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Heat Recovery Steam Generator (HRSG) Training Manual

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HRSG Manual Version (1) February 2009 of 91

Module Purpose The aim of this course is to provide participants with the knowledge and skills required for the operation and maintenance of a typical HRSG. The program is structured so as to provide operating staff with an overview of the plant, familiarity with plant locations, and a knowledge of unit operations and plant maintenance requirements.

Module Content By the end of this training, competent participants, shall be able to:

• Locate OEM operating procedures

• Interpret OEM operating procedures

• Describe the major steps in performing a cold start

• Describe the major steps in performing a hot start

• Describe the procedure recommended for altering load

• Describe the major steps in shutting down the unit

• Describe the procedures recommended for HRSG storage.

• Understand the reasons and methods for chemical control.

• Locate and interpret OEM procedures for responding to critical incidents

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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Table of Contents 1. Co-Generation Concepts 6 1.1 System Overview 9 1.2 HRSG Design Considerations 11 1.2.1 GT Exhaust Gas Design Data 13 1.3 Heat Energy Transfer 14 1.3.1 Radiation 14 1.3.2 Conduction 14 1.3.3 Convection 15 1.4 Properties of Steam 17 1.4.1 Wet Steam 17 1.4.2 Dry Saturated Steam 17 1.4.3 Superheated Steam 18 1.4.4 Reason for Superheating Steam 18 1.5 Water/Steam Characteristics 19 1.5.1 Evaporation 19 1.5.2 Shrink & Swell 19 1.5.3 Natural Circulation 20 1.6 Feedwater and Boiler Water Treatment 20 1.6.1 Water Treatment Aims 21 2. Impacts on Pressure Parts Remnant Life 23 2.1 Creep 23 2.2 Fatigue 23 2.3 Creep-Fatigue 24 3. HRSG Construction 25 3.1 Internal Insulation and Liner 25 3.2 Support and Structural Details 25 3.3 Tube Sections Construction 26 4. Major Components of the HRSG 27 4.1 HRSG Economisers 27 4.1.1 Detailed Description 27 4.1.2 Operation & Control 28 4.2 HRSG Drums 29 4.2.1 Detailed Description 30 4.2.2 Operation & Control 31 4.2.2.1 Drum Level Control 31 4.2.3 Technical Data 34 4.3 HRSG Evaporators 35 4.3.1 Detailed Description 35 4.3.2 Operation & Control 36 4.3.3 Technical Data 37 4.4 HRSG Superheaters 37

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4.4.1 Detailed Description 37 4.4.2 Operation & Control 38 4.4.3 Technical Data 40 5. Control of Main HRSG Equipment 41 5.1 HP Steam Temperature Control 42 5.2 ST Bypass System 42 6. Component Alarms 43 7. Start-Up the HRSG 48 7.1 First Boiler Filling 48 7.2 Cold Start of GT + HRSG + STG 48 7.3 Start of Warm HRSG 48 7.4 Start of Hot HRSG 48 7.5 Operational Outline 48 7.6 SYSTEM START-UP 49 7.6.1 Pre-Start Operational Instructions 49 7.6.2 Prerequisites 49 7.6.3 Extra Considerations and Precautions 49 7.6.4 Pre-Start Checklist 52 7.6.5 Instrument Air 55 7.6.6 Remote Operating Valves Function: 55 7.6.7 Closed Cycle Cooling Water System: 57 7.6.8 Check the Valve Open and Close Position for each section: 57 7.6.9 Check the Selection Mode of Controllers and Selection Switch 60 7.6.10 Confirm the Completion: 60 8. System Start-Up Instructions 61 8.1 Procedure for Preliminary water filling and Flushing 61 8.1.1 Start-Up procedure for HRSG 63 9. System Normal Operation 65 9.1 Routine Plant Checks 65 10. System Shutdown Instructions 70 10.1 Normal Shutdown Requirements 70 10.2 Scheduled Shutdown Procedure for Boxing up HRSG 70 11. Emergency Shutdown Procedure 71 11.1 Emergency Shutdown Requirements 71 12. Alarm Responses 72 12.1 Summary of Alarms 72 12.1.1 Alarm Response # 1 72 12.1.2 Alarm Response # 2 73 12.1.3 Alarm Response # 3 73 12.1.4 Alarm Response # 4 74 12.1.5 Alarm Response # 5 74 12.1.6 Alarm Response # 6 75

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12.1.7 Alarm Response # 7 75 12.1.8 Alarm Response # 8 76 12.1.9 Alarm Response # 9 76 12.2 Actions on Non Alarm Faults 77 12.2.1 Gas Leaking from Ducts or HRSG Casing 77 12.2.2 Water and Steam Leaks 77 13. Steam Line Blowing 78 13.1 Introduction 78 13.2 Safety 78 13.3 Steam Blowing Precautions 78 13.4 Steam Blowing Methods 79 13.5 Operating Procedures 80 14. Pre-Operational Chemical Cleaning Procedures 82 14.1 Introduction 82 14.2 Pre-Operational Boilout 82 14.2.1 Preliminary to Boilout 82 14.3 Boil-out Procedures 83 14.4 Post Boil-out Lay-up 86 14.5 Preparations for Putting the HRSG into Service Following Boil-out 86 14.5.1 Prior to Initial HRSG Operation: 86 14.6 Operational Acid Cleaning 87 14.6.1 Introduction 87 14.6.2 Acid Cleaning Procedures 88 15. Valves 89 15.1 Introduction 89 15.2 Pneumatic valves 89 15.2.1 General 89 15.2.2 Blowoff Valves 89 15.2.3 Start Up Vent Valves 89 15.2.4 Drain valves 89 16. Table of Figures 90 17. Table of Tables 91

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1. Co-Generation Concepts Typical applications for steam raising in the HRSG, like the intermediate pressure steam, may be used either to supply the anti-Nox steam system at the gas turbine burners or used to provide process steam, if required. Similarly with the low pressure system, this can provide an additional source of process steam and commonly is also employed to provide deaeration of the feedwater entering the boiler.

The amount of heat which can be transferred from the gas to the water and steam in the HRSG is dependent on two factors:

• The quantity of exhaust gas (mass flow)

• The temperature of the exhaust gas

It is important to note that the steam temperature from any particular section can never be higher than the gas temperature entering that section. Clearly in order to promote a transfer of heat, a temperature differential must exist between the gas and steam. For a typical example, the gas condition entering the high temperature section of the HRSG is at 640ºC at rate of 392kg/s while the HP steam outlet conditions are 568ºC at 102.2 bar and flow rate is 69.84kg/s.

These conditions only apply when the unit is running at rated load. At lower load in a conventional arrangement, the gas flow rate from the gas turbine remains constant, but its temperature falls. As less fuel is mixed with the same quantity of air, the temperature of the gas at both the turbine inlet and exhaust will decrease. For example if the load is decreased by 50%, the exhaust gas temperature only falls by approximately 70ºC.

The steam temperature at the high pressure section has reduced by approximately 80ºC. Moreover the amount of heat available for transfer is less and hence the quantity of steam produced also decreases. A similar reduction in steam temperature and flow rate would occur in the intermediate and low pressure sections. Of course, we should expect the steam flow rate to decrease at lower turbine loads, because there is less heat available in the exhaust gas. But it is the decrease in steam temperature which is more of a concern.

We know that the efficiency of the steam turbine is very much dependent upon maintaining rated steam temperature, so a decrease in efficiency would obviously occur at lower temperature. However a more serious problem, caused by the low steam temperature, may be partial condensation within the turbine with resultant damage to blades.

The relative size of the steam turbine/generator compared with the gas turbine actually depends upon what other energy demands exist. For example a large demand for process steam

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would reduce the quantity available for power generation. However, in most power generation applications the steam turbine generator output will be say 40 – 50% of that of the gas turbine generator.

In such an arrangement it is quite common to operate the steam turbine with the control valves wide open, so that it pulls as much steam as is available from the HRSG.

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Figure 1: Elementary Diagram of a Combined Cycle Plant

Fuel

Cooling Water

Generator

Condenser

Condensate

Feed Pump

Generator

Compressor Turbine

Stack

Combustion chamber

Air

Turbine exhaust

HRSG

Steam Turbine

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HRSG Manual Version (1) June 2008 of 91

In Figure 2 an intermediate section and low pressure section have been added so as to extract more heat from the exhaust gas. An economiser is sometimes installed and this raises the temperature of the incoming feedwater.

Figure 2: HSRG Fitted with HP, IP and LP Steam Sections

1.1 System Overview The HRSG is a dual-pressure level, natural circulation, water tube steam generator. The HRSG is designed to utilise the exhaust heat energy from the gas turbines installed at Power Station.

The function of the Heat Recovery Steam Generator is to convert pressurised water into superheated steam utilising the sensible heat of the gas turbine exhaust gas.

Stack

HRSG

LP Steam

IP Steam

HP Steam

LP HP IP

Gas Turbine

Turbine exhaust

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Exhaust gas from the GT is directed to the HRSG by the inlet transition duct.

The HRSG generates steam in the two-pressure levels, High Pressure (HP) and Low Pressure (LP). The steam generated in a HRSG is used to drive the Steam Turbine (ST) for power generation. The HP and LP superheated steam enters the HP cylinder and LP cylinder of the steam turbine.

The boiler metal components are exposed to high pressure and temperatures. All boiler components are designed for a target life, typically 22 years, while taking into consideration the material properties, expected operating conditions and amount of acceptable degradation.

The theoretical steam produced in The CCCP for two (2) GTs operating at base load and fired with natural gas is about 174360 kg/hr in the HP System; and 38595 kg/hr in the LP System.

The steam operating pressure at the outlet of HP Superheater is 85.4 barg and in the LP Superheater outlet is 8.8 barg. The steam temperatures at the outlet of the Superheaters in HP /LP systems are 532°C and 219°C respectively.

The HRSG has been designed for the following operating conditions:

1. GT generally operates at base load.

2. GT can be fired both by Natural Gas and Distillate Oil.

3. Both the GTs can be operated simultaneously at base load and with Steam Turbine Bypass in operation.

4. The average yearly ambient design basis is 32°C.

5. Twenty two (22) years of Economic Service Life.

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Figure 3: GT Exhaust inlet and HRSG Exhaust outlet

1.2 HRSG Design Considerations The 2 stage HRSG circuits have three (3) major components. These components are the superheaters, evaporators, and economisers. The typical layout for a 3 stage HRSG is shown below.

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Figure 4: Typical HRSG Arrangement

Hot Gas from Gas Turbine Exhaust

Heat from Final Waste

Gas to Atmosphere

IP Steam

HP Steam

Tem

perature

Temperature Gradient across HRSG

Heat in Hot Gas transferred to Water in HRSG creating IP and HP Steam Supply

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1.2.1 GT Exhaust Gas Design Data

Ambient Temperature oC 32 32 GT Fuel Type Natural Gas Distillate Oil Temperature of Exhaust oC 558 559 Exhaust Gas flow tonne/hr 1369 1373.4 Gas Composition N2 72.85 73.61 CO2 3.11 4.20 O2 13.37 13.49 H2O 9.81 7.84 Ar 0.86 0.86 SO2 Not Reported SO3 Not Reported

The HRSG is designed for "Zero Leakage" or gas tight enclosure to contain the heat and duct the GT exhaust gas through the HRSG heat transfer surfaces to the atmosphere. The gas is released to the atmosphere through a stack. The design of the stack is based on design and environmental licence requirements.

The CCPP, the pressure parts components are arranged in series in the gas flow path within the HRSG heating chamber. The boiler circuit is interspersed within the chamber in such a way as to optimize the HRSG thermal conversion performance. Hence the HP Steam evaporative and superheater sections are in the hottest part of the heating chamber.

The high pressure system includes two banks of superheater, drum, evaporator, and two banks of high pressure economisers. The low pressure system includes a superheater, drum, evaporator, and a bank of low pressure economiser.

Pressure part materials are based on the expected operating metal temperatures and pressures, and restricted to those materials listed in the Boiler or Piping Codes. Typical pressure parts are superheater tubes and headers, evaporator tubes and headers, drums, economiser tubes and headers, downcomers and interconnecting piping.

The HRSG casings and ductwork are internally insulated to keep the outer carbon steel casing cool. The internal insulation system consists of ceramic fiber or mineral wool insulation layers covered by a metal liner. The metal liner protects the internal insulation from the high velocity gas stream. The liner is also designed to accommodate the necessary thermal expansion as the HRSG is brought on line.

The liner is anchored to the casing with studs and is composed of a series of panels or plates to minimise the thermal growth of

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the panels. These liner panel attachment studs are welded to the casing. The stud size and spacing pattern is selected according to the velocity, turbulence, and operating temperature of the exhaust gas stream.

1.3 Heat Energy Transfer Heat Transfer is the exchange of heat energy from one media to another. In an HRSG this energy transfer is between GT exhaust gas and HRSG water/steam. This occurs because the GT Gas is at a higher energy level than the water's energy level. The difference in energy level is measured as a temperature differential. The greater the temperature differential the more energy transfer occurs.

Three heat transfer methods or modes have been used to describe this energy exchange. These methods are Radiation, Conduction, and Convection. These terms will be explained in the following paragraphs.

1.3.1 Radiation Radiation energy is transmitted from the flame of a hot source to colder surface without any actual contact being made.

The principal is best illustrated by the light given off by the Sun or a light bulb. When the heat radiation strikes a surface, some of the radiant energy may be reflected or reradiated, some of it may be transmitted through the body, and the remainder will be absorbed. This mode of energy exchange is similar to a line of sight electromagnetic wave phenomenon. As there is no actual naked flame in the GT Exhaust Gas, radiation energy transfer is negligible within an HRSG

1.3.2 Conduction Is a transfer of heat from one part of a substance to another without permanent displacement of the molecules. For example when one end of a metal rod is heated, heat will transfer along the rod making the other end warmer; this is shown below. The ability of a substance to transfer heat by conduction is known as

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its thermal conductivity. Metals are very good conductors of heat, while substances (such as glass) with poor thermal conductivity are known as thermal insulators.

Figure 5: Conduction of heat along metal rod

There is some remnant conduction heat transfer taking place between each of the tubes in an HRSG, but this is largely considered as negligible.

1.3.3 Convection Energy exchange occurs between a stationary surface and a hot fluid or gas moving over the surface. This energy exchange is referred to as Convection. Two regimes of convective heat transfer have been identified, free convection and forced convection. Free Convection is defined as the movement of a fluid or gas over a surface caused solely by the difference in fluid/gas density due to temperature differences. Forced convection requires fluid/gas movement produced by mechanical devices such as fans or a GT. The exchange or transfer rates for Radiation and Conduction can not be changed by increasing the velocity of the fluid/gas. Convective heat transfer rates are enhanced however by increases in fluid/gas velocity

The main source of heat transfer in the HRSG is through forced convection. Convective heat transfer is governed by gas temperature, gas velocity, final steam temperature, initial steam temperature, operating pressure, and surface area. Gas temperature and velocity are dictated by GT operations. Steam temperatures and pressure are set by Steam Turbine Design Parameters. Surface area is established during the HRSG Design phase to maximise the required Final Steam Conditions.

Convective heat transfer is further enhanced through the use of extended surface areas of the metal in the HRSG and superficial gas velocity approaching a maximum of 100 feet per second (fps). Gas velocities beyond 100 fps (30.5 meter per second) run a risk of tube wall erosion and excessive GT exhaust gas back pressure or HRSG pressure drop. The maximum pressure drop for these HRSGs is about 25 inches

Heat transfers

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(635mm) of water column. The extended surface used in the HRSG is produced through the use of finned tubes. Fins are ribbon of steel spirally wrapped around the outside of the tube. Fins may be serrated or solid configuration and are resistance welded to the tube wall.

Figure 6: Typical Finned Water Tube Arrangement

Water tube wall

Boiler casing

Fin

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1.4 Properties of Steam The temperature at which a liquid boils depends on the type of liquid and the surrounding pressure. An increase in pressure raises the temperature at which a liquid will boil and conversely a decrease in pressure reduces the boiling temperature.

The boiling temperature of a liquid is the saturation temperature. The corresponding pressure is the saturation pressure.

Water at standard atmospheric pressure of 101.3 kPa (absolute) will boil at a saturation temperature of 1000C

Steam is water in its gaseous state and tends to behave in the same manner as a gas.

Within the power plant cycle, steam may exist as wet, dry saturated or superheated steam.

1.4.1 Wet Steam Is a mixture of dry saturated steam and water vapour or water particles in suspension. Wet steam is usually present during the conversion of water to steam due to the agitation of the water surface, ejecting water particles into the steam space above. It is also present during the condensation of dry saturated steam back to water. Due to the presence of the water particles, wet steam is visible and is shown in Figure 7.

Figure 7: Wet Steam

1.4.2 Dry Saturated Steam Is steam at its saturation temperature (or boiling point) and which contains exactly the amount of latent heat to convert all the water into steam. Due to the absence of water particles, dry saturated steam is invisible. Refer to diagram below:

Wet steam cloud

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Figure 8: Dry Saturated Steam

Next time you boil water for a cup of coffee or tea; have a careful look at the steam stream coming from the kettle spout. You will be able to observe that immediately adjacent the kettle spout the stream is invisible (dry saturated steam) but as it travels further out it begins to cool and returns to wet steam.

1.4.3 Superheated Steam Superheated steam is at a temperature in excess of the saturation temperature and is produced when heat is absorbed by dry saturated steam. It is a dry invisible gas with the potential to harm or kill if a person was to enter its stream.

1.4.4 Reason for Superheating Steam When steam is supplied to a turbine it gives up heat as it travels through the blade system. As it gives up heat, work occurs on the turbine blades. If the steam was dry saturated steam only, it would immediately begin to become wet steam as it flowed through the turbine. In the early stage of the turbine the steam would drive the blades but as the moisture in the steam increased the blades would drive the steam. Also the impact of the water droplets on the blades would cause erosion along with a reduction in turbine efficiency.

By superheating the steam, most of the work is done by the steam before it begins to become wet steam as only sensible heat an approximately 12% of the latent heat is able to produce work within the turbine.

Wet steam cloud

Stream of invisible dry saturated steam

at exit of kettle spout

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1.5 Water/Steam Characteristics

1.5.1 Evaporation Evaporation or boiling is the process that occurs in the different stages of a typical steam generator circuit. This process changes the state of water from liquid to vapour or steam. The steam is generated at the saturation temperature associated with the operating pressure.

Steam results from adding sufficient heat to water to cause it to vaporize or boil. Boiling occurs in two steps. In Step 1, enough heat is added to the water to raise its temperature close to the boiling point. This occurs in the Economiser. In Step 2, more heat is added to change the state of the water from liquid to steam, known as latent heat of vaporization. This occurs in the Evaporator. The 3rd step is when superheat is added to the dry saturated steam. This occurs in the Superheater.

When water is heated at average sea level atmospheric pressure, each pound of water increases in temperature about 1°F for each Btu added until 212°F (100°C) is reached. Additional heat does not cause the steam temperature to rise in an evaporator section. When water is heated in an evaporator section and steam is generated, an increase in evaporator section pressure occurs. As the pressure increases, the temperature of the boiler water rises. It has been determined experimentally that during the phase change from liquid to steam at constant pressure, the steam in contact with the liquid will remain at constant temperature until boiler vaporization has been completed. Thus, the temperature at which boiling occurs for any given pressure is constant and is called the saturation temperature. This temperature is the same for the water as it is for the steam.

1.5.2 Shrink & Swell The steam bubbles that form within the hot water cause it to expand. "Shrink" and "Swell" are two terms associated with steam and water specific volume characteristics. Shrink is the decrease in the drum water volume that occurs when boiling stops, while swell is the increase in drum level due to increased boiling resulting from an increase in heat absorption. The impact of swell is most noticeable when heat is initially introduced into the HRSG.

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1.5.3 Natural Circulation This refers to the flow of water and steam particles in a closed loop system as shown in the figure below.

This flow takes place because one side of the loop is outside the heat chamber whilst the other is inside the heat chamber, resulting in uneven heating in the loop. As steam bubbles are produced on the heat chamber side, the density reduces. The higher density, cooler water on the outside then flows toward the less dense side, is heated in turn and produces steam bubbles. So the circulation cycle continues.

Figure 9: Simple Diagram of Natural Circulation

1.6 Feedwater and Boiler Water Treatment The successful and reliable operation of steam generating plant depends upon maintaining close control of water chemistry. To control deposits, scale formation and corrosion, not only in the

Source of heat

Steam

Cold water descending

Hot water/steam

rising

Water not turned to

steam i l ti

Feed water replacing

evaporated water lost to atmosphere in form of Steam

bubbles

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boiler but also in the feed lines, feed heaters, economisers, superheaters and prime movers, it is necessary to maintain favourable chemical conditions in the boiler water. This is done by injecting treatment chemicals into the steam drum, and by treatment of the feedwater before it enters the system.

There are a number of experienced water treatment consultants and companies that specialise in the supply of water treatment chemical services. It is recommended that the care and control of water conditions be put in the hands of such specialists unless the plant has adequate analytical facilities and personnel skilled to do it.

Modern steam turbines require a very high standard of steam purity and it is often this requirement that determines the level of salts in the boiler water.

Note: Deviation from industry normal practice can lead to serious problems.

1.6.1 Water Treatment Aims With all its complexity, water treatment has only these simple aims:

To minimise the accumulation of corrosion products from the pre-boiler piping system, such as the oxides of iron, copper, or nickel (these heavy metal oxides invariably plate out on heat transfer surfaces and must be periodically removed by acid cleaning).

To chemically control the normal impurities contained in makeup water, such as calcium, magnesium, and silica. The objectives are to manufacture a soft, porous sludge or to keep the impurities in a solution so that they can be removed by either bottom blowdown or continuous blowdown. (Hard, adherent scales must be avoided because they prevent tube metal cooling by boiler water, generally resulting in tube failures.)

To prevent the carry-over of boiler solids into superheaters or down-stream users, such as turbines or process. (This is usually easily accomplished by limiting total boiler water solids, but occasionally special water problems require the use of anti-foaming agents.)

The following general rules and procedures should be adhered to no matter what type of program is followed:

1. Use care in obtaining samples. Reliable results are dependent upon representative samples. Data must be accurately recorded and analysed. If feedwater or boiler

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water limits are exceeded, the problem should be discussed and the proper course of action decided upon and taken.

2. Oxygen removal should be monitored by periodic testing of the deaerator (without chemical addition). The indigo carmine test for oxygen is widely used for this purpose.

3. Consideration should be given to using multi-test field kits, which contain simple spectrophotometers for performing routine feedwater tests, including iron and copper.

4. Coordinated phosphate treatment relies on precise pH and phosphate measurements requiring greater precision than possible with colour comparators.

5. Protection of the boiler against corrosion should not be limited to when the unit is in operation. Rigid water conditioning standards must also be maintained during lay-up periods.

6. Boiler water silica content should be limited for the particular operating pressure involved. Refer to standard silica vaporisation curves.

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2. Impacts on Pressure Parts Remnant Life The boiler components are exposed to high pressure and temperatures. All boiler components are designed for a target life, typically 22 years, while taking into consideration the material properties, expected operating conditions and amount of acceptable degradation. The "design life" can be maintained or extended by operating and monitoring the units within the guidelines recommended by the designer.

The operation of a unit involves start-up, shutdown, load increase, decrease, steady load operation and emergency conditions resulting in abrupt load changes. If the unit is operated in the failure causing environment, then the design life would be reduced resulting in forced outage or premature retirement.

The failure or damage phenomena in high temperature/thicker components such as SH tubes, SH headers, drums and large bore steam pipelines include high temperature creep fatigue, creep fatigue, embrittlement, hydrogen attack and hot corrosion. For HRSG, which unlike a conventional boiler operate in lower gas temperatures, the hydrogen attack and hot corrosion are of less concern.

2.1 Creep Creep is defined as the deformation of material under stress at an elevated temperature. In a metal tube inside the HRSG the resulting deformation may result in unacceptable dimensional changes and distortion to the extent that even though the tube does not fail heat transfer will be greatly diminished. An example of such deformation is the bowing out of tubes due to expansion. The tubes may be functional but the performance may not be as desired. The creep can also result in failure due to stress-rupture. Creep occurs when a component is either overheated for a short term or kept at temperature above its nominal design limits for a long term.

2.2 Fatigue A component subjected to a repetitive or fluctuating stress will fail at a much lower load than the load applied constantly. This failure is termed as the "Fatigue Failure." Fatigue can be developed by cyclic loading due to temperature alterations and resultant pressure fluctuations which can be experienced during periods of plant trips.

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2.3 Creep-Fatigue This occurs when the conditions associated with both Creep and Fatigue combine. The reasons for this impact are as follows:

1. the extent and rate of temperature change

2. the surface heat transfer coefficient

3. the diameter or thickness of the pressure part

4. thermal concentration factors in high stress region

5. thermal properties of the material

The problem with creep-fatigue is that it is not necessarily apparent until there is a failure. Usually early warning can only be detected by removing samples of tubes in known problem areas and subjecting them to X-ray testing to identify any cracking on the surface.

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3. HRSG Construction 3.1 Internal Insulation and Liner

The HRSG casings and ductwork are internally insulated to keep the outer carbon steel casing cool. The internal insulation system consists of ceramic fibre or mineral wool insulation layers covered by a metal liner. The metal liner protects the internal insulation from the high velocity of GT Exhaust Gas stream. The liner is also designed to accommodate the necessary thermal expansion as the HRSG is brought to its hot operating service conditions. The liner is anchored to the casing with studs. The liner is composed of a series of panels or plates to minimize the thermal growth of the panels. These liner panel attachment studs are welded to the casing. The stud size and spacing pattern is selected according to the velocity, turbulence, and operating temperature of the GT exhaust gas stream.

Insulation and liner deterioration can rapidly lead to severe operating problems. This deterioration may result in thermal expansion problems, higher heat losses to the environment, and hazardous conditions for operators.

3.2 Support and Structural Details The all pressure part sections of HRSGs supplied to the CCCP are suspended from the top, free to expand downward during the operation. The drums are located on top of the roof structure beams. The pressure parts are in eight (8) module boxes per HRSG and have vent and drain lines.

The top support system for sections is achieved through hanging these parts by rods from top support beams outside the top casing. Seismic and wind loads are restrained through the structural members to the foundation.

All superheaters steam outlet delivery headers are located on the top of the HRSG. This placement, in conjunction with top support, minimizes the thermal movement of the steam outlet terminal points. Minimizing bottom placement of the steam headers clears the area directly below the HRSG of all large bore piping obstructions and minimizes the bottom casing penetrations

The HRSG bottom is approximately 2.55m above the floor. This clearance below the bottom casing, elimination of heat bleed paths, and the minimizing of bottom casing penetrations increases the bottom casing cooling.

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The steam drums (high pressure and low pressure systems) are located on top of the HRSG and supported from its bottom. Each drum weight is carried by two saddles and saddle beams; and then transferred to the top transverse beam of the HRSG beneath it. The weight is ultimately transferred by the vertical columns to the HRSG foundation. The saddles slide over saddle beams to accommodate thermal expansion. By this design, the downcomers and evaporator tubes/headers do not carry the drum weight.

3.3 Tube Sections Construction The different heating sections of the HRSG are constructed of finned tubes welded to top and bottom headers in single and three rows per section. Each section has either single pass or multi-pass steam/water flow arrangements. The multi-pass arrangement is on the steam/water side while the gas side is single pass only. Interconnection of tube sections is achieved by multiple 180° return bends made of tubing or pipe. The return bends are of similar material to the modules and are welded to the nozzles on the module headers. This arrangement is referred to as a ‘Platen’

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4. Major Components of the HRSG 4.1 HRSG Economisers

An economizer’s function is to increase water temperature close to the Saturation Temperature, known as Approach Temperature. Approach Temperature is designed to ensure maximum heat energy absorption efficiency and operational flexibility.

Economizers are "Once Thru" heat exchangers, such that each bank of tubes is in series with the next. Economisers can be designed for "Steaming" or Non-Steaming". The selection of steaming versus non-steaming economizers is based on operational consideration, water quality, heat absorption optimisation, and boiler life. Economizers incorporated in the CCCP HRSG are of the non-steaming type.

Figure 10: Section of HRSG Showing External Area of Economiser

4.1.1 Detailed Description Economiser sections are composed of extended or finned tube surface banks. Each economiser section bank is a multipass two or four row module with drains and vents. These modules are arranged in a Series/Parallel configuration to reach the desired final water temperature and capacity.

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Figure 11: Economiser Drains

The HP ECON tube sections are located in the exhaust gas stream according to the dictates of the declining temperature of the exhaust gas and the increasing temperatures of the heated feed water thus providing maximum energy recovery from the GT exhaust. The HP ECON consists of twenty four (24) rows of tubes arranged in eight (8) modules.

4.1.2 Operation & Control The HP feedwater, entering the HP ECON, is discharged from the high pressure stages of the boiler feed pumps. A motorised HP ECON vent valve is located in the HP economiser vent collection header for sliding pressure and partial load operating conditions,. This control valve is operated to allow the release of any trapped steam within this system, particularly at partial load operating conditions (low pressure operation) and thus prevent vapor binding or flashing steam in the HP economiser.

A check valve is located just prior to the FW entering the HP ECON. The check valve is used to allow flow into the HP ECON and to prevent flow in the reverse direction if the FW pumps trip. As the Economiser holds a large amount of water, which is situated high above the FW pumps, reverse flows would cause damage to the FW pipe work and components. The HP ECON section contains vents and drains. These HP ECON vents are used during start up or priming of the system to vent trapped air from the upper headers into the high pressure drum. The HP

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ECON drains are used primarily to drain the sections and flush the economiser section free of sediment during filling of boiler.

No. Description Design

Pressure Design

temperature 1 HP Economiser 1 140.3 BARG 298.9 o C 2 HP Economiser 2 140.3 BARG 176.7 o C 3 LP Economiser 24.1 BARG 176.7 o C

Table 1: Typical Economiser Pressures & Temperatures

4.2 HRSG Drums The CCCP HRSG is equipped with High Pressure and Low Pressure Steam Drums. The steam drums are steam/water separators and storage tanks as well as the provision of chemical injection for steam/water purity requirements.

Figure 12: HRSG HP Drum

Figure 13: LP Drum

Level Column

Drum

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4.2.1 Detailed Description Apart from the function of steam/water separation required for the LPSH, the LP Drum also serves as a water storage tank for the LP Feedwater Systems. There is a take-off line with regulating valve after the LP Economiser which provides Deaerator hot water heating and responds to Deaerator low/low levels. The water level ranges have been selected to provide an adequate margin for safe and reliable pump operation.

The LP steam drum is 1.4 m inside diameter, with a minimum of 17.7mm thick wall with 2: 1 semi ellipsoidal end. The LP steam drum is equipped with two (2) pressure relief safety valves (PSV) mounted vertically on top of the drum. One (1) PSV is set at 10.1 kg/cm2 g to relieve 18390 kg/hr. of saturated steam, and the other PSV is set at 10.4 kg/cm2 psig to relieve 18587 kg/hr. of saturated steam. Both safety valves are closed during normal operation; however, in an over-pressure situation, the PSV’s pop or lift, relieving excess steam pressure.

Figure 14: Drum Safety Valves

The HP steam drum is 1.8 m inside diameter with a minimum of 171.7mm thick wall with full hemispherical end. The high pressure steam drum is equipped with two (2) pressure relief valves (PSV’s) mounted vertically on top of the drum. One (1) PSV is set at 99.0 kg/cm2 to relieve max. 74234 kg/hr of saturated steam and the other PSV is set at 102.1 kg/cm2 to relieve max.74847 kg/hr of saturated steam. Both PSV’s are

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closed during normal operation; however, in an over-pressure situation, the HPSH PSV will lift or pop first, relieving excess steam. If the pressure continues to build, the HP drum PSV’s will lift.

4.2.2 Operation & Control Drum boilers operate in the area on or under the saturation curve. The HP steam drum receives the hot HP ECON outlet feedwater and distributes/mixes it with the existing drum water. The water is then fed to the HP evaporator through the downcomers, feeder headers, and feeder tubes. Steam bubbles are created and as a result of the variation in density in the evaporator loop, the steam and water rises to the HP steam drum via the riser tubes or riser collection header, thus completing the natural circulation loop.

The Steam/Water mixture entering the drum from the riser tubes is usually 5% to 30% steam, depending on the boiler load and pressure. Staying at low quality levels protects the tubes from overheat failures due to the nature of the boiling process. In the steam drum, saturated steam is separated from the steam/water mixture. The separated steam rises up through the drum as feedwater enters the drum from the economiser. The separated water from the steam/water mixture is then recirculated together with the feedwater to the heat absorbing evaporator tubes through the circulation loop. The steam/water separation is done through a combination of gravity and mechanical components.

4.2.2.1 Drum Level Control Drum steam/water separation is reliant on maintaining the water level in the drum at approximately the ½ way level of the gauge glass. This water level is referred to as the Normal Water Level (NWL). Maintaining NWL ensures a free controlled surface for steam/water mixture separation and proper operation of the primary separation equipment. High drum level will increase carryover to downstream equipment. In extreme cases, the steam lines can become flooded. Carryover can result in superheater tube contamination due to even slight amounts of chemicals and impurities in the boiler water. Low drum level can cause circulation problems by restricting flow to the downcomers which, in turn, supply the evaporator circuits. This ultimately results in evaporator tube overheating and failure. Excessive low water level (LLWL) in the HP/LP drums will cause a trip of HRSG.

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Figure 15: Drum Level Control Valves

The drum level is controlled by a single element control (during start up) or three element control (during normal operation). The input for the single element controller is drum level only. However once steam pressure is established and feeding forward to the turbine is possible, drum level on it’s own is not enough to give an accurate level indication.

The inputs for the three element controller are steam flow, feed water flow and drum level. It also incorporates a drum pressure compensation signal. There are three inputs per each signal for back up. The control system will take an average of two signals out of three, or if one fails will take the lowest reading. At the high water level (HWL) alarm the drum level control valve will be closed and the intermittent blowdown valve will be opened to blow down the level in the drum from high level to normal level.

In the CCCP HRSG drums, the separation of steam from the steam/water mixture generated usually takes place in two steps. Primary separation removes nearly all of the water from the mixture, so that in effect, no steam is recirculated to the boiler water. However, the steam may still contain some water and solid contaminants which must be removed or reduced in amount before the steam is sufficiently pure for use. This step is called secondary separation or steam scrubbing.

Primary steam separation is accomplished with cyclone steam separators (for the HP steam drums) or an impact plate (for the LP steam drum).

Further steam scrubbing of any trace amounts of water or contaminants in the steam is achieved by the secondary scrubbers. Located at the top of the steam drum, these corrugated plates provide a large surface which intercepts water particles as the steam weaves through the closely fitted plates. Steam velocity through the corrugated plate assembly is very low, so that re-entrainment of water is avoided. The collected water is

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drained from the bottom of the scrubber assembly to the water below.

Figure 16: Cyclone Separator Internals

Figure 17: Steam Drum Internal

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The drum is also designed to act as a storage tank or reservoir, allowing the boiler to accommodate upsets in feed pump operation and to “smooth out” transient drums level excursions during load swings. The steam drum acts as a contact vessel for internal boiler water treatment by chemicals. Continuous blowdown for reduction of solids concentration in the boiler water is an integral part of the chemical water treatment process.

Figure 18: HRSG Drum Blowdown Vessel

4.2.3 Technical Data HRSG process function is to extract sensible heat energy from the GT exhaust and produce steam. Based on various operating conditions, the maximum steam parameters in each pressure system for Natural Gas fired are given below:

System Description Rated condition Unit

High Pressure System Flow Pressure Temperature

348720 83.4 530

Kg/hr. bar(a) o C

Low pressure system Flow Pressure Temperature

77190 7.8 218

Kg/hr. bar(a) o C

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4.3 HRSG Evaporators

4.3.1 Detailed Description In the evaporation circuit the water is heated to as close to saturation temperature as is possible. This process changes the water from liquid to vapour or steam. It should be understood that the water in the HRSG is under pressure. Therefore this liquid to vapour state can only be achieved at extremely high temperatures. A comparison table between saturation temperature and pressure is in Table 2. Note that as the pressure increases the amount of heat energy required to raise the water temperature to saturation increases also.

Absolute

pressure

(kPa)

Saturation

temperature 0C

Heat Energy

kJ/kg

5 33 138

8.5 36.7 154

101.3 100 420

1000 180 763

3000 234 1008

4000 250 1087

6400 280 1233

10000 311 1399

16000 346 1645

22120 347.2 2107.4

Table 2: Steam Table Example

The LP EVAP section consists of twelve (12) rows of tubes, arranged in four (4) banks. The banks are all single pass, with flow from bottom to top and with no internal baffles in upper and lower headers. The tubes are oriented in this direction to allow steam bubbles generated to rise via the riser tubes to the steam drum. Water is fed to the tubes from the downcomer feeder header assemblies. This is referred to as a natural circulation loop.

The HP EVAP section consists of eighteen (18) rows of tubes located in six (6) sections. The HP EVAP is split or separated into

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two (2) subsections. Subsection 1 (referencing the gas flow) located at the back of box 2 contains nine(9) rows of tubes in three (3) sections, subsection 2 located at the front of box 3 contains again nine (9) rows of tubes in three (3) sections.

Figure 19: HP Drum Showing Downcomer Pipes 4.3.2 Operation & Control

Evaporator sections are where the boiling process or steam generation occurs. As heat energy is absorbed by water from the gas stream, the water temperature increases. When water reaches the boiling point or saturation temperature, some of the water evaporates or vaporises to steam.

The CCCP evaporator sections are typically single pass two and three row sections. The single pass is on the water side and is vertically upward. The system feed a steam/water mixture to the riser tubes. The downcomers are fed with water from the downcomers/feeder header assembly to replace the water exiting as a steam/water mixture.

In the LP NAP section, the water phase change between liquid and steam occurs. This phase change occurs due to the convective heat transfer or energy exchange between the GT exhaust gas stream and the water in the LP NAP tubes. The LP NAP tubes are components in the Natural Circulation Loop.

The lower downcomer crossover header located at the bottom of the system contains intermittent blowdown (IBD) connection. The Low Pressure Evaporator intermittent blowdown (IBD) is designed to remove any sludge or contaminates formed in the LPSG evaporator water and to maintain boiler water chemistry within limits. The IBD can be used to lower the drum level during start up to avoid unnecessary high drum level trips.

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In the HP EVAP section, the phase change between water and steam occurs. This phase change occurs due to the convective heat transfer or energy exchange between the CT exhaust gas stream and the water in the HP EVAP tubes. The HP NAP tubes are a component in the Natural Circulation Loop. The lower downcomer crossover headers located at the bottom of the system contain startup/intermittent blow-off connections. These are designed to remove any sludge or contaminates formed in the HPSG evaporator water and to maintain boiler water chemistry within limits. The IBD can be used to lower the drum level during start up to avoid unnecessary high drum level trips. This header is also equipped with connections for chemical cleaning, sparging steam, and start-up drain.

4.3.3 Technical Data

No. Description Design Pressure

Design temperature

1 HP Evaporator 99.1 BARG 310 o C 2 LP Evaporator 12.4 BARG 185 o C

Table 3: Typical Evaporator Pressure & Temperatures

4.4 HRSG Superheaters

4.4.1 Detailed Description The major function of superheater is to increase the pressurized water temperature above the steam saturation temperature for use in the steam turbine. Saturated steam is considered as “dry” steam. Steam below saturation temperature would still contain water droplets, which can cause damage to a steam turbine.

The Superheater absorbs heat energy from the GT exhaust gas and transfers this energy to the steam. The steam superheat energy level is measured as an increase in steam temperature beyond the steam temperature achieved in the evaporator section. Superheater sections typically have the highest metal temperatures in the HRSG.

Superheater sections are composed of extended or finned tube surface modules. The CCCP High and Low pressure modules are one steam pass modules. These sections are arranged in a Series-Parallel configurations to reach the desired final steam temperature and capacity.

The LPSH consists of two (2) rows of tubes in two (2) modules i.e. one row per module. The modules have one (1) pass on steam

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side with the steam entering the top header and exits from the bottom header. Steam on the inside of the tubes is received from the low pressure steam drum and is heated from saturation to 219°C (maximum). The LPSH is not equipped with a final steam temperature control system for attemperation. Steam leaving the LPSH is fed to the low pressure cylinder of the steam turbine.

The HPSH consists of eighteen (18) rows of tubes arranged in six (6) modules. Steam on the inside of the tubes is received from the high pressure steam drum at saturated temperature. The maximum steam temperature at the inlet of Main Stop Valve is 535°C. These modules are top supported to minimise thermal expansion considerations for the outlet header piping. These modules are constructed of chrome-molly alloyed carbon steel (SA 335 P 22) material designed for high temperature operation. HPSH subsection 1 (referencing the gas flow) contains two (2) modules with six (6) tube rows providing a single steam side pass from bottom to top. HPSH subsection 2 contains four (4) modules with twelve (12) tube rows providing a single pass from top to bottom. The steam flow from the top headers of HPSH subsection 2 to HPSH sub-section 1 passes through an attemperator loop.

4.4.2 Operation & Control Drainable superheaters are employed in the HRSG design to ensure that any liquid water accumulated in the lower headers are removed during start up. The water may be there as a result of the filling process or condensate formed during the purge of a "Hot' or 'Warm" Start. Drainable superheaters allow the CCCP HRSG to startup following the GT Exhaust Gas flow ramp.

The LP Superheater is fitted with a one (1) PSV, set to lift at 9.8 kg/cm2 to relieve a max of 9064 kg/hr of steam at 219°C. The PSV is mounted on the LP main steam outlet. The PSV is closed during normal operation; however, in an over-pressure situation, the safety valve pops, or lifts, relieving the excess steam pressure until the system pressure is reduced to the desired level. The LPSH PSV and the LP drum PSVs provide 100% relieving capacity as required by Boiler Code, Section I for personnel and equipment protection.

The LPSH modules are designed as drainable superheaters. This enables the superheater modules to be completely drained prior to startup. The LP superheater drains are used for the removal of condensate formed during the purge portion of HOT or WARM start ups, draining of hydro water and draining / flushing during chemical cleaning. The LPSH is equipped with vents to eliminate non-condensable gasses at startup and to release any

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air pockets to LP drum, during boiler commissioning. The LPSH vent is included with a silencer to control noise.

The HP superheater outlet is equipped with a pressure relief valve (PSV) set at 96.5 kg/ cm2g to relieve max 37882 kg/hr of superheated steam at a final steam temperature of 535°C. The PSV is closed during normal operation; however, in an over-pressure situation, the safety valve pops, or lifts, relieving the excess steam pressure until the system pressure is reduced to the desired level. If the system pressure continues to increase, the PSVs on the HP drum will open.

The HP Superheater is equipped with an interstage attemperator manufactured by the Nippon Keystone Corporation. The attemperator is a self contained control valve and spray nozzle assembly and located in the pipeline connecting HPSH subsection 2 and subsection 1. The attemperator is supplied for final steam temperature control. The spray attemperation process uses water as the cooling media. The spray water is directly fed to the attemperator from the HP Economiser 2 outlet line. Final steam temperature control is important for protection of the superheater and equipment served by the HRSG. The attemperation is designed to limit final steam temperature at HP superheater outlet to max 535oC (final rated temperature).

Figure 20: Typical Direct Spray Attemperator

Steam temperature sensing elements are located in the HP superheater outlet header. The HPSH modules are designed as drainable superheaters. This enables the superheater modules to be completely drained prior to startup. The HP superheater drains are used for the removal of condensate formed during the purge portion of HOT or WARM startups, draining of hydro water and draining /flushing during chemical cleaning. The HPSH

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modules and outlet header are equipped with vent valves to vent non-condensables at startup and to release any air pockets during boiler commissioning.

4.4.3 Technical Data

No. Description Design Pressure

Design Temperature

1 HP Superheater 97.2 BARG 560 o C 2 LP Superheater 12.4 BARG 185 o C

Table 4: Typical Evaporator Pressure & Temperatures

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5. Control of Main HRSG Equipment The HRSG has several critical control devices. These devices control steam temperature and water level in the drums. The drum level controls were discussed in detail earlier. Steam temperature is a function of heat energy input and steam pressure. The steam pressure in the HRSG is a function of FW pressure and ST loading requirements. Before optimal steam pressure can be reached however, it is important that the steam temperature is raised in such a way as to maximise plant and material life. The most accurate method of determining the optimal temperature rise is to measure heat input versus steam pressure.

The graph of GT load and Steam Pressure is shown in Figure 21 below for the HRSG.

Figure 21: GT load and Steam Pressure

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5.1 HP Steam Temperature Control This was discussed earlier.

5.2 ST Bypass System The ST bypass system can accept 2 x 100% HRSG steam production and is operated when the steam turbine is tripped. The HRSG HP/LP steam pressure is controlled by HP/LP ST bypass. The temperature is reduced by HP/LP steam attemperator

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6. Component Alarms

Alarm Title Alarm Level Set Point HRGS1 LP DRUM CONT BLOW V :LOCK LOW ---- HRGS1 LP DRUM CONT BLOW V :FAULT HIGH ---- HRGS1 LP DRUM CONT BLOW V :LOCAL LOW ---- HRGS1 LP DRUM DRN VLV :LOCK LOW ---- HRGS1 LP DRUM DRN VLV :FAULT HIGH ---- HRGS1 LP DRUM DRN VLV :LOCAL LOW ---- HRGS1 HP DRUM CONT BLOW V :LOCK LOW ---- HRGS1 HP DRUM CONT BLOW V :FAULT HIGH ---- HRGS1 HP DRUM CONT BLOW V :LOCAL LOW ---- HRGS1 HP DRUM DRN VLV :LOCK LOW ---- HRGS1 HP DRUM DRN VLV :FAULT HIGH ---- HRGS1 HP DRUM DRN VLV :LOCAL LOW ---- HRGS1 HP SH1 DRNVLV :LOCK LOW ---- HRGS1 HP SH1 DRNVLV :FAULT HIGH ---- HRGS1 HP SH1 DRNVLV :LOCAL LOW ---- HRGS1 LP ECO AIRVENT VLV :LOCK LOW ---- HRGS1 LP ECO AIRVENT VLV :FAULT HIGH ---- HRGS1 LP ECO AIRVENT VLV :LOCAL LOW ---- HRGS1 HP FWT STPVLV :LOCK LOW ---- HRGS1 HP FWT STPVLV :FAULT HIGH ---- HRGS1 HP FWT STPVLV :LOCAL LOW ---- HRGS1 HP ECO AIRVENT VLV :LOCK LOW ---- HRGS1 HP ECO AIRVENT VLV :FAULT HIGH ---- HRGS1 HP ECO AIRVENT VLV :LOCAL LOW ---- HRGS1 LP ECO STARTUPVENT VLV :LOCK LOW ---- HRGS1 LP ECO STARTUPAIRVENT VLV :FAULT HIGH ---- HRGS1 LP ECO STARTUPAIRVENT VLV :LOCAL LOW ---- HRGS1 LP STM STPVLV :LOCK LOW ---- HRGS1 LP STM STPVLV :FAULT HIGH ---- HRGS1 LP STM STPVLV :LOCAL LOW ---- HRGS1 LP STM STBYP VLV :LOCK LOW ---- HRGS1 LP STM STBYP VLV :FAULT HIGH ---- HRGS1 LP STM STBYP VLV :LOCAL LOW ---- HRGS1 LP STM DRNVLV :LOCK LOW ---- HRGS1 LP STM DRNVLV :FAULT HIGH ---- HRGS1 LP STM DRNVLV :LOCAL LOW ---- HRGS1 HP STARTUPVENT VLV :LOCK LOW ---- HRGS1 HP STARTUPVENT VLV :FAULT HIGH ---- HRGS1 HP STARTUPVENT VLV :LOCAL LOW ---- HRGS1 HP STM STPVLV :LOCK LOW ---- HRGS1 HP STM STPVLV :FAULT HIGH ---- HRGS1 HP STM STPVLV :LOCAL LOW ---- HRGS1 HP STM STPBYP V :LOCK LOW ---- HRGS1 HP STM STPBYP V :FAULT HIGH ---- HRGS1 HP STM STPBYP V :LOCAL LOW ---- HRGS1 HP STM DRNVLV :LOCK LOW ---- HRGS1 HP STM DRNVLV :FAULT HIGH ----

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Alarm Title Alarm Level Set Point HRGS1 HP STM DRNVLV :LOCAL LOW ---- HRGS1 BWS STP VLV1 :LOCK LOW ---- HRGS1 BWS STP VLV1 :FAULT HIGH ---- HRGS1 BWS STP VLV1 :LOCAL LOW ---- HRGS1 BWS STP VLV2 :LOCK LOW ---- HRGS1 BWS STP VLV2 :FAULT HIGH ---- HRGS1 BWS STP VLV2 :LOCAL LOW ---- HRGS1 LP DRUM LVL INTERLOCK :BYPASS LOW HRGS1 LP DRUM LVL-1 :L-LOW CRITICAL -500mm HRGS1 LP DRUM LVL :L-LOW CRITICAL -500mm HRGS1 LP DRUM LEVEL :LOW LOW -100mm HRGS1 LP DRUM LEVEL :HIGH LOW 100mm HRGS1 LP DRUM LVL-1 :HI-HI CRITICAL 250mm HRGS1 LP DRUM LVL :HI-HI CRITICAL 250mm HRGS1 LP DRUM LVL-2 :L-LOW CRITICAL -500mm HRGS1 LP DRUM LVL-2 :HI-HI CRITICAL 250mm HRGS1 LP DRUM LVL-3 :L-LOW CRITICAL -500mm HRGS1 LP DRUM LVL-3 :HI-HI CRITICAL 250mm HRGS1 LP DRUM LVL-1 :TROUBLE LOW ---- HRGS1 LP DRUM LVL-2 :TROUBLE LOW ---- HRGS1 LP DRUM LVL-3 :TROUBLE LOW ---- HRGS1 LP STM DRUM PRESS :HIGH LOW 9.4barG HRGS1 LP STM DRUM PRESS :HI-HI HIGH 9.9barG HRGS1 LP STM DRUM LVL DIFF 1-2 :H LOW +/-50mm HRGS1 LP STM DRUM LVL DIFF 1-3 :H LOW +/-50mm HRGS1 LP STM DRUM LVL DIFF 2-3 :H LOW +/-50mm HRGS1 HP DRUM LVL-1 :L-LOW CRITICAL -750mm HRGS1 HP DRUM LVL :L-LOW CRITICAL -750mm HRGS1 HP DRUM LVL :HI LOW 100mm HRGS1 HP DRUM LVL :LOW LOW -100mm HRGS1 HP DRUM LVL-1 :HI-HI CRITICAL 150mm HRGS1 HP DRUM LVL :HI-HI CRITICAL 150mm HRGS1 HP DRUM LVL-2 :L-LOW CRITICAL -750mm HRGS1 HP DRUM LVL-2 :HI-HI CRITICAL 150mm HRGS1 HP DRUM LVL-3 :L-LOW CRITICAL -750mm HRGS1 HP DRUM LVL-3 :HI-HI CRITICAL 150mm HRGS1 HP DRUM LVL-2 :TROUBLE LOW ---- HRGS1 HP DRUM LVL-3 :TROUBLE LOW ---- HRGS1 HP STM DRUM PRESS :HIGH LOW 94.5barG HRGS1 HP STM DRUM PRESS :HI-HI CRITICAL 97.0barG HRGS1 HP STM DRUM LVL DIFF 1-2 :H LOW +/-50mm HRGS1 HP STM DRUM LVL DIFF 1-3 :H LOW +/-50mm HRGS1 HP STM DRUM LVL DIFF 2-3 :H LOW +/-50mm HRGS1 LP DRUM LVL CV-1 FAULT LOW ---- HRGS1 LP DRUM LVL CV-2 FAULT LOW ---- HRGS1 HP DRUM LVL CV-1 FAULT LOW ---- HRGS1 HP DRUM LVL CV-2 FAULT LOW ---- B1 HP STM DSH CV-1 FAULT :FAULT LOW ---- B1 HP STM DSH CV-2 FAULT :FAULT LOW ---- HRGS1 LP SH OUTL STM PRESS :HIGH LOW 9.6barG HRGS1 LP SH OUTL STM TEMP :LOW LOW 170ºC

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Alarm Title Alarm Level Set Point P DIFF HRGS1/MAIN LP S :HIGH LOW 0.5barG P DIFF HRGS1/MAIN LP S :LOW LOW -1.0barG HRGS1 HP SH OUTL STM FLOW :HI-HI HIGH 208.0 T/H HRGS1 HP SH OUTL STM PRESS :HIGH LOW 94.6barG HRGS1 HP SH OUTL STM TEMP :LOW LOW 350ºC HRGS1 HP SH OUTL STM TEMP :HIGH LOW 544ºC HRGS1 HP SH OUTL STM TEMP :HI-HI HIGH 558ºC HRGS1 LP SAT. STM CONDCT :HIGH LOW 0.3µS/cm HRGS1 HP STM DRUM PRESS :LOW LOW 43.1barG HRGS2 HP SH OUTL STM PRESS :HIGH LOW 94.6barG HRGS2 LP DRUM CONT BLOW V :LOCK LOW ---- HRGS2 LP DRUM CONT BLOW V :FAULT HIGH ---- HRGS2 LP DRUM CONT BLOW V :LOCAL LOW ---- HRGS2 LP DRUM DRN VLV :LOCK LOW ---- HRGS2 LP DRUM DRN VLV :FAULT HIGH ---- HRGS2 LP DRUM DRN VLV :LOCAL LOW ---- HRGS2 HP DRUM CONT BLOW V :LOCK LOW ---- HRGS2 HP DRUM CONT BLOW V :FAULT HIGH ---- HRGS2 HP DRUM CONT BLOW V :LOCAL LOW ---- HRGS2 HP DRUM DRN VLV :LOCK LOW ---- HRGS2 HP DRUM DRN VLV :FAULT HIGH ---- HRGS2 HP DRUM DRN VLV :LOCAL LOW ---- HRGS2 HP SH1 DRNVLV :LOCK LOW ---- HRGS2 HP SH1 DRNVLV :FAULT HIGH ---- HRGS2 HP SH1 DRNVLV :LOCAL LOW ---- HRGS2 LP FWT STPVLV :LOCK LOW ---- HRGS2 LP FWT STPVLV :FAULT HIGH ---- HRGS2 LP FWT STPVLV :LOCAL LOW ---- HRGS2 DEAER HW STP VLV :LOCK LOW ---- HRGS2 DEAER HW STP VLV :FAULT HIGH ---- HRGS2 DEAER HW STP VLV :LOCAL LOW ---- HRGS2 LP ECO AIRVENT VLV :LOCK LOW ---- HRGS2 LP ECO AIRVENT VLV :FAULT HIGH ---- HRGS2 LP ECO AIRVENT VLV :LOCAL LOW ---- HRGS2 HP FWT STPVLV :LOCK LOW ---- HRGS2 HP FWT STPVLV :FAULT HIGH ---- HRGS2 HP FWT STPVLV :LOCAL LOW ---- HRGS2 HP ECO AIRVENT VLV :LOCK LOW ---- HRGS2 HP ECO AIRVENT VLV :FAULT HIGH ---- HRGS2 LH ECO AIRVENT VLV :LOCAL LOW ---- HRGS2 LP STARTUPVENT VLV :LOCK LOW ---- HRGS2 LP STARTUPVENT VLV :FAULT HIGH ---- HRGS2 LP STARTUPVENT VLV :LOCAL LOW ---- HRGS2 LP STM STPVLV :LOCK LOW ---- HRGS2 LP STM STPVLV :FAULT HIGH ---- HRGS2 LP STM STPVLV :LOCAL LOW ---- HRGS2 LP STM STPBYP VLV :LOCK LOW ---- HRGS2 LP STM STPBYP VLV :FAULT HIGH ---- HRGS2 LP STM STPBYP VLV :LOCAL LOW ---- HRGS2 LP STM DRNVLV :LOCK LOW ---- HRGS2 LP STM DRNVLV :FAULT HIGH ----

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Alarm Title Alarm Level Set Point HRGS2 LP STM DRNVLV :LOCAL LOW ---- HRGS2 HP STARTUPVENT VLV :LOCK LOW ---- HRGS2 HP STARTUPVENT VLV :FAULT HIGH ---- HRGS2 HP STARTUPVENT VLV :LOCAL LOW ---- HRGS2 HP ST STP VLV :LOCK LOW ---- HRGS2 HP ST STP VLV :FAULT HIGH ---- HRGS2 HP ST STP VLV :LOCAL LOW ---- HRGS2 HP STM STPBYP V :LOCK LOW ---- HRGS2 HP STM STPBYP V :FAULT HIGH ---- HRGS2 HP STM STPBYP V :LOCAL LOW ---- HRGS2 HP ST DRN VLV :LOCK LOW ---- HRGS2 HP ST DRN VLV :FAULT HIGH ---- HRGS2 HP ST DRN VLV :LOCAL LOW ---- HRGS2 BWS STP VLV1 :LOCK LOW ---- HRGS2 BWS STP VLV1 :FAULT HIGH ---- HRGS2 BWS STP VLV1 :LOCAL LOW ---- HRGS2 BWS STP VLV2 :LOCK LOW ---- HRGS2 BWS STP VLV2 :FAULT HIGH ---- HRGS2 BWS STP VLV2 :LOCAL LOW ---- HRGS2 LP DRUM LVL INTERLOCK :BYPASS LOW HRGS2 LP DRUM LVL-1 :L-LOW CRITICAL -500mm HRGS2 LP DRUM LVL :L-LOW CRITICAL -500mm HRGS2 LP DRUM LEVEL :LOW LOW -100mm HRGS2 LP DRUM LEVEL :HIGH LOW 100mm HRGS2 LP DRUM LVL-1 :HI-HI CRITICAL 250mm HRGS2 LP DRUM LVL :HI-HI CRITICAL 250mm HRGS2 LP DRUM LVL-2 :L-LOW CRITICAL -500mm HRGS2 LP DRUM LVL-2 :HI-HI CRITICAL 250mm HRGS2 LP DRUM LVL-3 :L-LOW CRITICAL -500mm HRGS2 LP DRUM LVL-3 :HI-HI CRITICAL 250mm HRGS2 LP DRUM LVL-1 :TROUBLE LOW ---- HRGS2 LP DRUM LVL-2 :TROUBLE LOW ---- HRGS2 LP DRUM LVL-3 :TROUBLE LOW ---- HRGS2 LP STM DRUM PRESS :HIGH LOW 9.4barG HRGS2 LP STM DRUM PRESS :HI-HI HIGH 9.9barG HRGS2 LP STM DRUM LVL DIFF 1-2 :H LOW +/-50mm HRGS2 LP STM DRUM LVL DIFF 1-3 :H LOW +/-50mm HRGS2 LP STM DRUM LVL DIFF 2-3 :H LOW +/-50mm HRGS2 HP DRUM LVL NTERLOCK :BYPASS LOW HRGS2 HP DRUM LVL-1 :L-LOW CRITICAL -750mm HRGS2 HP DRUM LVL :L-LOW CRITICAL -750mm HRGS2 HP DRUM LVL :HI LOW 100mm HRGS2 HP DRUM LVL :LOW LOW -100mm HRGS2 HP DRUM LVL-2 :L-LOW CRITICAL -750mm HRGS2 HP DRUM LVL-2 :HI-HI CRITICAL 150mm HRGS2 HP DRUM LVL-3 :L-LOW CRITICAL -750mm HRGS2 HP DRUM LVL-3 :HI-HI CRITICAL 150mm HRGS2 HP DRUM LVL-1 :TROUBLE LOW ---- HRGS2 HP DRUM LVL-2 :TROUBLE LOW ---- HRGS2 HP DRUM LVL-3 :TROUBLE LOW ---- HRGS2 HP STM DRUM PRESS :HIGH LOW 94.5barG

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Alarm Title Alarm Level Set Point HRGS2 HP STM DRUM PRESS :HI-HI CRITICAL 97.0barG HRGS2 HP STM DRUM LVL DIFF 1-2 :H LOW +/-50mm HRGS2 HP STM DRUM LVL DIFF 1-3 :H LOW +/-50mm HRGS2 HP STM DRUM LVL DIFF 2-3 :H LOW +/-50mm

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7. Start-Up the HRSG The following procedures are to be carried out to start-up the HRSG:

7.1 First Boiler Filling Prior to starting the plant, the HRSG tubes shall be filled with feed water to the normal start up level as indicated in the HP and LP drums.

This is carried out by pumping water from Demineralised Water Tank. In order to avoid thermal shocks or water hammering with flashing off of steam, the boiler must be cold (including the heat exchangers, piping, drums) prior to admitting water to the boiler.

7.2 Cold Start of GT + HRSG + STG The GT, HRSG and ST can be automatically started through the Automatic Plant Start-up Program.

The initial conditions of each part of the plant must be met prior to initiating an AUTO START.

7.3 Start of Warm HRSG Refer to the CCPP start-up procedure and warm start up curves.

7.4 Start of Hot HRSG Refer to the CCPP start-up procedure and hot start up curves.

7.5 Operational Outline HRSG is started as part of the Combined Cycle Power Plant (CCPP) start-up operating procedure. The CCPP is started in Automatic sequence after pre-start preparations are completed. The automatic sequence starts the following systems:

1. Service air system

2. Instrument air system

3. Fire Hydrant and Auto Sprinkler Systems Ready

4. CO2 Fire Protection Systems Ready

5. Demineralised water system.

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6. Make –up water system

7. Closed Cycle Cooling Water system

8. Steam Turbine Auxiliaries.

9. Condensate Water system

10. High Pressure BFP System.

11. Low Pressure BFP System.

12. Initial water filling for HRSG HP drum

13. Initial water filling for HRSG LP drum

14. Gland steam system

15. Vacuum Raising & ACC system

16. CCPP system

7.6 SYSTEM START-UP

7.6.1 Pre-Start Operational Instructions In this section the following items are described.

1. HRSG Start-up Preparation Procedure

2. HRSG Preliminary Water Filling and Flushing Procedures

7.6.2 Prerequisites If the HRSG was shut down for maintenance, prior to re-starting the plant must be returned to operations personnel control and all safety permits to work must be cleared.

Prior to handing the plant back, Maintenance must ensure that the equipment is serviceable and cleared of all debris both internally and externally.

Once the permits have been cleared the Operators are to return the plant to operational-ready condition.

7.6.3 Extra Considerations and Precautions

1. Ensure all trip relays have been reset.

2. The plant can be started to achieve closed cycle mode provided the HRSG is purged. This is done during run-up of the gas turbine shaft prior to ignition and for usually for a period corresponding to 5 volume charges of the HRSG

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3. While the HRSG is in the process of heating up, frequent checks should be made to the thermal expansion of the boiler and gas duct.

4. As soon as the heat is introduced into the HRSG chamber, the water level in the drum gauge glass will rise due to the expansion of the water.

5. Care must be taken that the water level is maintained at the levels specified values by operation of the intermittent blowdown valves.

6. Prior to starting any pumps they should be adequately primed and have a proper discharge head of pressure to avoid damage to the pump and associated pipe work as a result of fluid hammer and stress. If this is not possible the pump should not be started except with discharge valves closed.

7. Be careful not to reduce pump flow to less than the minimum flow described in the data sheet at any time. Otherwise it may cause the fluid temperature to rise inside the pump resulting in vapor pockets forming and cavitations or in the case of a chemical solution could accelerate internal corrosion.

8. If the drum water levels are observed to be increasing during steady-state operation, the boiler feed water control valve(s) may require to be exercised as they may be subject to sticking spindles.

9. The most important rule in the safe operation of a natural circulation boiler is to keep the water as near the normal water level as conditions will permit.

10. During normal operation more frequent intermittent blowdown may be necessary when trouble is experienced with boiler chemical imbalance, foaming, priming and other feed water troubles. However experience may indicate that less frequent intermittent blowdowns are desirable. The frequency of intermittent blowdowns should be determined by regular checks of the water chemistry and the control of the water levels.

11. When on continuous operation the boiler water should be blown down once a month. This is achieved by opening the HP/LP intermittent manual blow down valves. Blowdown should be maintained until a maximum water level decrease in the Drum of 50 mm is achieved.

The amount of blow down valve opening is usually determined by the following formula and Cv curves.

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Cv=1.17X * F/(ρ * ΔP)^0.5

Cv: Flow coefficient of blowdown valve

X: Rate of blowdown (Usually determined by Chemist when plant is on-line)

F: Feed water flow (t/h)

ρ: Specific gravity of boiler water (t/m3)

ΔP: Differential pressure of valve (bar)

12. Gauge glass lights should be maintained and the glasses kept clean. Steam or water should not be allowed to leak from the gauge glass connections, as this will cause the gauge glasses to show a false level.

13. Each drum and boiler safety valve should be checked periodically to ensure that it is open and free to operate. It is recommended that a specialist from the original valve manufacturer be used for checking safety valves. The valve manufacturer will normally be able to provide the tools and a technician to check the operating pressure and assist in restoring the valves to the optimum performance level.

14. Perform all boiler water and boiler feed water tests as directed by the Chemical Engineer. Adjust dosages etc accordingly.

15. Except for control valves, all other valves must be either fully open or fully closed and must not be left partially open. Non-control valves will wear the seat of the valve section rapidly when only partially open. If difficulty is experienced in closing a valve due to an obstruction between the valve and its seat, do not try to close the valve forcibly but open and close the valve several times to flush away the obstruction by the pressure of transferred liquid and then close the valve.

16. Initial opening of drains and vents allows condensate to escape and warm air or steam also to be driven out of the pipework.

17. By limiting the rate of pressure rise within the evaporator elements and the steam water drum, the rate of rise of the drum and evaporator metal temperatures are also limited

18. When a positive pressure (2 barg for the HP and 1bar for the LP) is present in the steam/water drums it can be assumed that steam is being generated and the steam space is free of oxygen (air). The drum vents can then be closed

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19. Following the closure of the drum vents steam begins to flow from the drum to the superheater.

20. On closure of the intermediate or interstage drains on the superheater the steam flows out from the superheater into the steam mains and either to atmosphere through the Vents or to the Blowdown Tank via the Steam Line Drains.

21. The vents are normally opened fully, initially, and then progressively closed to allow a pressure rise according to the design rate. The vents should remain partially open until such time as a continual steam flow is established through the superheater by the passage of steam to the steam turbine or through the bypass to condenser.

The valves are lined up for cold start-up, HRSG pressure raising and HRSG water filling as per list given below:

No System Description Status Check 3. List of main stop valves to be

closed. Refer to table 2 in this document

Closed Confirm

Setting of remote operated valves.

Refer to Table 3 in this document

Defined in table 3

Confirm setting.

Valve openings at initial setting for cold start.

Refer to Table 7 in this document.

Defined in table 7.

Confirm valve position.

7.6.4 Pre-Start Checklist If not previously completed, inspect the entire unit, consisting of gas ducts, access lanes between tube blocks, stack base and each manhole and maintenance opening to be sure that all boiler manholes and maintenance holes are tight and ready for start-up.

Remove all tools and foreign matter from the gas side of the unit. This is particularly important with regard to any combustible debris around the superheater and boiler inlet.

The following preparation procedures are to be carried out with reference to their appropriate tables:

Procedure

No. Description Refer to

Table No. 4. Confirm that HRSG pre-start check points are completed. 1 Check that all main stop valves are closed. 2 Switch on electrical power supplies 3 Feed instrument air. 4 Check the function of remote operation valves. 5 Feed the cooling water 6

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Procedure No.

Description Refer to Table No.

Check the valve open-and-close position for each line. 7 Check the selection mode of controller. 8 Confirm the completion of ready for start-up of boiler feed

water supply equipment, chemical dosing equipment and sampling system.

9

Table 1- Preparation and Checklist

No. Check Point Confirmation and Notes

Internal check 1) Steam drum Cleaned (without debris) 2) Steam drum internals Correctly installed 3) Gas side of boiler proper Cleaned (without debris) 4) Gas duct and stack Cleaned (without debris)

5.

5) Blow down tank Cleaned (without debris) External check 1) Flange connected parts Gasket are adequately tightened Manholes and inspection holes Closed tightly 1) Manhole door of steam drum 2) Manhole door of boiler proper 3) Manhole door of gas duct & stack

4) Manhole door of blow down tank Strainers Cleaned (without debris) Local gauge Confirm that indication each

gauge is correct Lubricant oil initially filled / confirmation

Level transmitters are in service All trip relays Reset

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Table 2- List of Valves to be closed No. Plant Item Valve No. Checked

Boiler feed water line - HP feed water stop valve

6.

- LP feed water stop valve Make up water line - HP make-up water stop valve inlet valve

7.

- LP make-up water stop valve inlet valve Steam line - HP steam stop valve (Boiler outlet valve) - LP steam stop valve (Boiler outlet valve) - HP-SH drain valves

8.

- LP-SH drain valves Desuperheating line 9. - HP DSH injection water stop valve Blowdown line - HP drum continuous blowdown valve - LP drum continuous blowdown valve -HP drum intermittent blowdown valve

10.

-LP drum intermittent blowdown valve Chemical dosing line -HP drum chemical feed stop valve (Phosphate)

-LP drum chemical feed stop valve (Phosphate)

- Ammonia feed stop valve

11.

- Hydrazine feed stop valve Sampling line - HP drum water sampling stop valve - LP drum water sampling stop valve - HP saturated steam sampling stop valve - LP saturated steam sampling stop valve - Condensate Pump outlet water sampling stop v/v

12.

- DEA outlet water sampling stop valve N2 supply line - HP drum nitrogen supply stop valve

13.

- LP drum nitrogen supply stop valve

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Table 3- Electric Power Supply Items

No. Check Point Equipment No. / Notes

14. HP BFW pumps LP BFW pumps Condensate pumps Make-up water pumps Motor operated valves Refer Table 5 below Chemical dosing equipment (Local control panel) N/A Sampling unit (Local panel) N/A HP & LP drum level indicators Gas analyzer

7.6.5 Instrument Air The compressed air for instrumentation is used to actuate flow control valves and on-off valves. The procedure to supply instrument air is shown in Table 4.

Table 4: Instrument Air Supply Procedure

No. Check Point Notes 15. Confirm that inlet valve of each branch line and drain

valve are opened.

Gradually open stop valve, until fully open. Confirm supply pressure by observing pressure

gauge.

Close drain valve after ensuring that all residual water has been completely evacuated.

7.6.6 Remote Operating Valves Function: The function of various valves such as motor-operated valves and control valves should be checked in accordance with Table 5 at the control panel and local panel (where applicable) preferably when the plant is shutdown. Selector switches for remote operation valves should be selected to Remote or Auto after checking the functions.

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Table 5: Confirmation of Remote Operated Valves Function

Valve No. Valve Description Check For Initial Pressure Raising

Motor Operated Valves HP ECO vent valve Open-Close Open LP ECO vent valve Open-Close Open HP drum continuous blowdown valve Open-Close Part Open LP drum continuous blowdown valve Open-Close Part Open HP drum intermittent blowdown valve Open-Close Closed LP drum intermittent blowdown valve Open-Close Closed HP-SH1 drain valve Open-Close Closed HP steam drain valve Open-Close Closed LP steam drain valve Open-Close Closed HP start-up vent valve Open-Close Open LP start-up vent valve Open-Close Open HP steam stop valve Open-Close Closed LP steam stop valve Open-Close Closed HP steam stop valve bypass valve Open-Close Open LP steam stop valve bypass valve Open-Close Open HP feed water stop valve Open-Close Open LP feed water stop valve Open-Close Open

HP BFW pump outlet stop valves Open-Close

Duty pump Open

LP BFW pump outlet stop valves

Open-Close

Duty pump Open

Deaerator hot water stop valve Open-Close Open Deaerator steam stop valve Open-Close

Open

Control Valve HP drum level control Level

control Auto

LP drum level control Level control

Auto

HP steam temperature control Temp. control

Auto

Deaerator level control Level control

Auto

Deaerator steam flow control Level control

Auto

Deaerator hot water pressure control Pressure control

Auto

Condensate recirculation flow control Flow control Auto Condensate tank level control (Spill

over) Level control

Auto

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7.6.7 Closed Cycle Cooling Water System: Comprises of pumps, CCCW coolers, pipes and valves. The system must be checked and primed prior to starting the CCCW pumps.

Table 6: Closed Cycle Cooling Water Feed Procedure No. Check Point Equipment

No. 16. Confirm the operation of closed cycle cooling water system

Check that cooling water is supplied to the following equipment. - HP boiler feed water pumps - LP boiler feed water pumps - Condensate pumps - Boiler Water Chemical Sampling cooler - ST condenser vacuum pump

- STG air cooler Outlet flow shall be checked through the flow sight glass

provided for each equipment

7.6.8 Check the Valve Open and Close Position for each section: Table 7: Valve Openings at Initial setting for Cold Start-Up, HRSG pressure raising and water filling C: CLOSED O: OPEN S.O: SPECIFIED OPEN POSITION

Function No.

Line

Valve number Water

Filling only

From Initial Setting for

HRSG press. rising

Condensate line Condensate pump suction stop valves

C->O->C C->O

Condensate pump discharge stop valves

C->O->C C->O

Gland steam condenser inlet stop valve

C->O->C C->O

Gland steam condenser outlet stop valve

C->O->C C->O

DEA level C/V inlet stop valves

C->O->C C->O

DEA level C/V outlet stop valve

C->O->C C->O

17.

DEA hot water stop valve C C->O

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Function No.

Line

Valve number Water

Filling only


HRSG press. rising

DEA steam stop valve C C->O Boiler feed water line HP BFW pump suction stop valves

C->O->C C->O

LP BFW pump suction stop valves

C->O->C C->O

HP BFW pump discharge stop valves

C->O->C C->O

LP BFW pump discharge stop valves

C->O->C C->O

HP boiler water filling stop valve

C->O->C C

LP boiler water filling stop valve

C->O->C C

HP feed water stop valve C->O->C C->O LP feed water stop valve C->O->C C->O HP FW C/V inlet stop valve C->O->C C->O LP FW C/V inlet stop valve C->O->C C->O H P feed water C/V C->O->C C LP feed water C/V C->O->C C HP FW C/V outlet stop valve C->O->C C->O LP FW C/V outlet stop valve C->O->C C->O HP DSH injection water stop v/v

C C->O

HP DSH valves C C Steam drum attachment HP drum continuous blowdown stop valve

C C->O

LP drum continuous blowdown stop valve

C C->O

HP continuous blowdown valve

C C->S.O

LP continuous blowdown valve

C C->S.O

HP drum intermittent blowdown stop valve

C C->O

LP drum intermittent blowdown stop valve

C C->O

HP drum intermittent blowdown reg valve

C C->O/C

LP drum intermittent blowdown reg valve

C C->O/C

HP drum level gauge drain valves

S.O->C C

LP drum level gauge drain S.O->C C

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Function No.

Line

Valve number Water

Filling only


HRSG press. rising

valves HP drum level gauge vents S.O->C C LP drum level gauge vents S.O->C C HP chemical feed stop valve C->O->C C->O LP chemical feed stop valve C->O->C C->O H P drum vent valves C->O->C O->C LP drum vent valves C->O->C O->C HP drum water sampling stop valves

C C->O

LP drum water sampling stop valve

C C->O

HP steam sampling valves C C->O

LP steam sampling valve C C->O HP/LP economizer HP ECO-2 vent valves C->S.O-

>C O->C

C->S.O->C

O->C H P ECO-1 vent valves

O O->C C->S.O-

>C C LP ECO vent valves

O O->C HP ECO-2 & ECO-1 drain valves

C C

LP ECO drain valves C C HP/LP evaporator HP EVAP drain valves C C

LP EVA P drain valves C C HP/LP superheater HP SH vent valve C C->O->C HP SH drain valves C C->O->C

LP SH drain valves C C->O->C HP/LP steam lines HP steam stop valves C C->O

LP steam stop valves C C->O

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7.6.9 Check the Selection Mode of Controllers and Selection Switch Table 8: Selection Mode of Controllers for Start-Up Operation

No. Item Tag No. selection 18. All motor operated valves Refer to Table 5. Auto All control valves Refer to Table 5. Auto

7.6.10 Confirm the Completion: of Ready for Start-Up of Boiler Feed Water Supply Equipment, Chemical Dosing Equipment and Sampling System.

Table 9: Ready for Start-Up Checks

No. Item Tag No. Status Boiler feed water supply equipment Condensate tank NWL Deaerator NWL HP boiler feed water pumps

Ready to Start

LP boiler feed water pumps Ready to Start

19.

Condensate pumps Ready to Start Chemical dosing equipment Chemical mixing

tanks filled. Pumps ready to start

Sampling system Available

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8. System Start-Up Instructions 8.1 Procedure for Preliminary water filling and Flushing

This procedure shown in Table 10 will provide a guide to flushing dirt, grit or other contaminants from HRSG upon initial HRSG fill. It also may be used as a guideline for refilling HRSG during maintenance outages or repairs.

SYSTEM HRSG PROCEDURE No 1 PLANT ITEM HRSG and Auxiliaries REVISION: 0 JOB HRSG Preliminary water filling and flushing STATE OF PLANT Empty and Cold No ACTION/Description Valve Tag No.

/Verification 20. Confirm the completion of preparation for HRSG start-up

described in Section 7.6

Confirm that all valve openings are set in accordance with the initial setting of water filling stage of Table 7 of Section 7.6.8

Check the water quality is within acceptable limits Confirm OK with Chemist

Start make-up pump. (See Note 1)

Open HP/LP water filling stop valves. Gradually open HP/LP level control valves and increase

boiler feed water flow rate

Close air vent valves for upper headers of condensate pre-heater and LP and HP economizers when water overflow from vent valves is confirmed. If a minimum of 7 barg water pressure is available, flush the condensate pre-heater and, LP and HP economizers by opening drain valves until the water runs clear. Repeat as often as required to clear headers and valves of construction dirt (Note 2)

Flush HP/LP boiler until water runs clear from the blowdown valves. The use of an open drain will permit the boiler operator to check the water for clarity and also provide a visible indication that the blowdown valves are completely shut off. Continue to fill the boiler until water flows from the drum vent. Close the drum vent when no additional air flows from this line.

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No ACTION/Description Valve Tag No. /Verification

Flush through HP and LP superheater drain valves in a similar manner to the HP and LP economizers. Use caution, if introducing hot condensate in boiler, as the hot water will flash and may also cause water hammer in the piping. Purge the air from the HP and LP superheater through the vent lines as provided.

Flush the gauge glass and water column valves until each runs clear and is free of air.

Flush out all pressure gauge and other instrument lines. Instrument Technician

Drop the HP/LP Drum level to NWL and proceed to alkaline clean (boiling out) the HP/LP boiler, or drop the NWL to start-up level.

Stop make-up water pump. Confirm that the condensate pre-heater inlet and outlet

valves and the HP and LP feed water filing stop valves are fully closed

Notes: 1) If cold water is not available the boiler feed water may be

used to use hot condensate. However, extra care must be taken so as not to thermally shock the pipework with hot water or cause water to flash off into steam. The maximum temperature differential should be 800C between the water and the metal of HP/LP drum. This not only prevents damage to piping, but also maintains acceptable differential temperature limits across each of the drums and prevents hogging.

2) Flushing the pipework and valves should not be attempted unless 7 barg for HP and 3.5 barg for LP are available. The higher pressure is required to ensure that any dirt trapped under a drain valve seat to blow clear completely to ensure the valve will properly reseat.

3) When cold water is used, the complete pressure parts must be full before significant pressure builds in the system. Remember that at a head pressure of 20 meter the indicated pressure at the lower drains without steam or air pressure is about 2.0 barg.

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8.1.1 Start-Up procedure for HRSG Two start-up situations of HRSG need to be considered. One is cold start after long term shutdown; the other is hot start after short term shutdown. Both start-up procedures are basically the same, except that for a hot start-up the steam vent valves, steam drain valves and drum vent valves are closed. The cold start routine is as follows:

1. Confirm the completion of manual preparation prior to HRSG start-up as stated in Section 2.1.3.

2. Confirm that all valve openings are set in accordance with the initial setting for HRSG pressure raising stage as stated in Table 7.

3. Confirm that the cooling water and instrument air systems are in operation.

SYSTEM HRSG PROCEDURE No PLANT ITEM HRSG and Auxiliaries REVISION: 0 JOB Start-up procedure STATE OF PLANT Cold/Hot Step Action/ Description Tag No./

Verification Checked

Condensate System 21. Select either Condensate pump 1 or 2 and

open it’s respective suction stop valve

Start selected Condensate pump Slowly open Condensate pump discharge

stop valve

Open Gland steam condenser inlet stop valve

Open Gland steam condenser outlet stop valve

Open DEA level C/V inlet stop valves Select Condensate tank level control valve to

Auto mode.

Select Condensate recirculation flow control valve to Auto mode

Select DEA level C/V to Auto mode Open DEA level C/V outlet stop valve Select DEA steam pressure control valve to

Auto mode.

Select DEA hot water pressure control valve to Auto mode

Boiler Feed water system Open HP BFW pump suction stop valves Open LP BFW pump suction stop valves

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Step Action/ Description Tag No./ Verification

Checked

Start selected HP BFW pump Start selected LP BFW pump Open selected HP BFW pump discharge

stop valve

Open selected LP BFW pump discharge stop valve

Close HP boiler water filling stop valve Close LP boiler water filling stop valve Open HP feed water stop valve Open LP feed water stop valve Open H P FW C/V inlet stop valve Open LP FW C/V inlet stop valve Select HP feed water C/V to Auto mode Select LP feed water C/V to Auto mode Open HP FW C/V outlet stop valve Open LP FW C/V outlet stop valve Open HP DSH injection water stop valve Select HP DSH valve to Auto mode

HP & LP Steam drum Open HP drum continuous blowdown stop

valve

Open LP drum continuous blowdown stop valve

Select HP continuous blowdown valve to Auto mode

Select LP continuous blowdown valve to Auto mode

Open HP drum intermittent blowdown stop valve

Open LP drum intermittent blowdown stop valve

Select HP drum intermittent blowdown valve to Auto mode

Select LP drum intermittent blowdown valve to Auto mode

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9. System Normal Operation The following sections give the procedures for normal operation and the precautions to be observed.

Normal operation of the HRSG is conducted in conjunction with the Gas Turbine and Steam Turbine operating procedures.

The operating philosophy of the GPS HRSG is such that the HRSG steam output follows the gas turbine. The HRSG has been designed for the following conditions:

• Continuous operation at maximum steam generating capability

• Operation in constant pressure mode

In general, HRSGs are much more responsive than conventional utility boilers, especially during start-up. Being more responsive, the HRSGs operation must be integrated with the GTG, STG, and other plant and equipment and their associated operating limits.

The rapid changes in the HRSG parameters require operators to be more responsive. They should keep in mind the following boiler operating criteria.

• Drums being operated at the specified NWL’s.

• HP final steam temperature limits are not exceeded

• Instrumentation, alarms and trips are accurate and level control is in good working order

• Water Chemistry remains within limits

• Deaerator system is operated at a steady pressure.

Under normal conditions HRSG operation is usually completely automatic; however individual systems can or may have to be operated manually.

9.1 Routine Plant Checks In order to ascertain the current operating condition of HRSG for any corrective action that may be required it is recommended that the following items be checked:

1. As a minimum requirement all Control screens associated with the HRSG should be scanned regularly and any alarm attended to immediately.

2. Operators must patrol the area related to GTG, HRSG, STG and ACC at regular intervals to ensure that each component is operating correctly. Prompt corrective action must be taken if any abnormality is found.

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3. A record of measured values not ready by the DCS historian must be taken at regular intervals not only for the control room instruments but for all other instruments.

4. These manually prepared records should be maintained for future reference.

5. All instruments should be regularly checked to ascertain if they are indicating correctly or not, and adjusted if necessary (as per manufacturer’s recommendations).

6. Functional tests of standby plant should be conducted periodically during unit operation to determine the true standby plant status and availability.

7. Control equipment and protection safety devices shall be regularly checked as per equipment supplier or ISA recommendations dictate.

8. Drum water level gauges must be checked for operation once a day by carrying out a gauge glass blowdown routine. This involves shutting off the steam and water supply valves and opening the drain then blowing through the gauge glass in turn with steam and water before restoring the level gauges to normal.

9. Each gauge must be watched carefully when load is varied or low load operation is performed. It is important to take corrective action promptly in the case of any abnormality.

10. Selection mode of controller and selection switch for normal operation is shown in Table below:

Table 12: Selection of MOV and Control Valves No. Item Tag No. Selection 1. All motor operated valves shown in Table

5 Refer to Table 5. Auto

All control valves shown in Table 5 Refer to Table 5. Auto

Table 13 is provided as a basic guide for recording routine measurements at local monitoring points. However, depending on operating conditions of the HRSG it may be considered necessary to increase the frequency of monitoring and the number of points monitored. Each value measured locally should be compared with the Control Room Control System measurement.

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Table 13: Measurements to Take During Routine Walkdowns of HRSG Plant

No. Description Tag No. Interval Local Pressure Gauges Condensate tank Once a shift Deaerator Once a shift HP BFP FW outlet Once a shift LP BFP FW outlet Once a shift HP Drum Once a shift LP Drum Once a shift HP Steam Once a shift

1.

LP Steam Once a shift Local Temperature Gauges Condensate tank Once a shift H P steam Once a shift

2.

LP steam Once a shift Local Level Indicators Condensate tank Once a shift Deaerator Once a shift HP drum gauge – compare immediately with Control Room

Once a shift

LP drum – compare immediately with Control Room

Once a shift

Chemical tanks – confirm details with Chemist

Once a shift

Cooling water flow & temperature for pumps, sampling system and ST system to be checked in accordance with each O&M manual.

11. Early detection of abnormal conditions or problems, and prompt remedial actions are essential in HRSG operation. From this point of view, it is essential to carry out adequate periodical checks on relevant plant and equipment during HRSG operation as stated in Table 14. Depending on operating conditions of HRSG, it may be considered necessary to increase the frequency of the checks and to carry out checks on more items.

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Table 14: Items to Check During Routine HRSG Walkdowns No. Item Frequency Notes 2. Boiler proper 1.1

Mass balance of HRSG. Check the energy input to energy output balance considering flow rate of steam, feed water, blowdown, etc.

Once a day

Check with Performance Engineer

1.2 Drum manholes Leakage Once a shift 1.3 Casing & gas duct hot spots and leakage Once a shift Use a thermal

camera to check any suspicious areas

1.4 HRSG framework and supports Once a month 2

Pressure piping a. Leakage b. Water hammering c. Vibration d. Pipe hangers and supports

Once a shift Once a shift Once a shift Once a month

Check for noise

3

Safety valve a. Relieving and closing pressure b. Leakage c. Deformation of exhaust piping

As per maintenance schedules Once a shift Once a shift

4 Water level gauge a. Correct indication b. Leakage c. Transparency of gauge glasses d. Gauge lights working

Once a day Once a shift Once a shift Once a shift

Compare with CCR

5 Pressure gauges a. Correct indication b. Leakage

Once a shift Once a shift

Compare with CCR

6 Thermometers a. Correct indication b. Leakage

Once a shift Once a shift

Compare with CCR

7

Valves a. Leakage through gland packing, bonnet or flanges. b. Passing valves c. Vibration or abnormal sound

Once a shift Once a shift Once a shift

Check drain lines

8 Drain Traps Steam leakage Once a week 9 Control valve

a. Leakage through gland packing, bonnet or flange. b. Vibration or hammering c. Operating condition d. Correct operation e. Instrument air pressure

Once a shift Once a shift Once a shift Once a month Once a shift

Freedom of movement

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No. Item Frequency Notes 10 Local transmitters

a. Leakage through flange or connector at impulse pipe. b. Leakage through flange or plug c. Correct function

Once a shift Once a shift Once a shift

Report all defects to Instrument Engineer

11 Thermocouples a. Tightness of flange of terminal box cover b. Tightness of terminal

Once a month Once a month


12 Level switches a. Tightness of terminal box cover b. Tightness of terminal c. Correct function

Once a month Once a month Once a month


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10. System Shutdown Instructions It is assumed that under scheduled shut down conditions that the STG will be shutdown at the same time, or at least its load reduced proportional to one HRSG being taken out of service. The associated GTG would be shutdown accordingly in parallel with the HRSG.

10.1 Normal Shutdown Requirements The shutdown of the steam cycle can be initiated through the following:

• Scheduled Shutdown or Trip of HRSG

• Scheduled Shutdown or Trip of GTG (s)

• Scheduled Shutdown or Trip of Steam Cycle (Steam turbine or HRSG)

• Shutdown Trip/Failure of the Main Cooling System

• Shutdown Trip/Failure of other Equipment.

Shutdowns can also be scheduled for short periods (a few hours), for weekends or for long periods.

10.2 Scheduled Shutdown Procedure for Boxing up HRSG STEP ACTION Tag No. Condition 3. Switch Drum level control from

Three element control to single element control

When the feed water flow ≤ 25% of design flow rate

Stop Chemical dosing pumps Inform Chemist Select to manual and close HP/LP

steam stop valves

Open HP/LP superheated steam drain valves

When HP drum press ≤ 2barg When LP drum press ≤ 1barg

Select to manual and close HP/LP continuous blowdown valves.

Select to manual and close HP/LP intermittent blowdown valves.

Close HP/LP boiler feed water stop valves

Stop HP/LP BFW pumps It is desirable to maintain HP and

LP Drum levels at NWL until boiler water temperature is ~1000C at < 1barg

Do not ‘top-up’ drum level if differential temp is > 800C

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11. Emergency Shutdown Procedure In the event that the critical failures develop, operators must urgently decide either to shut down or decrease GT load by carrying out the emergency shutdown procedure immediately. After cooling down of HRSG, confirm the cause of the failure and repair if necessary.

11.1 Emergency Shutdown Requirements In order to maintain personnel safety, plant integrity and minimise plant damage it is vital that all operations personnel are familiar with the Emergency Shutdown Procedures of the plant. Any critical incident will require correct and urgent response. In the event that the critical develop, operators must urgently decide either to shut down or decrease GT load by carrying out the emergency shutdown procedure immediately. It is important that operators are trained to be prepared for such abnormal conditions.

STEP ACTION Tag No. Condition 4. HRSG trip order ON

(and GT trip order ON)

In the event of critical failures

Switch Drum level control from three element control to single element control.

When feed water flow ≤ 25% of design flow rate

Stop Chemical dosing pumps Inform Chemist Select to manual and close

HP/LP steam stop valve

Open HP/LP superheated steam drain valve

When HP drum press ≤ 2barg When LP drum press ≤ 1barg

Select to manual and close HP/LP continuous blowdown valves.

Select to manual and close HP/LP intermittent blowdown valve.

Close HP/LP boiler feed water stop valves

Stop HP/LP BFW pump

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12. Alarm Responses Please Note; These are typical alarms for a HRSG and may not reflect the readings at the Power Station. These readings will need to be cross-referenced with local plant data.

System Monitored Parameters (Alarm Conditions) Summary.

No Tag No. Description Status Check5. HP drum water level LL= -750 mm LP drum water level LL=-500 mm HP drum pressure HH=97 barg HP steam temperature H=544 deg C

L=350 deg C

Deaerator Pressure H=3.6 barg Flue gas temperature at boiler inlet High Flue gas Pressure at boiler inlet H=+40 mbarG

12.1 Summary of Alarms

12.1.1 Alarm Response # 1 Alarm Title HP/LP Drum Level (high) Initiating Device Level transmitter/ Level switches. Set Point H= +100 mm from NWL for HP & LP

1 Problem with drum level control valve

2 Problem with level transmitter

Possible Causes

3 Sudden Increase of load Consequences 1 High Drum level trip if level is not controlled.

1 Continue operation, paying attention to the water level and flow rate indications

2 Open the intermittent blowdown valves

Immediate Action

3 Re-adjust the control device, if above 1) and 2) are not successful

Follow-up Action 1 Check level gauges and compare with remote

indications (to be coincident with above 3))

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12.1.2 Alarm Response # 2 Alarm Title HP/LP Drum Level (Low) Initiating Device Level transmitter/ Level switches. Set Point L= - 100 mm from NWL for HP & LP

1 Problem with drum level control valve

2 Problem with level transmitter 3 Sudden decrease of load

Possible Causes

4 Feed water line leakage. Consequences 1 Low Drum level trip if level is not controlled.

1 Continue operation, paying attention to the water level and flow rate indications

2 Never rapidly increase the feed water flow but slowly and steadily.

Immediate Action

3 Re-adjust the control device, if above 1) and 2) are not successful

1 Check level gauges and compare with remote

indications (to be coincident with above 3)

Follow-up Action

2 Check boiler feed water lines for leakage.

12.1.3 Alarm Response # 3 Alarm Title Abnormal HP & LP Drum Pressure (HIGH) Initiating Device Pressure transmitters Set Point H = 94.5 barg for HP drum

H=9.4 barg for LP drum.

1 Problem with steam pressure control device Possible Causes 2 Sudden increase of GTG load or decrease of STG

load. Consequences 1 High HP/LP drum level trip.

1 Continue operation paying attention to the steam pressure.

Immediate Action

2 Re-adjust the control device. Follow-up Action 1 Check local indication and compare with remote

indication

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12.1.4 Alarm Response # 4 Alarm Title Abnormal Quality of HP & LP Drum Water Initiating Device Chemical measurements Set Point pH less than "L" and more than "H"

(L =9.0, H =10.5) for HP drum (L = 9.8, H = 10.8) for LP drum Conductivity more than "H" HP/LP : (H =I50 μ s/cm)

Possible Causes 1 Incorrect application of Boiler water treatment 2 Insufficient quantity of Continuous Blow Down

HP Blowdown valve: HAD90AA202 LP Blowdown valve: HAD20AA202

Consequences 1 Boiler water pH or conductivity abnormal.

1 Continue operation paying attention to the boiler water quality.

2 Check chemical dosing equipment and feed water quality.

Immediate Action

3 Adequate regulation of continuous blow down Follow-up Action 1 Consult with Chemical Laboratory Staff

12.1.5 Alarm Response # 5 Alarm Title Abnormal Low Level of Chemical Tank Solution Initiating Device Tank level switches low alarm. Set Point Low level.

1 Insufficient chemical solution preparation Possible Causes 2 Chemical solution feed line or tank leaking

Consequences 1 Chemicals not available for treatment. Immediate Action 1 Recharge chemical solution. Follow-up Action 1 Inspect the chemical solution tank, feed piping and

each valve.

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12.1.6 Alarm Response # 6 Alarm Title Abnormal Temperature of HP steam DSH Outlet Initiating Device Temperature transmitter Set Point HP steam temperature more than H (H = 544 degC)

HP steam temperature less than L (L =350 degC)

1 Problem with desuperheater spray water control device LAE80AA004/05

Possible Causes

2 Problem with steam temperature detection device LBA80CT002

Consequences 1 Steam temp high/low trip.

1 Continue operation paying attention to the superheater outlet steam temperature, or deload the GT

Immediate Action

2 Check desuperheater spray water control device and steam temperature detecting device

Follow-up Action 1 Inspect the desuperheater system.

12.1.7 Alarm Response # 7 Alarm Title Abnormal Pressure of Deaerator Initiating Device Pressure transmitter Set Point Deaerator pressure more than H

H=3.6 barg

1 Problem with pressure control device 39LAB01 AA011/021 39LBA20AA003

Possible Causes

2 Problem with pressure detection device 39LAA10CP001

Consequences 1 Steam temp high/low trip. Immediate Action 1 Continue operation paying attention to the

Deaerator pressure and level

Follow-up Action 1 Check pressure control device and pressure

detection device.

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12.1.8 Alarm Response # 8 Alarm Title Abnormal Flue Gas Temperature of Boiler Inlet Initiating Device Temperature Device Set Point Boiler inlet flue gas temperature more than

design temperature

Possible Causes 1 Problem with Gas Turbine equipment

Consequences 1 Flue gas temp high. Immediate Action 1 Continue operation paying attention to

superheater inlet gas temperature, or de-load Gas Turbine

Follow-up Action 1 Check Gas turbine exhaust controls.

12.1.9 Alarm Response # 9 Alarm Title Abnormal Pressure of Boiler Inlet Flue Gas Initiating Device Pressure Transmitter Set Point Boiler inlet flue gas pressure more than H

(H = +40 mbarG)

1 Problem with Gas Turbine equipment Possible Causes 2 Problem with stack isolation damper

Consequences 1 Flue gas pressure high. Immediate Action 1 Continue operation paying attention to Gas

Turbine exhaust gas pressure, or deload Gas Turbine

Follow-up Action 1 Check Gas turbine equipment and stack dampers.

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12.2 Actions on Non Alarm Faults

12.2.1 Gas Leaking from Ducts or HRSG Casing This can be caused by metal distortion due to ‘hot’ spot temperatures, or through natural expansion and contraction of the metal parts over a number of operating cycles.

Actions:

• Identify source of leakage and conduct repairs as soon as plant is safely shutdown

• Minimise sudden changes in the GT loads to reduce large temperature excursions.

12.2.2 Water and Steam Leaks Leaks can occur at valve spindles, pipe joints, pump body and flanges located throughout the plant. HP Steam leaks can be of particular concern as the steam can be invisible. If a leak is heard but not seen, it will usually be compressed air or HP Steam. Spindle and flange leaks will deteriorate exponentially as once the spindle packing or flange gasket is passing, the leak will continue to get worse. Early detection and repair is preferred to avoid damage to valve or flange.

Actions:

• For safety, plant should be shutdown to effect repairs

• Protect electrical equipment within the vicinity of any leak

• Place safety barricades around any suspected steam leak to keep personnel away from the affected area.

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13. Steam Line Blowing 13.1 Introduction

New construction steam line blowing is performed prior to admitting steam to a turbine consumer and is intended to-clean the steam line(s) of any loose or foreign materials that would cause significant damage to the machinery.

Steam blowing should be considered following all major HRSG pressure parts repairs.

13.2 Safety It is the responsibility of the persons performing the steam blowing procedure to ensure that all Safety Procedures, such as Job Hazard Analysis, are properly followed.

13.3 Steam Blowing Precautions Prevention of damage to the steam turbine is of primary concern to the turbine manufacturer and the purchaser. The responsibility for determining cleanliness criteria and the effectiveness of the steam blows rests with the steam turbine manufacturer and/or the purchaser.

After hydrostatic testing and prior to steam line blowing, manufacturer's representative(s) for safety and safety relief valves should be contacted for on-site assistance in completing the installation and de-blocking of the valves.

All HRSG safety systems and functions should be tested and verified prior to steam line blowing. While steam line blowing is in progress, all HRSG safety systems are to be operational. No safety systems are to be bypassed or suppressed.

CAUTION: When steam line blowing is being performed, the HRSG experiences full operational thermal loads. Care must be exercised to insure that all pressure parts are expanding properly.

Care should be exercised in the design, fabrication and installation of all temporary piping used in the steam blow procedure. Protective measures should be used to insure that pressure and temperature operating limits for this piping are not exceeded.

Since all steam generated in the steam line blowing procedure is released to the atmosphere, substantial quantities of treated demineralised water is required. Care should be exercised to

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ensure that sufficient stocks of this water, and all other necessary chemicals, are readily available.

It is difficult to avoid carry over from the steam drums to the super-heaters during the steam line blowing operations. Therefore, boiler water should not be treated with non volatile chemicals during this process to avoid deposits of solid materials into the superheaters.

Waterside blow down of the HRSG, at the conclusion of each day's steam line blowing activities, is required throughout the steam line blowing procedure. Adhering to this schedule will greatly reduce water quality problems that can occur on new boiler installations.

Gas turbine flow must be discontinued during all steam line blows.

13.4 Steam Blowing Methods Multiple pressure HRSG's require simultaneous operation of the boiler sections throughout the steam blows. Personnel are required to monitor and operate each of the boiler sections. Temporary piping and silencers are also required for each section to be operated independently of the others.

There are two basic methods currently in use for performing steam blows, the pulse method and the continuous method.

The pulse method is performed by running the combustion turbine at its minimum MW rating and raising the pressure in the HRSG while the steam outlet valve is closed. When the pressure reaches approximately 50% of full HRSG operating pressure, the steam valve is opened, releasing steam to the new steam lines. As the pressure decays, the steam outlet valve is closed, raising the HRSG operating pressure. These pressure pulses should be repeated until the steam lines are determined to be clean as indicated by target impact testing. The pulse method is difficult to perform on an HRSG that is not fitted with a diverter damper. This method can also be detrimental to the combustion turbine due to erratic drum levels, which can cause combustion turbine trips as HRSG safety interlocks are activated.

The continuous method is based upon using high steam velocities that are attained by operating at the highest allowable steam temperature, at the lowest attainable steam pressure. When the unit is stabilised at these operating conditions, the control desuperheaters are operated to produce rapid steam temperature fluctuations. With all steam outlet valves in the wide-open position, the combustion turbine is started. With the

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steam outlet valves open to atmospheric pressure, pressure in the HRSG will rise to approximately 10% of the normal operating pressure.

13.5 Operating Procedures The steam generator is started in the normal manner. All normal recommendations and limitations with respect to gas turbine operation, fuel firing equipment, drains and vents, etc. should be followed, as if the unit was being started for normal operation. As for any new unit, the steam blowing operation is the first occasion that it is fired at any significant rate. Consequently, the start-up as well as the steam line blowing must be conducted with great care. The unit must be brought up much slower than normal (one half the normal start-up rate) to allow checking of all equipment and monitoring of expansion movements. Do not use the duct burners (if so equipped). The same general precautions taken on any new unit for this period of operation apply equally here.

The drum level in the steam drums will be subject to extreme fluctuations during the blows. As the temporary blow off valve is opened, the drum level will rise rapidly and may go out of sight in the gauge glass. As the blow progresses, the drum water level will reappear and may drop out of sight. Therefore it is important that the drum level is established at or slightly above normal operating level before the start of each blow. A small amount of feedwater flow should be established before the start of each blow and the feedwater flow should be increased as soon as the water level drops back in sight, in order to prevent an excessive low water level.

When the drum pressure reaches the value calculated to produce the desired blowing flow rate, the blowing process can be started:

1. Discontinue gas turbine flow and firing of duct burners (if so equipped). Gradually open the temporary blow off valve, to blow through the superheaters, main steam line and out the temporary blow off piping.

CAUTION: The first blow should always be done at reduced pressure, in order to check out the temporary piping system, its supports end anchors.

2. When the drum pressure has dropped to the value corresponding with a 100øF (56øC) saturated steam temperature decrease (see Figure 1), close the temporary blow off valve and re-fire the unit to re-establish blowing conditions.

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Repeat the above cycle until it is considered that cleaning is satisfactory as indicated by inspection of impact specimens during the final blows.

Figure 22: Steam Line Blowing Curve

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14. Pre-Operational Chemical Cleaning Procedures 14.1 Introduction

Immediately before a new HRSG is put into service, the internal surfaces should be cleaned to remove oil and grease by means of an alkaline boil-out. For new installations, acid cleaning is not recommended as a method of cleaning internal surfaces.

If acid cleaning is selected as the method for initial HRSG cleaning, it should be undertaken only by experienced, competent personnel. It is strongly recommended that a reliable chemical cleaning company be contracted for this purpose. In addition to cleaning the boiler surfaces, the pre-boiler system must be flushed with a hot alkaline solution to remove oils and siliceous material.

CAUTION: Do not boil out or acid clean the high pressure (HP)superheater or the intermediate pressure (JP) superheater. During either operation, the HP and IP superheaters should be back filled with demineralised water.

There are several methods of boiling out a HRSG. The recommended procedure outlined in this section has been proven to be successful.

14.2 Pre-Operational Boilout 14.2.1 Preliminary to Boilout

1. To minimise the amount of foreign matter that can be introduced into the HRSG from the pre-boiler system following start-up, the pre-boiler system should be alkaline flushed prior to boil-out.

2. It is good practice, though not a requirement, to remove all drum internals before boil-out. If drum internals are removed, inspect and steam clean prior to reinstallation, if necessary.

3. Mechanically remove as much oil and grease as possible from the drums before boil-out.

4. All HRSG instrumentation leads exposed to the cleaning solution should be isolated during the cleaning process.

5. Provisions should be made to utilise demineralised water.

6. The HP and IP superheaters shall be back filled with demineralised water and are not to be subjected to the boil-out solution.

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7. Install a temporary gauge glass on each steam drum.

8. Special lines are required from a truck location or remote chemical pumping station. Provisions should be made for:

a) A DN 80 mm or larger fill line to the acid fill connections on the HRSG.

b) Drain lines of adequate size to empty the HRSG rapidly, preferably within 1 hour. The method of disposal must also be considered.

c) Necessary atmospheric vents.

d) Blowdown valves should be used for sampling connections and should be appropriately tagged. All HRSG sections should be sampled independently utilising the blowdown valves supplied. This is required to ensure that::

(1) All sections of the HRSG are being properly cleaned.

(2) All sections of the HRSG are being properly flushed and neutralised.

9. All pressure parts must be carefully inspected for obstructions and the necessary hydrostatic tests made. Internal chemical feed lines should be checked to be certain that they are free and clear.

10. It is important that the operators on duty during the boil-out operation are familiar with normal operating procedures and precautions. The normal HRSG trip interlocks should be in operation and functioning properly. The HRSG auxiliaries and the special cleaning equipment should be in good operating condition.

11. Before introducing the cleaning solution into the HRSG, particular care should be taken to eliminate possible leaks, and adequate precautions should be taken to protect personnel in the event of leaks occurring.

14.3 Boil-out Procedures 1. A boil-out is normally performed to remove oil or

preservatives, and requires the use of a fairly strong caustic solution. The HRSG should be filled to normal operating level with the boil-out solution. The recommended boil-out solution is:

4.00 kg of sodium carbonate (Na2CO3) per 1000 kg (1 m3) of water

and

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4.00 kg of Trisodium Phosphate (Na3PO4) per 1000 kg (1 m3) of water

and

detergent (0.05 to 0.1% by volume)

CAUTION: Use of most commercial detergents at concentrations in excess of 0.1% by volume during boil-out may cause foaming and carry-over of alkaline solution to the superheaters. Since commercial detergents vary in strength (i.e. water diluted) check with the manufacturer if recommended use strengths arc-higher then 0.1%.

Other formulations and combinations of chemicals can be satisfactorily employed for boil-out, and in cases where pollution control requirements dictate, changes in formulation can be made. Changes should, however, be reviewed by ABB Power Generation for suitability prior to use.

2. The solution is added to the HRSG via the steam drum manholes (LP, IP and HP sections). Fill the drum to approximately the bottom edge of the drum door. Dissolve the chemicals in a suitable container with hot water and then slowly transfer the solution to the drum. Proceed slowly to allow time for dispersion. Chemicals should be added at both ends of the drum if practical.

3. After the boil-out solution has been added, close the drum doors (with temporary gaskets). Continue filling the boiler and confirm the drum level in the temporary water gauge glass. Prepare for start-up (refer to Unit Operating Procedures section of this manual). Apply heat slowly, bringing the pressure in the HP section of the HRSG to between 700 and 1400 kPa within 8 hours. The IP and LP sections will balance out at approximately 200 to 350kPa. Hold the pressure for 4 hours. The water level in the steam drums will rise during this period, however, blowdown should be restricted only to what is necessary to keep the water level from going out of sight in the temporary gauge glasses. A high water level should be maintained during the boil-out process. The gas turbine, controls, vents, drains, etc, should be operated as during normal start-up.

4. After 4 hours, secure the heat source and allow the HRSG pressure to decrease. After the pressure in the HP superheater has dropped noticeably, at least 500 kPa, restore the water level to normal operating level by means

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of blowdown. Blowdown the HRSG using the blowdown valves supplied, operating them in sequence. Do not allow the water level to go out of sight in the gauge glasses.

5. Reapply heat, raise the pressure to between 700 to 1400 kPa in the HP section and hold for 4 hours. At the end of the 4-hour period, repeat step 4.

6. Repeat step 5 two more times.

7. A boil-out solution sample should be obtained periodically and should be analysed for alkalinity, phosphate, and the presence of oil. All HRSG sections should be sampled independently to ensure that all sections are being properly cleaned. If the water alkalinity and phosphate concentrations have dropped to 1/2 the original values, additional boil-out chemical should be added to restore the original concentrations. Although quantitative de-terminations are preferable, qualitative checks for the presence of oil will be highly satisfactory for monitoring and control purposes.

8. When analysis of the samples show that alkalinity, phosphate and dissolved silica have reached equilibrium levels and oil is no longer detected in samples, the heat source should be shutdown.

9. When the steam pressure drops to 175 kPa, the drum vents and superheater header drains should be opened wide. This will occur for the HP, IP and LP (without superheater drains) sections.

10. Following the complete draining of the boil-out solution, the HRSG should be filled to the top of the gauge glasses with clear rinse water heated to 80øC. While the HRSG is being filled for the boil-out rinse, back fill the HP and IP superheaters through the outlet headers with demineralised water until water spills over into the steam drums. Leave the rinse water in the HRSG until it has sufficiently cooled to allow internal inspection. Drain the HRSG.

CAUTION: The use of fill water treated with solid chemicals should be avoided. Deposits of solid materials in superheaters can be detrimental from heat transfer and corrosion standpoints. Fill water quality should be verified immediately prior to its introductions into the superheater circuits. A demineralised water supply is recommended.

11. If the internal inspection of the HRSG indicates unsatisfactory cleaning, the boil-out procedure should be repeated.

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12. If immediate operation of the HRSG is not anticipated upon completion of the boil-out, the HRSG should be laid up using the procedure given below.

14.4 Post Boil-out Lay-up If the operation of the HRSG is delayed for more than 1 or 2 days after boil-out, lay-up can be accomplished by the following method:

1. Through normal filling connections, fill the HRSG with demineralised water containing approximately 200 ppm of hydrazine (N2H4) and sufficient ammonia (NH3) (approximately 10 ppm) to raise the pH to 10.

2. The HP and IP superheaters should be filled through their outlets with demineralised water containing the same solution as the rest of the HRSG. When the demineralised water solution overflows from the superheaters into the steam drums, the filling of the superheaters can be secured.

3. Introduce nitrogen through the superheater drains. Maintain a total pressure of 35 kPa with nitrogen.

14.5 Preparations for Putting the HRSG into Service Following Boil-out

14.5.1 Prior to Initial HRSG Operation: 1. Refill the superheaters with demineralised water. Drain

and test each superheater header individually to ensure that no chemicals have been inadvertently left in the superheaters. If required, flush the superheaters until satisfactory test results are achieved.

2. Inspect the steam drums.

a) Blow out the internal gauge glass connections and instrument leads. Remove temporary gauge glasses and install permanent gauge glasses.

b) Blow out chemical feed and continuous blowdown piping.

c) Flush out any loose sediment from drum surfaces and steam separators. Flush with clear water from the drums, draining through the blowdown connections at the bottom of the HRSG.

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3. When all internal surfaces are clean, reinstall drum internals if they were removed. Inspect and clean steam drum internals if required prior to installation.

4. Remove all temporary piping and/or valves used for the boil-out process.

5. When all work is completed, a thorough inspection should be made to ensure that no foreign material has been left in the drums.

6. Fill the HRSG. Apply a hydrostatic test at normal operating pressure. Refer to Hydrostatic Testing Procedures provided elsewhere in this manual. If the HRSG is not to be placed into operation, refer to recommended HRSG lay up procedures. If the HRSG is to be placed into operation continue with step 7.

7. Reduce the water level in the steam drums to the suggested operating level.

8. Drain the superheaters.

The HRSG is now ready for operation.

14.6 Operational Acid Cleaning 14.6.1 Introduction

Periodically during the operating life of any steam generator, chemical cleaning is recommended for the removal of iron oxide, copper, water formed and other deposits that may have accumulated on steam generating surfaces. The frequency of operational cleaning is dependent upon a number of operating conditions. However, cleaning every 3 years appears to be a common and suitable period. This schedule should be altered for units that are subjected to intermittent operation or in cases of system upsets, such as condenser leakage, when feedwater contamination is greater than normal. In cases of tube failures caused by excessive deposits, chemical cleaning is one of the steps to be taken to return the unit to a sound operating condition.

Additives included in the acid cleaning solution facilitate the removal of specific materials, such as copper and silica, which may be present in the deposit. The choice of additives should be based on the materials contained in deposits, and these should be determined prior to cleaning. If unusual or difficult to remove deposits are encountered, it may be necessary to use multi-step cleaning with special solvents to completely remove scale. It is recommended that one of the reliable chemical cleaning contractors be contacted for operational cleaning. These

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companies have the experience and technical know-how to properly formulate a cleaning mixture to re-move undesired materials.

14.6.2 Acid Cleaning Procedures CAUTIONS: Acid cleaning should only be performed by experienced personnel who will provide the appropriate procedures.

The initial clean out should be accomplished by means of a boil-out.

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15. Valves 15.1 Introduction

Commissioning procedures particular to the Island Co-generation Project are provided in this chapter. Detailed procedures are also provided for hydrostatic testing and steam line blowing as separate chapters due to the complexity of these items.

15.2 Pneumatic valves 15.2.1 General

Pneumatically actuated valves are provided in the intermittent blow-off, start up vents and drain systems. Commissioning is required to set the opening time of each valve as given below. Adjust the speed controller and lock in position (locknut or thread adhesive). Observe the operation of the valves during hot commissioning to verify acceptable action.

15.2.2 Blowoff Valves The intermittent blowoff system consists of a manual `y`-globe valve and actuated angle valve at the HP, IP and LP evaporators. The intermittent blowoff actuated valves require an opening time of 10 to 20seconds.

15.2.3 Start Up Vent Valves Start up vents are provided at the HP and IP superheater outlet pipes and the LP saturated steam line and consist of a manual globe valve and an actuated ball valve. The actuated start up vent valves require an opening time of 5 to 10 seconds.

15.2.4 Drain valves Pneumatically actuated drains are provided at the HP steam pipe HP superheaters, HP evaporator, IP steam pipe IP evaporator and LP evaporator The drains require an opening time of 5 to 10 seconds.

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16. Table of Figures Figure 1: Elementary Diagram of a Combined Cycle Plant.......................................................... 8 Figure 2: HSRG Fitted with HP, IP and LP Steam Sections ........................................................ 9 Figure 3: GT Exhaust inlet and HRSG Exhaust outlet ............................................................... 11 Figure 4: Typical HRSG Arrangement........................................................................................ 12 Figure 5: Conduction of heat along metal rod ............................................................................ 15 Figure 6: Typical Finned Water Tube Arrangement ................................................................... 16 Figure 7: Wet Steam .................................................................................................................. 17 Figure 8: Dry Saturated Steam................................................................................................... 18 Figure 9: Simple Diagram of Natural Circulation ........................................................................ 20 Figure 10: Section of HRSG Showing External Area of Economiser ......................................... 27 Figure 11: Economiser Drains.................................................................................................... 28 Figure 12: HRSG HP Drum........................................................................................................ 29 Figure 13: LP Drum.................................................................................................................... 29 Figure 14: Drum Safety Valves .................................................................................................. 30 Figure 15: Drum Level Control Valves ....................................................................................... 32 Figure 16: Cyclone Separator Internals...................................................................................... 33 Figure 17: Steam Drum Internal ................................................................................................. 33 Figure 18: HRSG Drum Blowdown Vessel................................................................................. 34 Figure 19: HP Drum showing downcomer pipes ........................................................................ 36 Figure 20: Typical Direct Spray Attemperator ............................................................................ 39 Figure 21: GT load and Steam Pressure.................................................................................... 41

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17. Table of Tables Table 1: Typical Economiser Pressures & Temperatures .......................................................... 29 Table 2: Steam Table Example .................................................................................................. 35 Table 3: Typical Evaporator Pressure & Temperatures ............................................................. 37 Table 4: Typical Evaporator Pressure & Temperatures ............................................................. 40

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