2. Turbine Manual

Ban chuan bi san xuat

Power Plant General Series Course Volume 2

Turbine Manual Version (a) 15 September 2010 Mr : Le Duy Hanh

TechComm Simulation Pty Ltd

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 6.3.2 6.3.3

6.4 6.4.1 6.4.2 6.4.3

6.5 6.5.1 6.5.2

6.6 6.6.1

6.7 6.7.1 6.7.2 6.7.3 6.7.4 6.7.5

Type of flow ................................................................................................................10 Cylinder arrangement .................................................................................................12 Trainee exercise: ........................................................................................................18

Types of blading .................................................................................................. 19 Impulse ......................................................................................................................19 Reaction .....................................................................................................................26 Trainee exercise: ........................................................................................................29

Turbine Nozzle Plates or Diaphragms................................................................ 31 Nozzle Plate ...............................................................................................................31 Trainee exercise .........................................................................................................35

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

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

7.

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

7.1

Turbine cylinder(s) .............................................................................................. 47

7.1.1 7.1.2 7.1.3

7.2 7.2.1 7.2.2

Casing flanges............................................................................................................51 Flange warming ..........................................................................................................53 Trainee exercise .........................................................................................................55

Turbine rotor ........................................................................................................ 58 Forged steel drum rotor ..............................................................................................58 Solid forged rotor ........................................................................................................59

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Version (a) 15 September, 2010` TechComm Simulation Pty Ltd

TechComm Simulation Pty Ltd 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 9.1.2 9.1.3

9.2

Oil Properties..............................................................................................................76 Causes of Oil Deterioration .........................................................................................78 Establishment of Oil Film ............................................................................................79

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 11.1.2 11.1.3 11.1.4

11.2

Turbo-Generators Operating in Parallel.......................................................................99 The Speeder Gear of a Turbine Governor .................................................................100 Load Sharing Between Units Fitted with Governors Having Speeder Gears ..............101 Relays ......................................................................................................................103

Overspeed Control Of A Turbine ...................................................................... 105

11.2.1 11.2.2 11.2.3 11.2.4 11.2.5 11.2.6 11.2.7 11.2.8 11.2.9 11.2.10 11.2.11 11.2.12 11.2.13 11.2.14 11.2.15 11.2.16 11.2.17

Development of Speed Control Systems ...................................................................105 Summary of Speed Control Systems ........................................................................106 Speed Governor .......................................................................................................106 Governor Control Valves...........................................................................................106 Emergency Governor................................................................................................107 Emergency Stop Valves ...........................................................................................107 Bled Steam Non-Return Valves ................................................................................107 The Secondary Governor..........................................................................................107 The IP Interceptor Valves .........................................................................................108 The IP Emergency Stop Valves ................................................................................109 Bled Steam Valves ...................................................................................................109 Governor Control Valves...........................................................................................109 Throttle Control.........................................................................................................109 Nozzle Control ..........................................................................................................109 HP Emergency Stop Valves ......................................................................................110 Load Pay Off or Unloading Gear ...............................................................................110 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

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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 13.1.2 13.1.3

13.2

Low Pressure Regenerative Heat Exchangers ..........................................................129 Moisture Extractors...................................................................................................130 Steam Jet Air Ejector Surface Condensers ...............................................................130

Low Pressure Feedwater Heaters .................................................................... 131

13.2.1 13.2.2 13.2.3

Deaerator .................................................................................................................131 Reserve feedwater Tanks (surge tank) .....................................................................132 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 14.2.2 14.2.3

14.3

Centrifugal Pumps. ...................................................................................................138 Axial and Mixed Flow Pumps ....................................................................................142 Positive Displacement Pumps...................................................................................143

HEAT EXCHANGERS ........................................................................................ 145

14.3.1 14.3.2 14.3.3 14.3.4 14.3.5 14.3.6 14.3.7

14.4

The Process of Heat Transfer ...................................................................................145 Types of Heat Exchanger .........................................................................................147 Temperature Difference ............................................................................................149 Volume or Mass Flow ...............................................................................................149 Thermal Conductivity of the Heat Transfer Surfaces .................................................149 Heat Transfer Surface Area ......................................................................................151 Flow Characteristics of Fluids. ..................................................................................152

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 15.1.2

15.2

Open (or Once Through) Cooling Water System .......................................................160 Closed Cooling Water System ..................................................................................161

Components of the System .............................................................................. 164

15.2.1

Trainee exercise: ......................................................................................................182

16.

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

17.

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

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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

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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

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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.

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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.

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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

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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 Turbine manual


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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 Turbine manual


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A simplified diagram of a reverse flow high pressure cylinder is shown in Figure 3.

High pressure steam inlet

Cylinder exhaust

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.

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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.

Steam from boiler

HP Rotor

LP Rotor

Exhaust steam to condenser

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 Turbine manual


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Steam from boiler

HP Rotor

IP Rotor

LP Rotor

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 Turbine manual


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Exhaust steam to condenser Steam from boiler

HP Rotor

Steam reheater

IP Rotor

LP 1 Rotor

LP 2 Rotor

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

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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.

Steam from boiler

Steam reheater

HP Rotor

LP 1 Rotor

IP Rotor

Alternator No 1 3600 rpm 2 pole 60Hz

LP 2 Rotor

Alternator No 2 1800 rpm 4 pole 60Hz


Figure 7: Tandem cross-compound turbine

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Exhaust steam to condenser Steam from boiler

HP Rotor

Steam reheater

IP Rotor

LP 1 Rotor

LP 2 Rotor

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 Turbine manual


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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) .................................................................................... ....................................................................................

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c) .................................................................................... .................................................................................... 5. Draw the steam flow path through the tandem three cylinder turbine shown in Figure 9:

HP

IP

LP

Condenser

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 entrance and exit angle of approximately 200. They generally installed in the higher pressure sections of turbine where the specific volume of steam is low

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requires much smaller flow areas than that at lower pressures. The impulse blades are short and have a constant cross section. Bearings Rotation

Rotor

Steam

Nozzle

Boiler

Flame 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) Turbine manual


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Figure 11 shows a section of impulse type blading. Force

Steam IN

Steam OUT

Leading edge

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.

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Exhaust steam leaving

Live steam entering

Fixed Nozzles

Casing

Rotor Moving blades

Shaft

Motion

Steam flows

Section

VL

P

B

V

N

PC 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

Figure 12: Cross section of an impulse blade stage

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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. Fixed blades


Live steam entering

Fixed Nozzles

Casing Moving blades

Shaft Rotor

Motion

Motion

Steam flows

Section B

B

Fixed

Moving

VL

P

B Moving

V

N

P – pressure of steam entering turbine V – velocity of steam entering turbine N – nozzle (fixed blade) B – blades (moving and fixed) PC – Condenser pressure VL – velocity of steam leaving turbine

PC

Figure 13: Velocity compounded impulse turbine Turbine manual


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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. Turbine manual


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Fixed nozzle


Live steam entering

Diaphragm Casing

Moving blades

Shaft Rotor

Motion

Motion Shaft gland

Fixed Nozzles

Steam flows

Section N

B Moving

VL

P

B Moving

V

N

PC P – pressure of steam entering turbine V – velocity of steam entering turbine N – nozzle (fixed blade) B – blades (moving and fixed) PC – Condenser pressure VL – velocity of steam leaving turbine

Figure 14: Two stage pressure impulse turbine

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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.

Rotation Nozzle Rotor

Boiler

Flame

Figure 15: Principle of reaction turbine

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A section of reaction type blading is shown in Figure 16 while Figure 17 shows a turbine section with pressure and velocity relationship.

Force

Leading edge

Steam IN

Steam OUT

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.

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Live steam entering

Fixed Nozzles

Casing

Rotor Moving blades

Shaft

Motion

Steam flows

Section

VL

P

B

V

N

PC P – pressure of steam entering turbine V – velocity of steam entering turbine N – nozzle (fixed) B – blades (moving) PC – Condenser pressure VL – velocity of steam leaving turbine

Figure 17: Turbine section showing pressure and velocity relationship.

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6.4.3

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. 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: Motion

Steam flows

VL

P

B

V

N

PC Figure 18: Reaction turbine stage Turbine manual


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

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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 ring(s) or diaphragm 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.

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Figure 19: Nozzle plate for double flow IP cylinder

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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 Centre ring(s) or diaphragm 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 ring(s) or diaphragm 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.

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Figure 20: IP cylinder diaphragm with baffle strips

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6.5.2

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. 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: .......................................................................................

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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

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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.

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Control valve Boiler Generator

Turbine

Condenser

Deaerator Circulating Water Pump Stack

Outlet

Inlet

Canals

Condensate Extraction Pump

LP Heater

Feedwater Pump

Precipitator or fabric filter

HP Heater

Air Fuel

Figure 21: Basic steam cycle Turbine manual

Version (a) 15 September, 2010`

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6.6.1

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

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Version (a) 15 September, 2010` TechComm Simulation Pty Ltd


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.

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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.

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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.

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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.

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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.

6.7.5

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. 1. Name three factors affecting turbine efficiency that operators have control over: a) ...................................................................................... b) ...................................................................................... c) ......................................................................................

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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: ......................................................................................... ......................................................................................... ......................................................................................... .........................................................................................

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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

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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.

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Figure 22: Cutaway of a single flow HP Cylinder Turbine manual


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Figure 23: Cutaway of a double flow IP Cylinder

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Figure 24: Cutaway of two double flow LP Cylinders

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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 Turbine manual


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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 wedgeshaped 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.

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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. Thinner casing

Thicker casing flange

Flange bolt/stud

Turbine rotor Flange joint

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 Turbine manual


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then passes through the flange to the next bolt/stud to continue the warming process.

Casing flanges

Flange bolt/stud 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 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.

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Casing flanges

Flange bolt/stud 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

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

7.1.3

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. 1. Why are most modern turbine casings constructed in two halves: ......................................................................................... ......................................................................................... ......................................................................................... .........................................................................................

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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: ......................................................................................... ......................................................................................... ......................................................................................... .........................................................................................

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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: ......................................................................................... .........................................................................................

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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

7.2.1



Shrunk and/or keyed to the shaft



Welded construction

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

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clearances can be kept to a minimum thus improving efficiency.

HP steam inlet end

Rotor blades

Driven dowels

Exhaust end shaft and disc Shrink fit

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

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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

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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.

Blades

Locking ring

Weights

Hole through shaft

Rotor shaft

Wheel

Figure 32: Shrink fit disc rotor

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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.

Discs

Figure 33: Rotor showing discs before welding

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Blades

Figure 34: Welded rotor construction after assembly

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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.

Cut-off blade section

Blade root

Annular Fir-tree

Axial Fir-tree

Inverted 'T'

Figure 35: Groove type root fixing

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Closing blade window

Dowel hole

Rotor disc

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.

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Dowel hole

Figure 37: Two shoulder straddle fir-tree blade root

Closing blade window

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.

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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.

Overlap of lacing wire at start and finish

Lacing wire

Reaction blading

Figure 39: Blading supported with lacing wire

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Shroud ring

Tang peened over

Tang

Blades

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

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Casing

Gland

Figure 41: Shrouding single baffle ring gland

Casing

Gland

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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

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Outer half of coupling

Inner claw

Shaft

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. Turbine manual


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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.

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Figure 46: Solid shaft coupling

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Figure 47: Solid shaft coupling fitted with hand barring gear

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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.

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9. 9.1

Lubrication Systems 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.

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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

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Normal Operation

38 – 45 Deg Celsius

Turning Gear

25 – 35 Deg Celsius

Turning Gear Permissive

25

High Limit

48


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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 Turbine manual


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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.

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1) Shaft at rest

2) Shaft as rotation commences Oil

Line of Contact

3) Increasing shaft speed

Line of Contact

4 ) Shaft at full speed

Minimum oil film Minimum oil film

( oil wedge established )

(film being established ) Figure 48: Establishing oil film

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9.2

Components of a Turbine Lubricating Oil System

Refer Figure 49

Turbine manual



Main Oil Tank



Oil Purification / Centrifuge Systems



Oil Pumps



Oil Coolers



Strainers / Filters



Instrumentation



Jacking Oil Pumps



Hydraulic Accumulator


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Bearings

Lube Oil Header

Sight Glasses

Pressure Switches

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

AC

DC Emergency Oil Pump

AC Oil Pump

Shaft Driven Oil Pump

DC

Oil Centrifuge

Drain Alarm

Leve

Heater

Main Oil Tank

Level

Figure 49: Typical turbine lubrication system Turbine manual


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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 bypasses 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 standby 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.

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TechComm Simulation Pty Ltd CW in

Oil Out

A

B

C

Oil in

CW Out

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

CW in

Oil Out

A

B

C

Oil in

CW Out

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

Figure 50: Oil cooler arrangement

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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 Turbine manual


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small containment tank which is level alarm protected to monitor excessive waste or abnormal flows.

Figure 51: Oil Centrifuge

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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.

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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 shutdowns 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.

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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 nonfriction 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 insoluble 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.

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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.

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Grease gun

Nipple Types

Grease gun Figure 53: Manual grease system

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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.

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Figure 54: Grease pumping system

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10. Thrust bearing

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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.

Manually Operated Throttle Valve Steam to Turbine Generator

Turbine

Condenser

Variable Load

Throttle valve setting manually adjusted following each speed reduction due to Load increase Turbine Speed

Turbine Speed versus Load Characteristic for each throttle valve setting

0

Figure 55

Turbine Load

Max

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 Turbine manual


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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. Throttle Valve Position Controlled by Governor Steam to Turbine Generator

Variable Load

Turbine

Condenser

Throttle valve automatically adjusted following each speed reduction due to Load increase Turbine Speed

A C B

0

Figure 56

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Turbine Load

% Droop

Max

Droop Curve for a Turbine with Flyball Governor Controlled Throttle Valve


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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.

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Throttle Valve Position Controlled by Governor Steam to Turbine Turbine

Generator A

Condenser Throttle Valve Position Controlled by Governor Steam to Turbine Turbine

Generator B

Condenser

Common Load

Turbine Speed

Generator A placed on line and partially loaded to L1A

L1A

L1B = 0

Generator A Speed-Load

Generator B Speed-Load L2

L2A

B

L3B 0

Figure 57

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L3A Turbine Load

Max

Synchronising and Loading Two Turbo-Generators in Parallel


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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 speedload characteristics

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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.

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Flyball Restraining Spring A

Moveable Sleeve X

Shaft Movement transferred to Throttle Valve Control

Spring B Driven from Turbine Shaft

Fixed Nut Handwheel Clutch Speeder Gear Motor

Figure 58

11.1.3

Flyball Governor with Speeder Gear

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.

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Generator A Speed-Load Characteristic Generator B Initial Speed-Load Characteristic

Turbine Speed

Generator B Speed-Load Characteristic after Speeder Gear Operation X2 LB1

X1

A LA1 LA2

B2 B1

LB2 0

Turbine Load

Max

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.

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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

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Double Acting Relay


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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

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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.

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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.

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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

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governor valves whereas approximately 0.2 seconds.

the

secondary

governor

takes

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.

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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.

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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.

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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 predetermined values. To shut off immediately the energy input to the turbine at any time should an emergency arise.

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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.

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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 reused 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.

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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

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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 noncondensables. (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 noncondensable gases without compromising the condenser backpressure must be provided

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Figure 62 shows a typical path for the air and noncondensable 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 NonCondensable Gas Path Turbine manual


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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)

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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. Steam In

Air In

Steam and Air Mixture Out

Figure 63: Single Stage Steam Jet Air Ejector Turbine manual


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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 maintenance costs. Turbine manual

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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.

950

700 Volumetric Capacity in l/sec

Vacuum Pump Hogging Ejector Main Ejector Start Up Range

470

Operating Range 235

0.35

1.7

3.5

10

35

101

Pressure in kPa Absolute

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 Turbine manual


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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

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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 flowinduced 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. Turbine manual


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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.

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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.

Inlet Water Box

Tube Support Plates

Steam Inlet Tube Plate

Cooling Water Inlet

Outlet Water Box

Cooling Water Outlet

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 Turbine manual


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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.

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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.

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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

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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. Turbine manual


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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.

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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 Turbine manual


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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.

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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:

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13.3 HP Feedwater Heaters

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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.

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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.

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Pressure

Pressure Head (e.g. Steam pressure in Boiler Drum)

Discharge Head

Suction Head

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

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Expansion/Head Tank

Static Head

Cooler/Heater P

Pump

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.

Dynamic Head Total Pump Discharge Head

Head Static Head

0

System Flow

100%

Figure 69: System Resistance to Flow

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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.

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Liquid discharges from pump

Liquid enters eye of Impeller

Velocity is reduced and pressure increased in volute

Liquid driven from impeller at high velocity

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.

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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.

Power Efficiency

Head

0

Flow

Head versus Flow (H-Q) Power versus Flow Required NPSH Efficiency

Figure 71: Typical Pump Characteristic Curves for a Centrifugal Pump

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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.

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Pump Performance Curve 35 30 He 25 ad (m 20 ) 15

Operating Point

10 5 0 1

2

3

4

5

6

7

Flow (l/s)

8

9

Pump Curve System Curve

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.

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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.

Head

Power

0

% Flow

100

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.

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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.

Theoretical (H-Q) Curve

Head versus Flow (H-Q) Curve

Head/Power

Power Curve

0

% Flow

100

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.

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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 Turbine manual


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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. Turbine manual


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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 separates the two fluids.

an intervening

surface

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 Turbine manual


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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 Turbine manual


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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

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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.

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Fluid Film

Fluid Film

Hot Fluid

Tube Wall

Cool Fluid

Temperature

Scale and other surface deposits

Material through which heat is passing - in order of progress

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

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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.

Centreline of pipe

Tube Wall

Velocity of liquid

Pipe wall

Each layer of the fluid moves independent of the others Cross Section of Pipe

Figure 76: Simplified Diagram showing Laminar Flow in a Pipe and Graph of Velocity Curve across the Pipe Cross Section Turbine manual


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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).

Centreline of pipe

Tube Wall Velocity of liquid

Eddies and turbulence cause layers of the fluid to intermix with each other

Pipe wall

Cross Section of Pipe

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:

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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

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Cascaded

Vent

Condensation Zone

D r a i n

Shrouded Desuperheating Zone

Steam Inlet

I n l e tBaffles and U Shaped Tube Nest

Tube Supports

Feedwater Outlet

Drainate Outlet

Water Level

Snorkel

Enclosed Drainate Sub-Cooling Zone

Feedwater Inlet

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)

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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

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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

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Figure 80: Simplified diagram showing the flow pattern of consecutive elements of a plate heat exchanger

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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) Turbine manual


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partially System).

15.1.1

discharged

and

partially

retained

(Combined

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 reentrained 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).

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Steam to LP Cylinders

~

Condenser

Debris Screen

Cooling Water Pump

Condensate Pump Water Source – River Sea or Lake

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

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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

Steam to LP Cylinders Return Water Flow

~ Air In

Make Up Water Pump

Cooling Water Pump Debris Screens

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. Turbine manual


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Steam to LP Cylinders

~

Condenser

Condensate Pump Cooling Water Pump Water Source – River Sea or Lake Make Up Water Pump

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.

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Steam to LP Cylinders Warm water to Cooling Tower

~

Condenser

Cooling Tower Basin

Condensate Pump

Cooled Water returned to Water Source

Cooling Water Pump

Water Source – River Sea or Lake

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.

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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 Turbine manual


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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.

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Warm Air Out

Drift Eliminators

Warm Air Out

Hot Water Distribution System

Hot Water In Fill Cold Air In Cool Water Collected in Cooling Tower Basin Cool Water Out

Figure 85: Cutaway View of Natural Draft Cooling Tower

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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 distribution through out the tower

even

air

as the tower is pressurised leakage can occur from the casing during cold weather operation in winter, frost can accumulate around the fan intake

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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.

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Warm Air Out Fan Cowl

External Fan Drive Unit

Induced Draft Fan

Hot Water In

Drift Eliminators

Hot Water Distributors

Fill Material

Cool Air In

Cool Air In

Cool Water Out

Cool Water Collected in Cooling Tower Basin

Figure 86: Counterflow Induced Draft Cooling Tower

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Warm Air Out Fan Cowl

Hot Water In

Hot Water Distributor

Induced Draft Fan

External Fan Drive Unit

Cool Air In

Cool Air In

Air Entry louvres Fill Material

Cool Water Out

Cool Water Collected in Cooling Tower Basin

Figure 87: Cross Flow Induced Draft Cooling Tower

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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 Turbine manual


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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.

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Air Flow Horizontal and Water Curtain Vertical Splash Bars

Water Flow Consistently Broken and Slowed Down by Splash Bars

Figure 88: Splash Fill – Most Suitable for Cross Flow Cooling Towers

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

Figure 89: Film Type Fill – Equally Suitable for Cross or Counter Flow

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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 Turbine manual


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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. Turbine manual


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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.

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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

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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.

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Expansion /Head Tank

Auxiliary Cooling Water Out

Main Cooling Water Inlet

Plant Heat Exchangers Main/Auxiliary Cooling Water Heat Exchangers

Main Cooling Water Outlet

Auxiliary Cooling Water Inlet

Auxiliary Cooling Water Circulating Pumps

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 Turbine manual


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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

Turbine manual

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.


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15.2.1

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

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....................................................................................... 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 ....................................................................................... ....................................................................................... ....................................................................................... ....................................................................................... ....................................................................................... ....................................................................................... ....................................................................................... ....................................................................................... ....................................................................................... ....................................................................................... ....................................................................................... Turbine manual


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

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

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16. Safe Operation of a Turbine

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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.

HP

IP

LP

Condenser Figure 91: Steam flow through a tandem three cylinder turbine

Trainee exercise 6.4.3 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. Turbine manual


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3.

Motion

Steam flows

N

VL

V

P

B

PC 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

Trainee exercise 6.6.1 1. Condensate is drawn from the condenser hotwell by the condensate extraction pump. It is then pumped through Turbine manual


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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 Turbine manual


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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 pressure = 101.7 =

absolute

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

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2. Turbine Manual

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