can occur.

Positive displacement pumps are generally self-priming,

provided internal clearances are small and wear is minimal.

Head versus Flow (H-Q) Curve

% Flow 0

Power Curve

100

Head/Power

Theoretical (H-Q) Curve




14.3 HEAT EXCHANGERS

14.3.1 The Process of Heat Transfer

Heat can be transferred from one object to another by means of either Conduction or Radiation. Heat can also be

dissipated throughout a fluid by Convection.

Conduction

Thermal energy is carried in a substance in the form of

kinetic energy inherent within the atoms and molecules of the

substance. The higher the velocity of the electrons within the molecules, the greater the kinetic energy and the higher the

temperature of the substance. When one substance is placed

in contact with another, thermal energy is transferred from

one to the other by the collision of molecules of one substance with molecules in the other. This form of energy

transfer is called conduction.

Metals have a more compact molecular structure than liquids

and gases and therefore there is more opportunity for metal

molecules to collide with each other. For this reason metals have greater thermal conductivity than liquids or gases.

The amount of heat transferred by conduction depends upon:

a) The surface areas of the two substances in contact (the

number of molecules that can come into contact)

b) The difference in surface temperature between the two

faces in contact (the difference in molecular velocity between the two substances)

c) The amount of time during which heat transfer can occur

(the greater the time the greater the number of collisions that can occur)

d) The thickness of the material (if you consider a piece of

material with a thick cross-section; the first row of molecules absorb the full impact of a colliding molecule from the hotter

substance. The molecules on the surface could therefore be

expected to have a temperature approached that of the heating source (depending on how often the surface

molecules are being collided with). As the molecules within

the thick piece of material collide with each other, each

subsequent row of molecules, behind the first row, absorbs a




smaller portion of the energy so that the energy is dissipated

at a constantly reducing rate through the material.

e) The type of material. (Each substance requires a different

amount of heat energy to increase the rate of vibration or the

velocity of its molecules).

The greater the area and temperature difference, the greater

the rate of heat transfer. The heat transfer is therefore

proportional to area and temperature difference.

Conversely the greater the thickness of the material the less

the heat transfer. Heat transfer is therefore inversely proportional to thickness.

As an example of heater transfer by conduction, consider the transfer of heat from steam inside a pipe to the outside. The

heat must pass through material of the pipe. The heat being

transferred through the pipe is said to be conducted through

the pipe.

Radiation.

Heat transfer by thermal radiation involves the radiation of

electromagnetic energy from one body and its absorption by another. Electromagnetic radiation exists in the form of

electric and magnetic waves each travelling at right angles to

each other. Electromagnetic waves include the whole spectrum from gamma rays with wavelengths in the

1picometre range, through visible light in the 1micrometre

range to long wave radio waves with a wavelength of 1 kilometre. Electromagnetic waves do not rely on the

existence of matter for their transmission (as sound waves

do) and can pass through a vacuum. Any object with a temperature in excess of 0oK will emit some radiation. Two

factors control the amount of heat energy radiated from a

body: the temperature of the emitting surface (the hotter the

surface the greater the emission) and whether the surface is light or dark (dark bodies emitting and absorbing a greater

amount of heat energy than light bodies).

A prime example of heat transfer by radiation can be seen in

the way in which the sun transmits heat energy through

space to the Earth.




The amount of heat transferred by conduction largely

depends upon the temperature difference between the emitting and receiving bodies rather than the actual surface

temperature of the emitting body. In case of radiation,

however the temperature level of the emitting surface largely

controls the quantity of heat transmitted. A further point, which effects the amount of energy a body will emit or absorb

by radiation, is whether the surface is light or dark. It is

found that dark bodies emit or absorb a considerable amount of radiant heat energy, while light bodies do not. This gives

rise to the definition of what is known as a “Black Body”

A black body is a perfect absorber or emitter of radiant heat

energy (has an emissivity E=1) while polished and reflective

surfaces have poor emissivity (polished copper E=0.041).

14.3.2 Types of Heat Exchanger

The exchange of heat between one substance and another is

an important process within Power Plant Cycles and a large

number of heat exchangers are used within the plant.

Heat exchangers are devices which allow a transfer of heat

between a primary medium (the fluid that is required to be heated or cooled) and a secondary medium (the fluid that is

doing the heating or cooling)

The principal types of heat exchanger are:

contact type in which the hot and cold fluids mix.

non contact type in which an intervening surface

separates the two fluids.

Contact Type Heat Exchangers

Contact Type Heat Exchangers are the most

thermodynamically efficient type of heat exchanger but can only be used when there is no problem created by the mixing

of the hot and the cold fluids. Typical contact type heat

exchangers include:

deaerators




spray water type desuperheater

cooling towers.

In the case of a deaerator, steam is mixed intimately with condensate flowing into the deaerator. The steam itself

condenses giving up its latent heat to the condensate, which

increases in temperature causing dissolved oxygen to be released. The condensed steam is simply added to the total

volume of condensate in the deaerator storage tank.

In a contact type desuperheater water is sprayed into a steam line to reduce the steam temperature. The superheated steam

gives up a portion of its heat (initially seen as a reduction in

superheat temperature) to evaporate the water and bring it up to the same final temperature as the steam as it leaves the

desuperheater. The evaporated feedwater is added to the total

volume of the steam flowing in the system.

In both of these examples heat transfer is complete as the

heating or cooling medium becomes a part of the primary medium within the system.

In a cooling tower hot water and cool air are intimately

mixed, the air is increased in temperature and part of the water is evaporated and carried away with the air stream

taking with it further heat from the water. In this case the

two fluids are easily separated again after mixing, the air flowing away to the surrounding atmosphere and the water

being retained in the cooling tower basin.

Non Contact Type Heat Exchangers

Non Contact Type Heat Exchangers make up the bulk of heat

exchangers within a power station principally because the

two mediums within the heat exchanger often cannot be mixed. Typical examples include lubricating oil coolers,

generator hydrogen coolers and primary air heaters.

Non Contact Type Heat exchangers are also often called Surface Type Heat Exchangers because an intervening heat

transfer surface is imposed between the fluid being heated or

cooled and the fluid doing the heating or cooling. This separation of the two fluids by a common heat transfer

surface demands a different mode of heat transfer than that




in a contact type heat exchanger where intimate mixing can

occur. The capacity for heat transfer within a surface type

heat exchanger is influenced by the following:

The temperature difference between the two fluids

The volume or mass flow of each fluid

The thermal conductivity of the heat transfer surface

The total surface area presented as a heat transfer surface

The flow characteristics of the two fluids

The direction of flow of the two fluids relative to each other

The first two of the above factors are properties of the fluids

themselves the remaining factors are imposed by the heat exchanger design

14.3.3 Temperature Difference

Temperature difference determines the potential for heat flow. In order for heat to flow from one fluid to another a

temperature difference must exist. The higher the

temperature difference between the two fluids the greater the

potential for heat transfer.

14.3.4 Volume or Mass Flow

The relative mass or volume flow of the two fluids determines

the capacity for heat transfer. For a given rise or fall in temperature the volume or mass flow of the two fluids

determines the total amount of heat available for rejection

from one fluid and the ability of the other fluid to accept the transfer of that heat.

14.3.5 Thermal Conductivity of the Heat Transfer Surfaces

Every substance conducts heat at its own unique rate. In a new, clean heat exchanger the thermal conductivity of the

heat transfer surface will be that of the material of which the

surface is made. Over time however, scaling and other fouling

can occur which will effect the transfer rate.

The fluid flowing over the heat transfer surface tends to flow

as a film closest to the heat transfer surface. Depending on the type of fluid flow (laminar or turbulent) the surface film




may travel at a speed considerably slower than the main body

of fluid passing through the heat exchanger. If this happens

then the temperature differential between the surface film and the tube wall will reduce because the heat is not being

transferred effectively between the main body of fluid and the

film layer and this in turn will further reduce the heat

transfer rate.

Figure 75 provides a graphical representation of the factors

affecting the thermal conductivity of a heat exchanger shown as a hypothetical temperature drop curve across the various

heat transfer surfaces in turn from hot fluid through to cold

fluid.

Air and other incondensable gases can adversely affect a heat

exchanger by blanketing part of the heat exchange surfaces. It is common for heat exchangers with liquid to liquid heat

exchange to have vents included on the shell and tube side to

ensure that they can be effectively primed and vented as

required to remove these gases.




Figure 75: Factors Affecting the Thermal Conductivity of a Surface Type Heat Exchanger

14.3.6 Heat Transfer Surface Area

The opportunity to transfer heat within a surface type heat

exchanger is increased proportionally with an increase in

surface area. In order to maximise the surface area a shell and tube arrangement is often employed. In such cases the

fluid to be heated or cooled is initially passed into a chamber

which then feeds a nest of tubes through which the fluid continues. The cooling or heating medium flows over the

outside of the tube nest. More tubes of smaller diameter

provide a greater surface area than fewer tubes of a larger diameter. With a decrease in tube size however problems are

encountered with increased flow resistance, a greater

tendency to fouling or blockage, higher cost and a possible

Hot

Fluid

Fluid Film Fluid Film

Tube Wall

Scale and other surface

deposits

Temperature

Cool

Fluid

Material through which heat is passing - in order of progress




reduction in the mechanical strength of the tubes. A heat

exchanger will be designed to give the most economical

surface area arrangement for the heat transfer duty to be performed.

14.3.7 Flow Characteristics of Fluids.

As a fluid flows it can assume a laminar, turbulent or

transitional flow pattern.

Laminar Flow

Laminar flow within a circular pipe can be described as a

motion similar to that displayed when opening of a telescope. Each concentric layer of the liquid moves independent of

those surrounding it. In a long straight section of pipe the

flow of the layer at the wall of the pipe may approximate zero with the flow velocity increasing with each layer to a

maximum on the centreline of the pipe. The velocity profile

within a circular pipe is parabolic (See Figure 76).

If laminar flow exists within a heat exchanger heat flow is

impeded by the slow moving layer next to the heat exchange

surface which increases in temperature and retards the heat transfer while the fast moving cool water in the centre of the

pipe or tube has little opportunity to gain any heat.

Figure 76: Simplified Diagram showing Laminar Flow in a Pipe and Graph of Velocity Curve across the Pipe Cross Section

Velocity of

liquid

Centreline

of pipe

Cross Section of Pipe

Each layer of

the fluid moves

independent

of the others

Tube Wall

Pipe wall




Turbulent Flow

Turbulent Flow can be described as an irregular eddying

motion with pronounced commotion and agitation and

velocity fluctuations superimposed on the main flow and boundary layers. Due to the intimate mixing of the fluid

during turbulent flow the velocity of the liquid is virtually the

same across the whole cross section of the pipe or tube.

The intimate mixing and common flow velocity inherent in

turbulent flow means that the temperature of the liquid will

be close to uniform across the whole cross section of flow at any one point allowing heat transfer to take place more

readily (See Figure 77).

Figure 77: Simplified Diagram showing Turbulent Flow in a Pipe and Graph of Velocity Curve across the Pipe Cross Section

Transitional Flow

Transitional flow begins if the velocity of a fluid in laminar

flow is increased. Turbulence begins at the centre of flow and

continues to spreads toward the circumference as the velocity is increased.

Increased velocities of the fluids passing through a heat exchanger may have detrimental effects such as:

Pipe wall

Velocity of

liquid

Centreline of

pipe

Cross Section of Pipe

Eddies and turbulence

cause layers of the fluid to

intermix with

each other

Tube Wall




Low residence time in the heater will not allow time for

heat transfer

Poor quality of the fluids being passed through the heat

exchanger (e.g. sea water containing suspended solids such as sand and shell grit) may lead to excessive

scouring and erosion of the heat exchanger tube neat and

other components

In the above cases a compromise may need to be struck to

limit the fluid velocity through the heat exchanger to a point

where an effective level of transitional flow is achieved.

14.4 Regenerative Heat Exchangers

Heat, generated in the combustion zone of the boiler is partly

transferred to the steam generated in the boiler and partly

contained in the flue gas exiting from the boiler stack.

The heat transferred to the steam is partly converted to work

in the turbine and then to electrical energy in the Generator

with the remaining heat being transferred to the cooling water flowing through the condenser and the condensate

formed as the steam condenses.

Both the flue gas and the cooling water flowing through the

condenser give up a large portion of heat to the atmosphere.

Heat exchangers that take some of this otherwise wasted heat

and reinvest it in the process are called Regenerative Heat

Exchangers. Examples of regenerative Heat Exchangers are:

Condensate and Feedwater Heaters including the Deaerator

Primary and Secondary Air Heaters

Regenerative Heat Exchangers can be either Contact or Non Contact Type




Figure 78: Simplified Diagram of Shell and Tube Surface Type Heat Exchanger Showing Heat Transfer Zones

Figure 78 shows a simplified sketch of a typical horizontal

three-zoned surface type regenerative feedwater heater. The feedwater enters the heater through the inlet side of a divided

water box and flows through a u-shaped tube nest to the

outlet. The Feedwater passes through three distinct zones in sequence as it flows through the tubes. These zones are

designated by the type of process that the steam and its

condensate are undergoing within that zone and are known as:

Subcooling Zone

Condensing Zone

Desuperheating Zone

The Steam enters at the top of the heater and flows in a

direction parallel to but generally in the opposite direction to

the feedwater flow. (Contra Flow)

Steam Inlet Shrouded

Desuperheating

Zone

Cascaded Dr

a

in

In

l

e

t

Vent

Enclosed Drainate

Sub-Cooling Zone Snorkel

Water Level

Feedwater

Inlet

Feedwater

Outlet

Drainate

Outlet

Condensation Zone

U Shaped

Tube Nest

Baffles and Tube

Supports




Desuperheating Zone.

Bled Steam enters the Desuperheating Zone as superheated

steam. Within this zone the steam gives up sensible heat as it

reduces its degree of superheat and approaches saturation temperature. The Desuperheating Zone is encased in a

shroud and contains a number of baffles that provide both a

support for the tube nest and a circuitous path for the steam

flow, which enhances heat transfer.

Condensing Zone

Further baffles are provided throughout the Condensing Zone

to ensure good contact between the steam and the tube nest. The Condensing Zone makes up the greater pat of the heater

and it is in this section that the Saturated Steam gives up its

latent heat as it condenses. The greatest amount of heat transfer therefore takes place in this zone. The condensing

steam falls from the tube nest to the bottom of the heater.

Subcooling Zone

The Sub-cooling Zone forms a separate enclosure again with

baffles to direct the flow of condensate over the tube nest in a

circuitous path. The condensate enters the subcooling zone through a snorkel, which is located below the normal working

level of condensate within the heater. A pressure differential

exists across the subcooling zone so that the tube nest is

completely covered with condensate as it flows to the Drain Outlet, which is located above the normal working level of the

condensate.

14.4.1 Plate Heat Exchangers

An alternative to the Shell and tube type heat exchanger is

the Plate or Plate and frame heat exchanger. These heat

exchangers are made up of a series of plates, mounted in a frame and bolted or clamped together. Each plate has a

herringbone or chevron pattern pressed into it and when the

plates are clamped together a series of flow paths are formed between the pattern. The pattern pressed into the plate

provides strength and rigidity to the plate itself while

providing increased heat transfer surface area and creating a

turbulent flow pattern in the liquid flowing through the channels. The hot and cold liquids enter and exit the heat

exchanger from the four corners of the plate. Alternating




gaskets between each plate direct first one liquid and then

the other through the plate flow paths so that each

consecutive plate has a hot and cold liquid either side of a thin metal wall allowing ease of heat transfer. Figure 79 and

Figure 80provide simplified diagrams of the construction of

and flow pattern within a plate heat exchanger.

Due to the ease of disassembly plate heat exchangers have

lower maintenance costs than shell and tube heat

exchangers.

Some disadvantages of plate heat exchangers include:

maximum design working pressure is limited to 2.1 Mpa.

gasket life is adversely affected by rapid fluctuations in

steam temperature and pressure

not suitable for gaseous applications involving a change in

state.

Figure 79: Simplified Diagram Showing individual segments and end plates of a Plate Heat Exchanger




Figure 80: Simplified diagram showing the flow pattern of consecutive elements of a plate heat exchanger




15. Main Cooling Water Systems

(Sometimes referred to as Circulating Water System)

The function of the Main Cooling Water System is to provide a

cooling medium to remove the major heat load being

dissipated from the turbine condenser (where turbine exhaust steam is converted back to water or condensate) and

selected turbine auxiliary coolers.

The Main Cooling Water System consists of:

a cooling water source ( River, Sea, Lake or Pond)

a means of preventing debris from entering the cooling water

circuit (Debris Screens)

a means of distributing the cooling water through the system

( Cooling Water Pump/s)

heat exchangers through which to transfer the heat from the

turbine exhaust steam and auxiliaries to the circulating

cooling water

a heat sink to which the heat taken from the condenser and

auxiliary coolers is dissipated (ultimately , the environment).

15.1 TYPES OF MAIN COOLING WATER SYSTEM

The classification of a Main Cooling Water System is

determined by whether the cooling water is:

discharged from the cycle after passing through the heat

exchangers ( Open System)

retained within a cycle (Closed System)




partially discharged and partially retained (Combined

System).

15.1.1 Open (or Once Through) Cooling Water System

A typical Open Cooling Water System draws from a large

water source such as the sea, a river or a lake. The water

makes a single pass through the system and is returned to the source where heat is dissipated to the general

environment. The inlet and outlet points are selected to

ensure that the heated water being discharged is not re-entrained in the supply stream. Where a lake is the source,

inlet and outlet canals, natural features such as headlands

and promontories and artificial barriers are often used to

ensure that the residence time of the discharged water within the lake is kept as long as possible to allow for maximum

cooling to take place before the water is reused. Although

natural cooling within a lake is accomplished by evaporation, radiation and convection, the cooling rate is quite slow and

therefore the volume and surface area must be very large for

the lake to act as a continuous heat sink for a power station.

Figure 81 shows the components of an Open Cooling Water

System. The only power demands on the system are those associated with running the Main Cooling Water Pump(s) and

Debris Screen (if rotating rather than fixed screen).




Figure 81: Basic Components of an Open Cooling Water System

Thermodynamically, the Open Cooling Water System is the most efficient means of transferring heat, however, the lack of

availability of large areas of surface water or environmental

regulations limiting the use of such areas often prevent their use as power station cooling ponds. In such cases the Closed

Cooling Water System is employed.

15.1.2 Closed Cooling Water System

A typical Closed Cooling Water System retains the cooling

water within the cooling circuit and therefore must

incorporate an effective means of transferring heat gained

within the cycle to an external heat sink. The most common means of doing this is to incorporate a Cooling Tower in the

circuit.

Water is drawn from a holding basin at the base of the

Cooling Tower, is pumped through the condenser and other

~

Cooling Water Pump

Condensate

Pump

Steam to LP

Cylinders

Water Source – River Sea or Lake

Condenser

Debris Screen




heat exchangers and discharged to a Cooling Tower Cooling

Cell. Within the cooling tower cell the heat from the water is

transferred to the air stream passing through it, the damp warm air is discharged to atmosphere and the cooled water is

returned to the holding basin to continue the cycle. Figure 82

shows the basic components of a Closed Cooling Water

System

Figure 82: Basic Components of a Closed Cooling Water System

Combined Cooling Water System

A combined Cooling Water System may be used for a variety

of reasons:

Seasonal variation in rainfall creating periods of high and low

water supply availability

Restrictions placed on maximum return water temperature

Shared use of a single source with others, resulting in

intermittent use

Figure 83 shows a Combined Cooling Water System. During

times of unlimited access to the water source this system

would operate in the Open Mode with the Cooling Tower idle. During times of restricted access to the water source the

system would operate in the Closed Mode.

Debris Screens

Air In

Debris

Screens

Cooling

Water Pump

Make Up Water Pump

Steam to LP Cylinders Return Water Flow

~




Figure 83: Combined Cooling Water System set up for Open or Closed Operation

Figure 84 shows an Open Cooling Water System with a

Cooling Tower included in the cooling water discharge line. The limiting factor in this system‟s design is the return water

temperature. During times of low load running when return

water temperatures are below the maximum allowable the system will discharge directly to the water source with the

Cooling Tower idle. As the transferred heat load from the

condenser increases the Cooling Tower will be placed in service and, dependent on the cell arrangement, cooling tower

fans will progressively be placed in service as required, to

maintain the temperature of the water returning to the water

source within design limits.

~

Cooling Water

Pump

Condensate Pump

Condenser

Steam to LP Cylinders


Make Up Water Pump




Figure 84: Cooling Tower Included in an Open System to Reduce Return Water Temperature

15.2 Components of the System

The Cooling Water Source

For economic reasons Power Stations are normally located as

near as practicable to the resources they rely upon. This

usually means that the provision of an adequate supply of

cooling water has already been negotiated at the design stage and the Power Station will be located adjacent to a sea side or

fresh water lake or have access to a pumping quota from a

nearby river.

~

Cooling Water Pump

Condensate Pump

Condenser

Steam to LP Cylinders


Cooling Tower Basin

Warm water to Cooling Tower

Cooled Water returned to

Water Source




Inland Power Stations are more likely to rely upon river water

makeup to a Closed Cooling Water System than to have

exclusive use of an inland Lake as a cooling medium. It is the Cooling Towers associated with a Closed Cooling Water

System that will now be examined in more detail.

Cooling Towers

Cooling Towers are Air/Water Heat Exchangers in which the water to be cooled is brought into intimate contact with a

stream of ambient air resulting in a transfer of heat from the

water to the atmosphere. Heat transfer occurs through:

Sensible heat exchange, seen as an increase in the air

temperature

Latent heat exchange, in which a portion of the water is

evaporated and lost from the cooling water circuit, taking with it the extra heat load required to create the

water/steam phase change. (This accounts for the major

part of the heat loss from the returning cooling water).

A small portion of water is also lost from the system due to

drift or entrainment in the air stream. This water has to be replaced from a make up source, which is usually colder than

the return water temperature, resulting in a reduction of the

overall cooling water temperature (although not caused by

heat transfer as such)

The type and size of cooling tower used will depend upon:

The amount of heat rejected by the turbine and auxiliary plant at maximum load.

The average and extreme conditions of ambient

temperature and humidity experienced at the Cooling

Tower site.

The design supply and return cooling water temperatures

for the Cooling Water System (which are related to the

mass flow of cooling water and the condenser design)

Cooling Towers may be of a Natural or Fan Assisted Flow

design.

A Natural Draft Cooling Tower relies on what is termed as a

“stack (or chimney) effect” to create a rising air flow through




the tower. This “stack effect” is produced by the warm, less

dense air being driven from the top of the tower as it is

displaced by the cool, more dense air entering the base.

Fan Assisted Cooling Towers incorporate a mechanical fan to

promote a flow of air through the Tower.

Natural Draft Cooling Towers

The driving pressure, which maintains the air flow through a

Natural Draft Cooling Tower, is dependent on the difference

in densities between the inside and outside air and the height of the tower. As the difference in densities is often quite

small, the height of the tower becomes the most important

design criteria.

This increased demand for height brings with it problems in

construction due to a need for superior strength and resistance to the high wind loading that can be directed

against such a large surface area.

The hyperbolic shape (shown in Figure 85) offers the most

suitable profile for strength and wind resistance.

The performance of Natural Draft Cooling Towers is poor in

hot dry inland areas where low relative humidity conditions are common and the air density outside of the cooling tower

may not be high enough to displace the moisture laden air

inside the tower. Natural Draft Cooling Towers are, however, well suited to locations with consistently high relative

humidity, a cool, humid climate and a high winter power

demand.

High initial costs tend to relegate the Natural Draft Cooling

Tower to higher output Power Stations where long term gains made from the non use of mechanical fans offset the initial

cost.




Figure 85: Cutaway View of Natural Draft Cooling Tower

Cold Air In

Warm Air Out

Cool Water Collected in

Cooling Tower Basin

Drift Eliminators

Fill

Hot Water Distribution

System

Hot Water In

Warm Air Out

Cool Water Out




Fan Assisted Cooling Towers

Where initial cost, climatic conditions and available space

become a concern an alternative to Natural Draft type Cooling

Towers must be found.

By reducing the total height and size of a cooling tower, the

natural “Stack effect,” which induces air flow is also reduced

and it becomes necessary to use a fan to create the required air flow.

Fan assisted cooling towers provide an alternative to the natural draft type, having a lower initial cost, but incurring

an ongoing cost associated with fan useage.

Fan Assisted Cooling Towers may be of a Forced or induced

Draft type.

Forced Draft Cooling Towers

The fan (or fans) in a Forced Draft Cooling Tower is in the air

stream entering the tower. This design allows:

greater ease of access to the fans for inspection and maintenance

reduced fan power demand due to the drier less dense air

being passed by the fan

But incurs the following disadvantages:

heat generated by the fan is added to the Turbine Heat

Load within the Cooling Tower

a portion of the Hot Air and Moisture from the Cooling Tower discharge can be re-entrained into the Fan intake

and recirculated

difficulty is encountered in maintaining even air

distribution through out the tower

as the tower is pressurised leakage can occur from the

casing

during cold weather operation in winter, frost can

accumulate around the fan intake




Owing to the above disadvantages, the majority of Fan

assisted Cooling Towers are of the Induced Draft Type.

Induced Draft Cooling Towers.

The fan in an Induced Draft Cooling Tower is placed at the

top of the Cooling Tower above the Hot Water Distribution

System. The fan draws air from the surrounding area

through the open sided base of the tower and induces it to flow through the water distribution system before discharging

to atmosphere above the tower.

Cooling Towers can be either crossflow or counterflow.

A Counterflow Cooling Tower (shown in Figure 86 draws air into the tower and directs it to flow vertically upward through

the falling water curtain and fill.

A Crossflow Cooling Tower (shown inFigure 87) draws air into

the tower horizontally while the water curtain is falling

vertically.




Figure 86: Counterflow Induced Draft Cooling Tower

Hot Water

In

Hot Water

Distributors Fill Material

Warm Air Out

Cool Air In Cool Air In

Drift

Eliminators

Cool Water Collected in Cooling Tower Basin

Induced

Draft Fan

External Fan

Drive Unit

Fan Cowl

Cool Water

Out




Figure 87: Cross Flow Induced Draft Cooling Tower

Air Entry

louvres

Hot Water

In

Hot Water

Distributor

Fill

Material

Warm Air

Out

Cool Air

In Cool Air

In

Induced Draft Fan

External Fan Drive

Unit

Fan Cowl

Cool Water

Out Cool Water Collected in Cooling Tower Basin




Hot Water Distribution Systems

Hot Water, returning from the condenser, is pumped to the

Cooling Tower under pressure and evenly distributed

throughout the cooling tower cells. This ensures maximum contact and maximum heat transfer between the air and

water. The distribution system does this by breaking the flow

into fine droplets (Spray Distribution) and/or reducing the

velocity of the water flow into the tower (Gravity Distribution).

Spray Distribution uses a grid of spray distributor nozzles fed

through branched piping taken from the main inlet manifold. The spray system allows maximum wetting of the Cooling

Tower and enhanced water/air stream contact. Spray

Distribution is used mainly on Counterflow Cooling Towers (see Error! Reference source not found.).

A Gravity Distribution system first reduces the return water velocity by discharging from the return pipework into a basin

above the cooling tower fill. The hot water, with a reduced

head, then flows through a grid of orifices. Diffuser heads can

be inserted into the orifices to give the required spray pattern on to the fill material below. Gravity Distribution is used

mainly on Cross Flow Cooling Towers (see Error! Reference

source not found.).

Cooling Tower Fill

To increase the heat transfer capacity of a Cooling Tower the

air and water must be mixed as intimately as possible.

This is done by:

increasing the time the water takes to fall from the inlet to

the holding basin and

increasing the surface area that is presented to the air

stream.

The use of fill or “wet deck” within a cooling tower achieves

both of the above. The fill is placed between the hot water

distribution system and the holding basin.

Splash Fill is made up of a series of rectangular bars ( or

planks depending on the material used) with a small vertical




dimension and a larger horizontal dimension, arranged in

tiers within the cooling tower. The small vertical dimension

gives little impedance to the air flow while the broader horizontal dimension impedes the water flow, causing the

stream to be repeatedly broken up and thinly distributed

across the broad face of the bars. This increases both the

surface area in contact with the air stream and the time the water is in contact with the air stream before it finally

reaches the basin below. Figure 88 shows a simplified flow

diagram of the air and water through a section of splash type fill.

Film Type Fill is made up of many hard plastic sheets (which are formed in a range of rippled patterns dependent on the

supplier) placed together to form hundreds of separate flow

paths. The water tends to flow as a thin film down the sides of the fill while the air flows up through the centre.

The rippled patterns:

present a greater water surface area to the air flow

increase the time that the water is in contact with the air

stream and

create turbulence in the air stream to ensure more

intimate contact between the air and water

By arranging the sheets so that the paths are not vertical but

zig-zagged the contact time and surface area are further extended.

Figure 89 is a simplified diagram of film type fill showing the air and water paths.




Figure 88: Splash Fill – Most Suitable for Cross Flow Cooling Towers

Figure 89: Film Type Fill – Equally Suitable for Cross or Counter Flow

Water Flow Consistently Broken and

Slowed Down by Splash Bars

Air Flow Horizontal

and

Water Curtain Vertical

Splash Bars

Air passes over a fine film of water flowing

down the surface of the fill medium

Cross or Counter flow are equally

appropriate for film

type fill media




Cooling Tower Fans

Cooling Tower Fans may be of either the centrifugal or axial

flow type. Centrifugal fans operate against increased

discharge heads and so are more likely to be used for forced draft Cooling Tower applications. Axial flow fans are most

prominent in Induced Draft Cooling Towers where they are

capable of moving large volumes of air for a relatively low

power demand.

Air Flow and Water Temperature Control

Air Flow through the Cooling Tower can be regulated by a

number of mechanisms:

Fan speed adjustment

Fan Blade Pitch adjustment (axial Flow Fans)

Shutting down and placing fans in service as air flow

demand dictates

As the Heat Load transferred to the Main Cooling Water System may vary dependent on the total steam flow being

passed to the Turbine Condenser and the load being

contributed from the Auxiliary Heat Exchangers, Cooling Towers for larger installation tend to be of a multi-cellular

construction. Each Cell is fitted with its own fan, hot water

distribution system and “wet deck” or Fill.

This allows the Cooling Tower power demand to be „turned

down‟ during times of low heat transfer demand. Fans can be

selectively taken out of service or fan blade pitch changed to reduce the total air flow through the tower to prevent

overcooling of the water. Where multiple Main Cooling Water

Pumps are provided ( each with less than 100% flow capacity) cooling water flow can be altered by varying the number of

pumps in service.

Cooling Tower Basin

Cooling Tower Basins for Power Stations are generally made

of concrete and form the holding pond for the Main Cooling

Water in a Closed Cooling Water System. The Basin in




initially filled from an external source (Sea, lake or river) and

the operating level is maintained from the same source. The

Basin‟s size should be calculated to allow the system to operate without makeup for sufficient time to carry out

regular in-service maintenance.

The Cooling Tower Basin is normally fitted with the following:

Valved Cooling Water Makeup Supply Line

Valved Drain Line

Overflow Line

Main Cooling Water Pump Forebay (Usually of a greater depth than the main basin area to prevent pump vortexing

and cavitation)

Debris Screens at the pump forebay entry

Chemical Dosing Facilities

Facilities to monitor Water Quality and blowdown

Where on site water resources are limited Cooling Tower

Basins have been used as an emergency source of water for Fire Fighting. Alternate valved pipework is installed to supply

the Fire Fighting Pumps‟ suction.

Cooling Tower Makeup

Water is lost from the Main Cooling Water Circuit due to:

Evaporation Losses in the Cooling Tower (approximately 1

to 1.5% total Cooling Water flow rate)

Drift Losses from the Cooling Tower ( approximately 0.02 to 0.03% total flow rate)

Blowdown from the Cooling Tower Basin to control the

concentration of dissolved solids (approximately 0.2 to 1.5

% total Cooling Water flow rate dependent on allowable concentration of solids)

All these losses must be made up from the primary water source to allow continuous operation of the power plant. As

an example: the cooling water makeup to a 1000MW Power

Plant closed cooling water system with a circulating cooling

water flow of 45000 litres/second (l/sec) could range from 550 to 1500 l/sec.




Blowdown and Chemical Dosing

With an evaporation rate of 1 to 1.5% the water within the

Cooling Tower Basin would have a concentration of solids of 2

to 2.5 times that of the makeup water with every 100 cycles of the basin‟s volume through the system. Dependent on

whether the primary source is sea water, lake or river water

the initial concentration of solids will vary. Chemical analysis

of the water will determine the allowable concentration levels and the degree of blowdown required to maintain acceptable

concentrations within the system. If the total concentration of

solids reach saturation point scaling will occur within the cooling water circuit and the heat exchange capacity of the

system will deteriorate. It is therefore necessary to

continually remove a percentage of the cooling water from the circuit and to replace it with makeup water with a lower

solids concentration.

Air moving through the Cooling Tower carries with it dust

and debris which is washed from the air by the cooling water.

This silt enters the system and, if the water is not treated to

prevent it, precipitates out, forming a film over the heat exchange surfaces.

Biological contaminants in the form of marine and fresh water molluscs and crustaceans, water resident plants, algae

and bacteria can cause fouling and corrosion within the

systems pipework and the heat exchange surfaces.

Crossflow and Counterflow Cooling Towers without air entry

louvres tend to grow more algae due to the increased amounts of sunlight entering the tower.

Breakdown and decomposition of biological material can generate Hydrogen Sulphide and Carbon Monoxide, which

readily combine with water to form corrosive solutions.

To counter the above scaling and corrosion effects, antiscalant and anticorrosion chemical dosing is normally

carried out (if required) on a regular basis with dedicated

dosing pumps delivering a metered dose from chemical storage tanks.




Biological control tends to be irregular in the form of “shock”

dosing to prevent molluscs etc from developing a learned

response and subsequently withdrawing themselves from the dosing stream prior to the dose being delivered.

Cooling Tower Wetdown System

Where the main structural components of the cooling tower

are made from wood a Wetdown System is normally installed. Such a system uses low pressure sprays to douse the cooling

tower internals and prevent dryout and distortion of the

wooden structure during periods when the cooling water circuit is out of service. The risk of fire within the cooling

tower is also reduced by keeping the wooden structure damp.

Circulating Water Pumps

Cooling Water Pumps may be of the Centrifugal, Axial Flow or

Mixed Flow types dependent on the total System Discharge

Head and mass flow required. Axial Flow pumps are well suited to Open Cooling Systems while Centrifugal Pumps

perform well in Closed Systems.

Debris Screens

Depending on the water source a variety of debris screens are

used to prevent fouling of the pumps and heat exchangers by

large particulate matter.

Where salt or fresh water molluscs and crustaceans are

plentiful care must be taken to prevent a build up of shells

and grit within the system. In such cases the intake from the water source needs to be screened and where a cooling tower

forms a component of the system a further debris screen

needs to be added at the Cooling Tower Basin Outlet.

Screens can take the form of:

Fixed Screens with a means of raking the debris from the

screen and discarding it to waste

Rotating Screens with a self cleaning water spray which

flushes water borne fauna and debris to waste




Removable Series Screens, which allow any one screen to

be removed and cleaned while subsequent screens remain

active in the flow path.

The condition of the screens may be monitored by the

installation of a differential pressure switch across the screen

with alarm contacts included to initiate an automatic self cleaning action or to inform plant operators when the

differential pressure has reached a preset value and action

must be taken.

Heavily fouled screens can have a pronounced effect on

cooling water flow to the extent that the pump flow can exceed supply resulting in a reduction in the level of the

pump suction forebay and possible pump cavitation and

tripping out of service.

Auxiliary Cooling Water Systems

In addition to the Main Turbine Condenser there are many

other heat exchangers removing minor heat loads from

operating plant throughout the Power Station Site. It is common practice to use a secondary or Auxiliary Cooling

Water System to remove and dissipate the heat from these

heat exchangers.

The Auxiliary Cooling Water System design can include any

of the following:

separate closed system completely divorced from the Main

Cooling Water System

closed system which includes a heat exchanger cooled by

a branch line from the Main Cooling Water System thereby transferring its heat to the same heat sink as the

Main System

Open System with the heat exchangers cooled directly

from a branch line off the Main Cooling Water Supply Line.

Figure 90 shows a typical Closed System utilising a heat exchanger between the Main and Auxiliary Cooling Water

Systems.




Figure 90: Auxiliary Cooling Water System Utilising Main/Auxiliary Cooling Water Heat Exchanger

In a system such as that shown in Figure 90 the recirculating

Cooling Medium is usually of a high quality (eg. Demineralised Water). Provision is made for the addition of

makeup and for the expansion of the system through a raised

head tank which also serves to maintain a positive suction head on the circulating pumps. Chemical dosing and/or

other methods of water quality maintenance and control may

also be used dependent on the circulating fluids in the heat

exchangers to be cooled.

System pressures within Auxiliary Cooling Water System

Heat Exchangers normally maintain a positive pressure differential between the fluid being cooled and the fluid

coolant to prevent contamination of the primary fluid should

a leak occur within the heat exchanger. An example can be seen in a Lubricating Oil Cooler. The system pressure of the

Lubricating Oil would be higher than the Auxiliary Cooling

Auxiliary Cooling Water Circulating

Pumps

Main/Auxiliary Cooling Water Heat

Exchangers

Main Cooling Water Inlet

Main Cooling Water Outlet Auxiliary

Cooling

Water Inlet

Plant Heat

Exchangers

Expansion /Head Tank

Auxiliary Cooling Water Out




Water Pressure to ensure any leakage would result in oil

migrating into the cooling water circuit rather than vice

versa. Th higher pressure system is also placed into service before the cooling circuit and removed from service after the

cooling circuit

Typical Heat Exchange Circuits served by the Auxiliary Cooling Water System can include but are not limited to :

Turbine Lubricating Oil Coolers

Turbine Control Oil Coolers

Generator Seal Oil Coolers

Generator Air Coolers

Boiler Feedwater Pump Coolers

Air Compressor Coolers

Steam and Hot Water Sample Coolers

Glossary of Terms

Dry Bulb Temperature

The air temperature as normally measured using a mercury type thermometer.

Wet Bulb Temperature

The air temperature as measured by a sling psychrometer.

Sling Psychrometer

A thermometer held in a frame with a piece of damp gauze covering the mercury filled bulb. As air passes over the wetted gauze (by rotating the device rapidly) water evaporates and cools the bulb resulting in a lower reading than would be seen on a dry bulb thermometer at the same location. The lower the humidity the greater the difference between wet and dry bulb temperatures. At 100% humidity Wet and Dry Bulb temperatures are the same.

Dew Point The temperature at which the water vapour in the air begins to condense.

Approach The difference between the temperature of the cold water out of the cooling tower and the ambient wet bulb temperature

Range The difference in temperature between the hot water in and cold water out of the cooling tower.








1. List three types of Main Cooling Water System

.......................................................................................

.......................................................................................

.......................................................................................

2. What is the main method of Heat Transfer that occurs in

a Cooling Tower.

.......................................................................................

.......................................................................................

3. Name three Types of Cooling Tower based on the method of air flow through the tower.

.......................................................................................

.......................................................................................

.......................................................................................

4. Why is it necessary to have a makeup water supply to a Cooling Tower in a Closed System.

.......................................................................................

.......................................................................................




.......................................................................................

5. List 3 causes of water quality contamination found within

a Closed Cooling Water System.

.......................................................................................

.......................................................................................

.......................................................................................

6. List all the components of a Closed Cooling Water System

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................




7. How can Cooling Tower Basin Water Temperature be

controlled in a Closed Cooling Water System.

.......................................................................................

.......................................................................................

.......................................................................................

8. What is the purpose of using wetdeck or fill within a cooling tower.

.......................................................................................

.......................................................................................

.......................................................................................

9. Name two types of fill used in cooling towers

.......................................................................................

.......................................................................................

10. Explain the difference between wet bulb and dry bulb

temperatures and when would both temperatures be the same.

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................




11. What is the most thermodynamically efficient type of

cooling water system and why is this type of system not

always used.

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

12. List 5 Heat exchangers commonly served by the Auxiliary Cooling Water System

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

.......................................................................................

13. When placing a Turbine Lubricating Oil Cooler in Service which system would normally be pressurised first. The

Lubricating Oil or the Auxiliary Cooling Water.

.......................................................................................

.......................................................................................




16. Safe Operation of a Turbine




17. Answers to Trainee exercises

Trainee exercise 6.3.3

1. The design shape of the fixed blades.

2. a) Type of flow

b) Cylinder arrangement

c) Type of blading

3. Several cylinders can be coupled together to achieve a

turbine with a greater output.

4. a) outer casing joint flanges and bolts experience much

lower steam conditions than with the one direction design

b) reduction or elimination of axial thrust created within the cylinder

c) lower steam pressure the outer casing shaft glands

have to accommodate

5.

Figure 91: Steam flow through a tandem three cylinder turbine


1. High pressure steam striking or hitting against the

rotating blade causes it to move.

2. Impulse blades are usually installed in the high pressure section of a turbine.

HP

LP IP

Condenser




3.

Figure 92: Pressure velocity diagram for reaction turbine stage

4. a) pressure drop occurs in the fixed nozzles

b) no pressure drop occurs across the moving blades

Error! Reference source not found. Error! Reference source not found.

1. This arrangement allows for easy dismantling should maintenance be required

2. a) Nozzle segments

b) Centre rings

c) Baffle strips

3. Diaphragm outer ring


1. Condensate is drawn from the condenser hotwell by the

condensate extraction pump. It is then pumped through

B N

V P

Steam flows

PC

VL

Motion




the non-contact low pressure (LP) heater/s. Travelling

through the low pressure heater/s the condensate is

heated. It then passes to the deaerator (DA) for further heating and oxygen removal.

Condensate exits the DA and enters the feedwater pump

which boosts the pressure greater than boiler pressure and therefore forces what is now known as feedwater

through the high pressure (HP) heater/s and into the

boiler.

As the feedwater travels through the boiler it becomes

high pressure, high temperature steam known as superheated steam.

Superheated steam exiting the boiler is piped to the control valve/s (or throttle valve/s). The control valves

regulate admission of steam to the turbine depending

upon load. Once the superheated steam enters the turbine

it expands and gives up heat causing the turbine rotor to rotate.

When steam has exhausted its energy it exits the turbine and enters the condenser. The steam condenses in the

condenser and gravitating to the condenser hotwell ready

for pumping once again around the water/steam cycle.

Trainee exercise Error! Reference source not found.

1. a) Deposits on blades

b) Steam inlet conditions

c) Steam exhaust conditions

2. a) Loading on the turbine

b) Circulating water inlet temperature

c) Circulating water quantity passing through condenser




d) Cleanliness of condenser tube surfaces

e) Air entrainment in the circulating water

f) Air in the steam side of the condenser

3. gauge pressure = atmospheric pressure absolute

pressure

= 101.7 8.7

= 93kPa gauge

Trainee exercise Error! Reference source not found.

1. They are constructed in two halves (top and bottom) along a horizontal joint so that the cylinder is easily opened

for inspection and maintenance.

2. A double casing arrangement subjects the outer casing

joint flanges, bolts and outer casing glands to lower steam

condition.

3. a) Bolted

b) Clamped

4. Insertion of heating rods into the centre hole of the bolts

or studs to raise the temperature to manufacturers

specifications whilst tensioning.

5. Casing flanges are much thicker and have a greater

thermal mass than the casing, therefore they are slower to change temperature than the casing.

6. By the proper application of flange warming

2. turbine manual

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