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HRSG OPERATION AND MAINTENANCE
ALSTOM Power Revision: 0 iv Copyright 2005 09/01/05 Project: NUBARIA POWER STATION I & II
ALSTOM Power Revision: 0 v Copyright 2005 09/01/05 Project: NUBARIA POWER STATION I & II
SECTION 4: DRUM LEVEL and PROCESS CONTROL ..............................................................4-1
4.1 LEARNING OBJECTIVES ............................................................................................4-1 4.2 CONCEPT FOR LP, IP AND HP DRUM LEVEL CONTROLS.......................................4-1 4.3 LP DRUM LEVEL ..........................................................................................................4-8 4.4 LP STEAM VENT VALVE CONTROL ...........................................................................4-9 4.5 IP DRUM LEVEL .........................................................................................................4-10 4.6 IP DRUM CONTINUOUS BLOWDOWN ISOLATION VALVE .....................................4-10 4.7 HRSG IP MAIN STEAM VENT VALVE........................................................................4-11 4.8 IP TO LP PEGGING STEAM CONTROL.....................................................................4-11 4.9 HP DRUM CONTINUOUS BLOWDOWN ISOLATION VALVE ...................................4-11 4.10 HP DRUM LEVEL ........................................................................................................4-11 4.11 HP STEAM TEMPERATURE CONTROL ....................................................................4-12 4.12 HP OVERPRESSURE .................................................................................................4-12 4.13 HP MAIN STEAM OUTLET VENT VALVE ..................................................................4-13 4.14 RH STEAM TEMPERATURE CONTROL ...................................................................4-13 4.15 FEEDWATER HEATER RECIRCULATION CONTROL .............................................4-14 4.16 CONDENSATE PARTIAL BYPASS CONTROL .........................................................4-14
5.1 LEARNING OBJECTIVES .............................................................................................5-1 5.2 HRSG BOILER OPERATIONAL REVIEW.....................................................................5-1 5.3 COMPLETION OF MAINTENANCE PRIOR TO OPERATION......................................5-1 5.4 INITIAL FILLING ............................................................................................................5-1 5.5 PRE-OPERATIONAL EQUIPMENT CHECKS...............................................................5-3 5.6 FEEDWATER PREHEATER RECIRCULATION ...........................................................5-4 5.7 START UP FROM A COLD CONDITION ......................................................................5-4 5.8 START UP FROM A WARM CONDITION...................................................................5-10 5.9 SECURING TO A WARM LAY-UP CONDITION .........................................................5-15 5.10 SECURING TO DRAIN ................................................................................................5-16 5.11 CONTROLS AND INSTRUMENTATION .....................................................................5-17 5.12 SAFETY VALVES ........................................................................................................5-18 5.13 FW PREHEATER BYPASS OPERATION...................................................................5-19 5.14 EMERGENCY PROCEDURES....................................................................................5-19
SECTION 6: FEEDWATER AND BOILER WATER CHEMISTRY ...........................................6-1
LEARNING OBJECTIVES .............................................................................................6-1 6.1 INTRODUCTION............................................................................................................6-3 6.2 STANDARD SPECIFICATIONS FOR COMBINED CYCLES WITH DRUM-TYPE BOILERS......6-4
SECTION 7: INSPECTION AND MAINTENANCE ...................................................................7-1
8.1 LEARNING OBJECTIVES .............................................................................................8-1 8.2 DESCRIPTION OF CURVES.........................................................................................8-1 8.3 START-UP PERFORMANCE CURVES ........................................................................8-3 HP PREDICTED PERFORMANCE- COLD START.................................................8-4 HRH/IP PREDICTED PERFORMANCE- COLD START .........................................8-5 LP PREDICTED PERFORMANCE- COLD START .................................................8-6 HP PREDICTED PERFORMANCE- HOT START (after 48 hr) ...............................8-7 HRH/IP PREDICTED PERFORMANCE- HOT START (after 48 hr) ........................8-8 LP PREDICTED PERFORMANCE- HOT START (after 48 hr)................................8-9 HP PREDICTED PERFORMANCE- HOT START (after 8 hr) ...............................8-10 HRH/IP PREDICTED PERFORMANCE- HOT START (after 8 hr) ........................8-11 LP PREDICTED PERFORMANCE- HOT START (after 8 hr)................................8-12 HP PREDICTED PERFORMANCE- 1x1x1 to 2x2x1 Transition ............................8-13 HRH/IP PREDICTED PERFORMANCE- 1x1x1 to 2x2x1 Transition ....................8-14 LP PREDICTED PERFORMANCE- 1x1x1 to 2x2x1 Transition ............................8-15 SHUTDOWN PRESSURE DECAY- HP.................................................................8-16 SHUTDOWN PRESSURE DECAY- IP ..................................................................8-17 SHUTDOWN PRESSURE DECAY- LP .................................................................8-18
SECTION 9.0: VALVE and INSTRUMENT LISTS...................................................................9-1
9.1 VALVE LIST ...................................................................................................................9-3 9.2 INSTRUMENT LIST .......................................................................................................9-7
P&ID - High Pressure 07202-1D 0012 ...........................................10-3 P&ID - Intermediate Pressure 08003-1D 0013 ...........................................10-4 P&ID - Low Pressure 08003-1D 0014 ...........................................10-5 P&ID - Gas Side 08003-1D 0015 ...........................................10-6 P&ID - Deaerator System 08003-1D 0016 ...........................................10-7 P&ID - Blowdown Tank 08003-1D 0017 ...........................................10-8 General Arrangement - Right Side Elevation 08003-1E 0001............................................10-9 General Arrangement - Upper Plan View 08003-1E 0002..........................................10-10 General Arrangement - Lower Plan View 08003-1E 0003..........................................10-11 General Arrangement - Left Side Elevation 08003-1E 0004..........................................10-12 Pressure Part Arrangement - Side Elevation 08003-1E 0100..........................................10-13 Pressure Part Arrangement - Section ‘AA’ 08003-1E 0101..........................................10-14 Pressure Part Arrangement - Section ‘BB’ 08003-1E 0102..........................................10-15 Pressure Part Arrangement - Section ‘CC’ 08003-1E 0103..........................................10-16 Pressure Part Arrangement - Section ‘DD’ 08003-1E 0104..........................................10-17 Pressure Part Arrangement - Section ‘EE’ 08003-1E 0105..........................................10-18 Pressure Part Arrangement - Section ‘GG’ 08003-1E 0106..........................................10-19 Steam Drum Internals 1829 mm HP Drum 08003-1D 1401..........................................10-20 Steam Drum Internals 1372 mm IP Drum 08003-1D 1411..........................................10-21 Steam Drum Internals 1524 mm LP Drum 08003-1D 1421..........................................10-22
HRSG OPERATION AND MAINTENANCE
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SECTION 1: ENGINEERING FUNDAMENTALS 1. LEARNING OBJECTIVES • Explain the fundamental physical principals of: water to steam conversion, heat transfer and
natural circulation for a heat recovery steam generator. • Explain basic functional concepts of the Heat Recovery Steam Generator (HRSG) boiler
design 2. WATER TO STEAM The function of the boiler is to produce a specific amount of steam at a constant pressure and temperature from a specific amount of feedwater. This steam is used to drive the turbine. Water can exist in three physical states, solid, liquid or gas (vapor), depending on the corresponding pressure and temperature. Steam generation is only concerned with the liquid and vapor forms of water. Steam results from adding sufficient heat to water to cause it to vaporize or turn into a gas. This occurs in two steps: a. The addition of heat sufficient enough to raise the temperature of water to the boiling
temperature. b. A continuing addition of heat to change to change the physical state of water from a
liquid to a gas (steam) Thermal capacity (specific heat) is the quantity of heat required to produce a unit change in temperature. Water has a high thermal capacity. This means that a great amount of heat is required to cause a temperature change in water. Water cools slowly in the process of giving up absorbed heat. Specific heat is the term used in power generation for thermal capacity. Specific heat is the amount of British Thermal Units, BTU, required to raise the temperature of one pound of water one degree Fahrenheit (oF). It takes one BTU to raise the temperature of one pound of water one degree F. Other substances may require either more or less heat to raise one pound by one degree F. Enthalpy is the measure of the total stored internal energy of a substance, such as water or steam. Steam tables list the enthalpy in Btu/lb of saturated liquid (hf), and saturated and superheated steam at various pressures and temperatures. The Btu/lb Represents the amount of heat transferred to the water/steam from the combustion of fuels. Enthalpy changes are a function of temperature and pressure. The steam tables show the trends in BTU when going from a lower pressure to a high steam pressure.
HRSG OPERATION AND MAINTENANCE
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3. STEAM GENERATION PROCESS Latent Heat of Fusion Latent heat of fusion is defined as the amount of heat required to melt one pound of ice at 32oF to one pound of water at 32oF. This latent heat or “hidden heat” produces a change in state of the water instead of a change in temperature. 144 Btu are needed to convert one pound of ice into one pound of water at 32oF at 14.7 psig or 29.92 “Hg, the normal atmospheric pressure or absolute pressure. This process is depicted in Figure 1.
Figure 1: Latent Heat of Fusion
Latent Heat of Vaporization Latent heat of vaporization is defined as the amount of heat required to change one pound of liquid water to one pound of steam (vapor). When additional heat is added to the water at its boiling point, the temperature of the water remains constant, but the physical state is changed. One pound of water at 212o F. which is the boiling point of water at 14.7 psig, requires 970 Btu to change into one pound of steam at 212o F. This process is depicted in Figure 2.
Figure 2: Latent Heat of Vaporization/Condensation
HRSG OPERATION AND MAINTENANCE
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Latent Heat of Condensation Latent heat of condensation, also shown in Figure 2, refers to the condition where a pound of steam at 212o F is cooled (heat is removed) to form a pound of liquid water at 212o F. The energy lost in going from a pound of steam to water is 970 Btu/lb. Sensible Heat Refer to Figure 3. When the flow of heat is not reflected in a temperature change (latent heat), it is absorbed in the fluid or substance and increases the kinetic energy of the molecules of the substance. This is called sensible heat. Water at 32o F will absorb 180 Btu of sensible heat per pound when raising the water temperature to 212o F.
Figure 3: Sensible and Latent Heat
HRSG OPERATION AND MAINTENANCE
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Heat Flow Heat is the flow of thermal energy. When heat is added or removed, temperature differentials are formed so that thermal energy can flow from one substance or area to another. Sensible heat and latent heat are merely two effects produced by heat, not different kinds of heat. When the flow of heat is not reflected in a temperature change (latent heat), it is absorbed in the fluid or substance and increases the kinetic energy of the molecules of the substance. 4. STEAM CHARACTERISTICS Quality of Steam The proportion, by weight, or “dry” vapor in a steam and water mixture is termed the quality of steam. Steam quality is expressed in percentages. If as quantity of steam contains 90% steam and 10% water vapor, the mixture has a quality of 90%. Saturated Steam Saturated steam is steam saturated with all the heat it can hold at the boiling temperature of water. Dry saturated steam vapor essentially contains very little moisture (dependent upon its quality), and is at saturated temperature for the given pressure. Its total heat content, or enthalpy, is equal to the heat of the liquids plus the heat of vaporization. Pressure and Temperature Relationship When water is heater to the boiling point in a closed vessel, the vapor released caused the pressure to increase in the vessel. With the increase in pressure, the boiling temperature of the water also increases. The temperature at which water boils at a given pressure is termed the saturation temperature. For each saturation temperature, there is a corresponding pressure called the saturation pressure. Figure 4 depicts the relationship between saturation temperature and saturation pressure.
HRSG OPERATION AND MAINTENANCE
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Figure 4. Pressure/Temperature Relation ship The Critical Point At 3208.2 psia with a corresponding saturation temperature of 705.5o F, water and steam properties are identical. In fact the terms “water” or “steam” no longer apply since the properties of the water and liquid are the same. Instead the term “working fluid” is used when temperature and pressure are above this critical point. Boilers designed to operate at pressures and temperatures below the critical point are called sub-critical boilers. Boilers designed to operate at pressures and temperatures above the critical point are called supercritical boilers. Superheated Steam Steam heated above its corresponding saturation temperature at a particular pressure is called superheated steam. Superheated steam contains no moisture, and will not condense until its temperature has been lowered to that of saturated steam at the same pressure. Superheating of steam takes place in the various superheater sections of the boiler. Steam must be superheated before it can be sent to the turbine or process steam headers to do useful work.
HRSG OPERATION AND MAINTENANCE
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Degree of superheat refers to the temperature difference in degree Fahrenheit between the steam at the superheater outlet, and its corresponding saturation temperature (steam drum outlet) at a given pressure. For example, consider a superheater outlet steam pressure of 72.5 psi and a superheater outlet temperature of 572o F. The corresponding saturation temperature at that pressure is 318o F. Therefore, the degree of superheat is 5720 F minus 318o F, equaling 254o F. It must also be recognized that there is a loss in steam pressure between the drum steam pressure and the superheater outlet pressure. Superheated steam has three advantages over steam that is not superheated: • It increases the efficiency of the turbine. • It prevents damage to turbine blades from condensation. • It is able to travel through long pipelines with little or no condensing. Departure from Nucleate Boiling There are two types of boiling that can occur in steam generators. Nucleate boiling – is the normal boiling process in a boiler in which water is raised to the boiling point, and individual steam bubbles form as water comes in contact with the hot tube surfaces. As these bubbles form and leave the heated surface, the cool water that remains (due to proper circulation) wets the tube surfaces, thus keeping the waterwall tube metal temperatures well within allowable limits. Film boiling – is an abnormal boiling condition and is present at times when insufficient water flow or circulation exists. When this type of boiling process takes place, steam bubbles form as water comes in contact with the hot tubes surfaces. They then collect and burst forming a film of steam which blankets the hot tube surface. Waterwall tube metal temperatures increase and tube damage can result. A term commonly used to describe this condition in DNB, or Departure from Nucleate Boiling. DNB can occur during periods of excessive firing rates if the circulation ratio or tube flow is not sufficient to carry away excess heat. Steam pockets form over large areas of the inner tube diameter, creating an insulating film barrier to normal heat transfer. The transition from Nucleate Boiling to DNB is shown in Figure 5.
HRSG OPERATION AND MAINTENANCE
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Figure 5: Nucleate Boiling and DNB Results of DNB can include: • Overheated tube failures • Rapid accumulation of waterside tube deposits • Uncontrollable drum level as large steam pockets are released • Turbulence inside the drum can carry water out with the steam 5. HEAT TRANSFER PRINCIPLES The process of transferring thermal energy can only occur if it originates from an area or material on one temperature to and area or material of a lower temperature. Heat transfer is vital to the operation of the power plant cycle and occurs in many locations throughout the plant. 6. HEAT TRANSFER MODES Conduction When heat passes through a solid object, quickly moving molecules in the hot portion collide with and give up some energy to slower molecules in the cooler portion. This type of heat transfer is called conduction.
HRSG OPERATION AND MAINTENANCE
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Radiation Heat transfer occurs via radiation when electromagnetic waves from a heat producing source strike a surface, and give up energy to the molecules in that surface. Burning fuels give radiant energy. Convection When a heated fluid or vapor moves to a cooler region by circulation resulting from density differences between the hot and cold areas within the fluid or vapor, this is called convection. 7. MAIN FACTORS AFFECTING HEAT TRANSFER Differential Temperatures (∆T) The temperature difference between a high temperature source and a low temperature source is called differential temperature. A higher ∆T will result in a greater amount of heat transfer. Thermal Conductivity Thermal conductivity is an indication of how well a material absorbs and transfers heat. A higher value of thermal conductivity means a material is capable of transmitting heat at a faster rate than a material with a low thermal conductivity. Surface Area Surface area is the area of a low temperature source that is placed in contact with a source of higher temperature. A larger exposed area will result in a higher heat Transfer Coefficient. The heat transfer coefficient is a constant factor, which mainly depends on the physical properties of the heat transferring mediums such as gasses, solids and metal tubes, and the gas velocity in the boiler. Materials are selected and arranged in the boiler according to their various heat transfer properties. Pinch Point The difference between the gas temperature leaving an evaporating section and the temperature at which boiling is occurring (saturated water temperature) is called a pinch point. The pinch point strongly influences the amount of heat transfer surface in the evaporating section. Current HRSG designs uses pinch points in the 15o to 25o F range. See Figure 16 for a graphic representation.
HRSG OPERATION AND MAINTENANCE
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Approach Temperature The approach temperature is the difference between the saturated-water temperature in an evaporating section and the incoming feedwater temperature. The approach temperature influences the amount of surface required for an economizer section, with exponentially increasing amounts required for very low approach temperatures. Current HRSG economizers have approach temperatures in the 15o to 25o F range. Many other operating conditions can occur at off-design points, including start-up. Some conditions will result in steaming at the exit of the economizer, such that it acts as an evaporative surface. See Figure 16 for a graphic representation. Materials Metals have good thermal conductivity. The number and arrangement of the tube assemblies placed in a boiler are selected to provide the proper tube surface area which is expressed to the hot solids/gasses so that the correct amount of heat is transferred to the water/steam to obtain design steam pressure and temperatures with design combustion temperatures. Fiberglass, silica block, and certain refractory compounds are used where heat transfer is not desired. These materials, called insulators, have low thermal conductivity and help to reduce the heat transfer. Improper insulation in the form of ash and /or dust and internal tube deposits can be very detrimental to boiler heat transfer, as indicated in Figures 6, 7, 8 and 9. Ash/dust deposits on the external surfaces of boiler tubes have lower thermal conductivity than the tube metal. A higher differential temperature is required to pass the proper amount of heat through the ash/dust to the water/steam inside the tubes. The reduction in heat flow from the tube to the boiler water/steam increases the average tube metal temperature, which can lead to tube failures from overheating. Temperature limitations for typical tube materials are shown in Table 1.
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Figure 8: Temperature Profile across Tube Wall with Internal Deposit
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Table 1: Temperature Limitations for Typical Tube Materials 8. BOILER WATER CIRCULATION Boiler circulation is defined s the movement of water, a mixture of steam and water, or steam through boiler tube circuits. There are two types of circulation: • Natural or “thermal” circulation • Forced or “controlled” circulation
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Natural Circulation In natural circulation boilers, circulation is accomplished without the use of circulating pump. The density difference between steam and water (thermal head) is the driving force in a natural circulation boiler (Figures 10 and 11).
Figure 10: Natural (Thermal) Circulation
Cold side: The density of saturated water in the downtakes (also called downcomers) will range between 60 lb/ft3 and 30 lb/ft3, depending on the corresponding pressure and temperature in the boiler steam drum. Hot side: The steam/water mixture density in the waterwalls will be approximately 25 lb/ft3. Variations in boiler pressure have a lesser effect on the mixture density.
HRSG OPERATION AND MAINTENANCE
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Figure 11: Circulation Schematic for Natural (Thermal) Circulation As boiler pressure increases, the difference between the densities of water and steam, which is the motive force for natural circulation boilers, becomes smaller (Figure 12). Thermal head differential is the resulting differential ranges between approximately 25 psi and 10 psi, with the greater differential being possible in lower pressure boilers (Figures 12 and 13).
HRSG OPERATION AND MAINTENANCE
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Figure 12: Density of Water to Steam vs. Pressure In addition to the fact that there is less motive force in a higher-pressure boiler, there are also other factors in a natural circulation boiler, which oppose circulation. These are: • Friction between water and tube metal • Friction between water and scale deposits in tubes • Friction in tube bends • Friction in lower drum and headers • Friction around upper drum internals • Friction in the steam and water separating equipment
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Figure 13: Typical Boiler Static Head – Constant Circulation Ratio of 4.0 Circulation Ratio Circulation ratio is defined as the weight of water entering the downcomer, divided by the weight of steam in the water/steam mixture leaving the water wall tube circuits. Because circulation is dependent on the thermal head, which is dependent on boiler pressure, the flow of water into the downcomer increases as load decreases. At low loads of 50% of Maximum Continuous Rating (MCR) or less, the circulation ratio will be much higher since there is less steam being generated. Natural Circulation boilers are generally designed for a circulation ratio of “5” equaling a circulation ratio of 5 to 1. For example, for every 25-lb. Of water entering the downcomer, there could be as much as 5 lb of steam leaving. 9. HEAT RECOVERY STEAM GENERATOR The following material was copied from pages 8-30 to 8-35 of the Combustion Fossil Power text. A Heat Recovery Steam Generator (HRSG) is used to recover heat that otherwise would be lost in the exhaust from a gas turbine. This heat is then used to generate steam that will drive a steam turbine or be used in a process. Typically, the addition of an HRSG and a steam turbine boosts total output of electricity by 30 percent or more over the traditional gas turbine operating in a single cycle mode. Efficiency increases with the increased output. Gas turbines have been widely used to provide standby or peaking power for electric utilities, or for unattended service in remote locations. As described in Chapter 1, the thermal efficiency is low because of high exit-gas temperatures (800 to 1000o F, or 425 to 540oC) and high excess-air levels (220 to 300 percent) in the combustion products. The thermal energy remaining in the
HRSG OPERATION AND MAINTENANCE
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exhaust gas can be recovered in a heat-recovery boiler to produce additional electricity using a steam-turbine generator. The combined output of electricity from the gas turbine and the steam turbine is 30 to 50 percent greater than that obtained from the gas turbine alone, with no additional fuel input. Combined-cycle power plants for industrial power-generation application have much higher thermal efficiencies than conventional steam power plants with the same steam conditions. In general, the high thermal efficiency of a combined-cycle plant can be economically exploited if liquid or gaseous fuels are readily available and the unit can be operated continuously or operated on an interruptible basis at least 50 percent of the time at full power. Chapter 1 of the Combustion Fossil Power text identified the four major classifications of combined cycles and their associated heat rates. The two most commonly used cycles for industry employ unfired or supplementary fired heat-recovery steam generators (HRSG’s). Supplementary fired heat-recovery steam generators use firing equipment located in the exhaust gas stream in the boiler inlet transition duct. Since gas-turbine exhaust contains 75 to 80 percent of the oxygen normally found in atmospheric air, fuel may be burned without the need for additional fresh air. By using duct burners, gas-turbine exhaust temperatures can be increased to 1500 to 1600oF (815 to 870oC) with a consequent reduction in the oxygen content of the exhaust gas from 15 percent to 11 percent. Supplementary firing generally doubles the steam output of the heat-recovery boiler by providing a mechanism for varying steam production and matching process-steam demand, independent of the gas-turbine electricity production. Most applications of HRSG’s to gas-turbines of greater than 20MW generate steam at two or three pressure levels. High-pressure steam (600 to 1800 psig, or 4.1 to 12.4 MPa gage) usually drives a steam-turbine generator. Intermediate-pressure steam (200 to 400 psig, or 1.4 to 2.8 MPa gage) is used for process steam in a plant or is injected into the gas-turbine combustor to reduce NO, emissions. Low-pressure steam (5 psig to 120 psig, or 35 to 825 KPa gage) is used for plant processes or feedwater heating in a de-aerator. An increasing number of installations induce intermediate-pressure steam for additional power recovery in the low-pressure stages of an enhanced power output when plant steam demand is low, but electrical demand is high. The heat-recovery steam generator may also incorporate additional water-heating sections for condensate preheating or for high-temperature water for fuel heating or other plant processes. In some locations, air-quality authorities have imposed very stringent requirements for NOx emissions from gas turbines. In many cases, these requirements virtually mandate the use of NOx reduction catalysts in the turbine exhaust steam. These catalyst assemblies operate in a narrow temperature range that is lower than the turbine exhaust-gas temperature. The presence of an HRSG is an asset in the strategy to control emissions since the NOx reduction catalyst may be located in the appropriate temperature zone between sections of heat-exchange surface in the boiler. Steam-Generator Designs The basic principles for selecting heat-recovery steam-generating equipment are similar to those for conventional utility and industrial boilers. However, the designer must be aware of the entire system arrangement in order to integrate the steam generator properly within the overall plant. Although cycle efficiency and economics generally determine the basic cycle conditions, the designer is typically faced with a matrix of conditions, which determine the optimum design. These conditions include a wide range of thermal performance parameters, dictated by varying ambient conditions and steam load requirements, limitations on capital cost, and restrictions on available space. In pursuing a solution to the demands of a specific application, three aspects
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of the boiler design process dominate: (1) extensive use of externally finned tubing for maximum convective heat recovery, (2) an emphasis on low gas-side pressure loss to limit the gas-turbine fuel-rate penalty associated with increased backpressure on the gas turbine, and (3) distribution of heat-recovery surface in multiple sections to achieve optimum heat transfer at each temperature level through the boiler.
Figure 14: Vertical, Unfired Steam Generator for Recovery of Heat from Gas Turbine Exhaust
Boiler Configuration Waste-heat boilers in gas-turbine exhaust service can be configured with gas flow in the horizontal or vertical direction. Vertical gas-flow units permit an arrangement of equipment in the exhaust flow path that occupies less floor space but requires extensive steel support structure. Horizontal gas-flow units generally cover a greater plan area, but afford much better access for maintenance of boiler parts, duct burners, catalyst elements, and other equipment that may be associated with the HRSG.
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Boilers with vertical gas flow usually employ horizontal tubes connected by return bends with the tubes supported at several locations along the length of the tube my tube sheets, as illustrated in the figure above. Most of these applications require a circulating pump in the steam-generating sections of the boiler. The circulating pump ensures uniform distribution of water to multiple parallel steam-generating circuits. Pumps are usually sized to maintain a circulation ratio of 4 to 1 at the maximum steaming condition. Boilers with horizontal gas flow use vertical tubes connected to headers at the top and bottom, as seen in the following figure. The tube and header assemblies may be either top-supported or bottom-supported. Although the tubes are self-supporting in the vertical direction, lateral restraints are required to control gas-flow-induced vibrations. Natural circulation in the steam-generating sections provides high circulation ratios without the use of pumps.
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1. Stack 2. HP Drum 3. IP Drum 4. LP Drum/Storage Tank 5. Inlet Duct 6. Stair Tower 7. HP Steam Safety Valve Silencer 8. Hot Reheat Safety Valve Silencer 9. Cold Reheat Safety Valve Silencer
10. HP Drum Safety Valve Silencer 11. HP Drum Safety Valve Silencer 12. HP/RH Desup. Spraywater Station 13. Feedwater Heater Recirculation Pumps 14. CO Catalysts Cavity 15. SCR Catalyst Cavity 16. Duct Burner Cavity 17. Duct Burner Skid 18. SCR Ammonia Flow Control Skid
Figure 15: Horizontal Gas Flow Heat Recovery Steam Generator
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Figure 16: Temperature Profile of Unfired Heat Recovery Steam Generator with Three
Operating Pressure Levels A simplified flow diagram (Figure 17) for a triple-pressure HRSG illustrates the way in which heat-absorbing sections operating at certain temperature levels are located in the gas stream to minimize the amount of heat-transfer surface required. There are ten discrete heat-exchange sections distributed in descending order based on the gas temperature available and the fluid temperature requirements. The two critical temperature differences that influence the amount of heat-transfer surface and the overall steam generated at each pressure level are the: • Pinch point: The difference between the gas temperature leaving a evaporating section
and the temperature at which boiling is occurring (saturated-water temperature). • Approach temperature: The difference between the saturated-water temperature in an
evaporating section and the incoming feed-water temperature. The pinch point strongly influences the amount of heat-transfer surface in the evaporating section. Current HRSG designs use pinch points in the 15 to 25oF (8 to 14oC) range. In general, these boilers have 50 percent more surface in the evaporating section than boilers with pinch points of 40 to 50oF (22 to 28OC). The approach temperature also influences the temperatures. Current HRSG economizers have approach temperatures in the 15 to 250oF (8 to 14oC) range at the design point. Many other operating conditions can occur at off-design points, including start-up. Some conditions will result in steaming at the exit of the economizer, such that it acts as evaporative surface.
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Specific provisions to accommodate steaming at levels up to 5 percent of total flow in an economizer include: (1) careful control of water distribution in the last downflow passes of the economizer to cause that portion of the economizer to behave as a forced-circulation evaporator, or (2) configuring the last few passes of the economizer as entirely upflow, with relief by natural circulation into the steam drum. The triple-pressure HRSG temperature diagram shown in Figure 16 illustrates the distribution of heat-exchanger sections and the side of each evaporating bank section. Approach temperatures are illustrated as the difference between the water temperature leaving the last section of each economizer and the saturated-water temperature. Note that the high-pressure economizer is divided into three separate sections to provide appropriate temperature zones for the intermediate-pressure superheater, evaporator and economizer. Typical Construction Features The triple-pressure HRSG shown in Figure 17 illustrates equipment normally included in the scope of supply of the boiler supplier: • Expansion joint at gas-turbine exhaust interface
• Single-blade exhaust diverter valve bypass stack with silencer
• Inlet transition duct with flow corrective devices
• Exhaust stack Insulation is placed on the inside of all duct sections and boiler casing sections, thereby allowing the use of carbon steel casing plate and stiffeners, and minimizing the thermal growth of the overall boiler structure. A system of internal liner plates protects the insulation from gas flow. These plates are segmented for individual thermal expansion and overlapped in the direction of gas flow. All boiler pressure parts are supported in ways that allow complete freedom for thermal expansion relative to the casing and support structure.
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Fired Steam Generators Supplied with Gas Turbine Exhaust Normally containing 75 to 80 percent of the oxygen found in free atmospheric air, gas-turbine exhaust can concurrently supply to the furnace of a steam generator both sensible heat and oxygen for the combustion of a fuel. The design and operation of such boilers vary considerably, depending upon the ratio of the total exhaust flow to the amount necessary for oxidizing the supplementary fuel needed for a given evaporation. Combustion air preheaters are not used because of the already high level of preheat represented by the 700o to 900oF (370oF to 480OC) temperature of the exhaust gases. Supplementary-fired steam generators (Fig. 24) using most of the oxygen in the turbine exhaust are of the same design and size as units using outside air through forced-draft fans. The stack temperature of such a unit can be dropped economically to within 100o F (55o C) of the incoming feedwater temperature. Since the boiler is sized for a flue gas weight based on fresh air firing, a portion of the gas turbine exhaust is by-passed. This portion of the exhaust is cooled by passing over a separate steam generating bank, to the same temperature as the gasses passing through the boiler, and then proceeds to the final heat recovery in the economizer. In such a cycle, gas turbine and boiler size must be matched closely to obtain a high ratio of feedwater flow to the gas-turbine exhaust flow. Because all gas-turbine/boiler applications involve the recovery of sensible heat, the usual concept of boiler efficiency loses its significance. Customary practice therefore is to evaluate performance of combined-cycle boilers on the basis of stack temperature. The overall station heat balance is determined using the calculated value of fuel fired in the boiler (rather than boiler efficiency as such), in addition to the fuel fired in the gas turbine.
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SECTION 2: HRSG SYSTEM DESCRIPTION 2.1 LEARNING OBJECTIVES
• Draw a simplified functional diagram of the HRSG, labeling the major components. • Describe the purpose and function of the major components. 2.2 INTRODUCTION (Refer to Pressure Part Diagram, Figure 2-3) This section provides a brief description of the components that make up the Heat Recovery Steam Generator (HRSG). The HRSG consists of three boiler systems at different pressure levels, high pressure (HP), intermediate pressure (IP), and low pressure (LP) and a Reheater. The water/steam and the exhaust gas flow paths are described below, starting from the inlet and following the fluid flow path. Each pressure stage consists of an economizer, evaporator and superheater. The Feedwater is heated in the economizer and fed to the drum. From the drum, water is fed into the evaporator, where a portion is evaporated. The resulting water-steam mixture returns to the drum, where the mixture is separated by means of separators. The saturated steam is fed into the superheater. The water/steam and the exhaust gas flow paths are described in the next section starting from the inlet and following the fluid flow path. The heat-absorbing sections of the HRSG are made up of shop-assembled pressure part modules. These modules can be shipped by truck, rail or barge. Each module is properly braced for shipment. The HRSG finned tubing is made by helically winding solid or serrated fin stock to the walls of bare tubing by means of a low penetration, high frequency resistance welding process. The HRSG evaporator circuits incorporate large steam drums to reduce the potential for water surges normally encountered during cold starts. Dedicated downcomers are used to ensure a proper circulation in each of the evaporator circuits. 2.3 HIGH PRESSURE WATER/STEAM FLOW PATH
HP feedwater is supplied to the HP pressure section via the HP stage of the feedwater pump, which extracts feedwater from the Deaerator Storage Tank. The HP Economizer section functions to raise the boiler feedwater to a suitable approach temperature. After passing through the feedwater control, check and stop valves, the HP feedwater enters the HRSG at HP Economizer 4. The water then flows through HP Economizer 4, HP Economizer 3, HP Economizer 2, and then through HP Economizer 1. After leaving HP Economizer 1, the water enters the HP Steam Drum through one feedwater inlet nozzle and continues on to HP Evaporator. Natural circulation is maintained in the HP Evaporator by means of downcomers, which feed the water from the drum through distribution manifolds to the lower evaporator headers. Steam is generated and flows upward in the
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evaporator tubes. The saturated water/steam mixture is conducted from the upper HP Evaporator headers to the HP Steam Drum through risers. The saturated steam is separated from the saturated water/steam mixture by the drum internals (centrifugal separators, corrugated dryers, and dry box) and then exits the top of the HP Steam Drum through the saturated steam outlets. ( A typical section of steam drum internals is shown in Figure 2-1) The saturated steam leaving the drum passes through HP Superheater 3 and HP Superheater 2. After leaving HP Superheater 2, the steam passes through two HP Desuperheaters in parallel. After leaving the HP Desuperheater, the steam flows through HP Superheater 1. The steam leaves HP Superheater 1 through connecting links where it is combined into the HP Main Steam line. 2.4 REHEATER STEAM FLOW PATH After combining with the IP steam, the cold RH enters the HRSG through Reheater 2. The steam then passes through two RH Desuperheaters in parallel into Reheater 1. The steam leaves Reheater 1 through connecting links where it is combined into the hot Reheat Steam Line. 2.5 INTERMEDIATE PRESSURE WATER/STEAM FLOW PATH After passing through the feedwater control, check and stop valves, the IP feedwater enters IP Economizer 1 then enters the IP Steam Drum through the feedwater inlet nozzle. This flow continues through the IP Evaporator. Natural circulation is maintained in the IP Evaporator by means of downcomers, which feed the water from the drum through distribution manifolds to the lower evaporator headers. Steam is generated and flows upward in the evaporator tubes. The saturated water/steam mixture is conducted from the upper IP Evaporator headers to the IP Steam Drum through risers. The saturated steam is separated from the saturated water/steam mixture entering the steam drum by the drum internals (centrifugal separators, corrugated dryers, and dry box) and exits the top of the IP Steam Drum through saturated steam outlets. The saturated steam leaving the drum passes through the IP Superheater. The steam leaves the IP Superheater through connecting links where it is combined into the IP Main Steam Line. A portion of the IP Steam can be used as pegging steam for the external deaerator. The IP steam passes through non-return and stop valves and then combines with the cold reheat steam. 2.6 LOW PRESSURE WATER/STEAM FLOW PATH The LP Feedwater takes suction from the Dearerator Storage Tank. The LP Feed water from terminal point (TP-7) passes through the flow orifice, control valve, stop check valve and block valve and enters the LP Drum through the feedwater inlet nozzle. A separate Condensate Feed flows through the Condensate Preheater and on into the External Deaerator Tank. A portion of the water from the Preheater outlet is taken to the Preheater Recirculation Pump suction. It then is being recirculated and mixed with the feedwater entering the Preheater inlet nozzle to increase the temperature of the incoming feedwater prior to entering the External Deaerator. Natural circulation is maintained in the LP Evaporator by means of downcomers, which feed the water through distribution manifolds into the lower evaporator headers. Steam is generated and flows upward in the evaporator tubes. The saturated water/steam mixture is conducted from the upper LP Evaporator headers to the LP Drum through risers. The saturated steam is separated
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from the saturated water/steam mixture entering the steam drum by the drum internals (corrugated dryers, and dry box) and exits the top of the LP Drum through saturated steam outlets. The saturated steam leaving the drum passes through the LP Superheater. The steam leaves the LP Superheater through connecting links where it is combined into the LP Main Steam line. 2.7 GAS SIDE FLOW PATHS The exhaust gas that enters the HRSG will pass by the pressure part sections of the HRSG, heating the steam or water inside the tubes. The exhaust gas will pass across the pressure part sections in the following order: HP Superheater 1 - Reheater 1 - HP Superheater 2 - Reheater 2 - HP Superheater 3 - HP Evaporator 1 – HP Evaporator 2 The gas then passes across the remaining pressure parts sections in the following order: IP Superheater - HP Economizer 1 - LP Superheater - HP Economizer 2 - IP Evaporator - HP Economizer 3 - IP Economizer 1 - LP Evaporator - HP Economizer 4 - Condensate Feedwater Preheater. The exhaust gas will leave FW Preheater and exit the HRSG through the main exhaust stack. Some changes may occur in the pressure sections such as surface oxidation. In addition, normal operation of the boiler may result in some bowing of the tubes due to normal manufacturing tolerances. Both of these conditions are considered normal and are expected. 2.8 SCR – SELECTIVE CATALYTIC REDUCTION SYSTEM (Not used at Nubaria) N/A 2.9 START-UP VENTS The HP main steam outlet piping incorporates a remotely operated vent valve at a location just upstream of the main steam outlet check valve. This valve is used to vent air and non-condensables from the system during start-up and to relieve excess steam pressure during steam system transients. 2.10 SKY VENTS The sky vents system consists of a shut off manual valve, a control valve, the flow orifice and the steam silencer. Whenever the control valve opens, steam releases into the atmosphere. The flow orifice determines the steam flow to be added to the total steam flow for drum level control. The steam silencer reduces the noise through this vent line. 2.11 MAIN STEAM TO COLD REHEAT BYPASS (Not used at Nubaria) N/A
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2.12 CONDENSATE PREHEATER BYPASS & RECIRCULATION The Condensate PreHeater recirculating pump performs the following function: Control of the Condensate PreHeater inlet temperature during gas and oil fired operation in order to avoid an exhaust gas temperature to be below the acid dew point. Each HRSG uses a single Condensate PreHeater recirculating pump. Temperature measuring points are arranged at the inlet of the Condensate PreHeater and at the outlet of the PreHeater for temperature monitoring. A safety valve is installed in the LP feedwater inlet line at the upstream of FW Heater for over pressure protection of the FW Heater when it is isolated. 2.13 DRAINS AND VENTS 2.13.1 SUPERHEATER & REHEATER DRAINS: Superheater and Reheater drains are provided to take out the condensate from the piping. Drain valves shall open and close based on the operating logic. 2.13.2 VENTS AND DRAINS: Vents and drains in water line such as economizer can be used for maintenance purpose. During normal operation, these valves should be closed.
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2.14 Steam Drum
FIG. 2-1 DRUM INTERNAL CENTRIFUGAL TYPE (TYPICAL)
The drums shall be of fusion welded construction,
fabricated carbon steel plate and equipped with two (2) manway openings, one at
each end of the drum accessible from the drum
end platform.
Drum Internals The steam drums will
include primary centrifugal type unitized steam separators with corrugated plate dryers
and dry box.
Drum Connections Connections are provided
on the steam drums for steam outlet feed inlet,
riser and downtake, venting, safety valves,
surface blowdown, feedwater regulators, water
columns, chemical feed, and nitrogen blanketing.
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2.15 OVERALL PROJECT A gas turbine combined with a triple-pressure HRSG with reheat and HP/IP/LP steam turbines form the combined cycle plant at the Nubaria Power Station. The HRSG utilizes the hot exhaust gas from the gas turbine to generate steam in three cycles: high pressure, intermediate, and low pressure. Steam produced is directed to the steam turbine. The HRSG is also equipped with a reheater section to reheat steam, which has passed through the HP turbine and direct it to the IP turbine. The Predicted Performance data provided at the end of this section addresses multiple operating conditions for the HRSG. Ambient conditions ranged from a modest 15 °C (59 °F) on up to 40 °C (104 °F) were reviewed. Maximum HP steam flow 71.19 Kg/s occurs at 129.2 bar and 567.7 °C. 2.16 SCHEMATIC OVERVIEW Figure 2-3 (At the end of this section) provides an overview of the fluid flow paths, both series and parallel, which integrate the HRSG into the larger system of separators, coolers, preheaters, pumps, and turbines. Rather than simply being a radiator, the integration of this complex heat transfer system results in one of the most cost effective and efficient electric power production units in the world. 2.17 GAS SIDE FLOW PATHS Gas Turbine exhaust gas enters the HRSG at approximately 3,465,000 #/hr at 1121 °F. The exhaust gas passes through the following sections: • HP Superheater 1
• Reheater 1
• HP Superheater 2
• Reheater 2
• HP Superheater 3
• HP Evaporator
• IP Superheater
• HP Economizer 1
• LP Superheater
• HP Economizer 2
• IP Evaporator
• HP Economizer 3
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• IP Economizer 1
• LP Evaporator
• HP Economizer 4
• FW Heater
2.18 Predicted performance The following Table list multiple data points where performance will be measured either during normal operation, or during commissioning. Actual numbers will vary with load and system deterioration, as maintenance is needed. Critical values for safe operation will be covered in the operation sections. Note that the data reflects one specific case description. Case descriptions can be generated for various conditions such as ambient temperature and whether or not the GT evaporative Cooler is on or off.
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Case Number 1 2 3 4 5Case Name CASE01 CASE02 CASE03 CASE04 CASE05Case Description NG, 27C
ambient, 100% load, 2x2x1
NG, 15C ambient 100%
load, 2x2x1
NG, 40C ambient, 100% load, 2x2x1
NG, 20.7C ambient, 100%
load, 1x1x1
NG, 20.7C ambient, 65%
load, 1x1x1Ambient Temperature °C 27.0 15.0 40.0 20.7 20.7Relative Humidity % 65 60 60 65 65Atmospheric Pressure bara 1.01 1.01 1.01 1.01 1.01HRSG Performance Status Guaranteed Predicted Predicted Predicted PredictedGas Turbine Load % 100 100 100 100 65Number of Gas Turbines Operating 2X2X1 2X2X1 2X2X1 1X1X1 1X1X1Gas Turbine Fuel NG NG NG NG NGGas Turbine Exhaust Flow kg/s 630.90 661.00 594.70 647.30 488.20Gas Turbine Exhaust Temperature °C 598.4 589.7 610.9 593.5 578.5. O2 12.48 12.64 12.13 12.57 13.38Exhaust Gas N2 73.59 74.52 72.05 74.12 74.39Constituents CO2 3.84 3.88 3.80 3.86 3.47% by Volume H2O 9.23 8.08 11.17 8.58 7.87. Ar 0.86 0.87 0.84 0.87 0.87Miscellaneous Heat Loss kW 842 860 829 863 639Casing Heat Loss kW 842 860 829 863 639HP Steam Flow at Terminal Point (1) kg/s 71.19* 72.21 69.96 76.67 57.00HP Steam Temperature (+/- 3°C) °C 567.7* 559.3 573.1 565.8 560.6HP Steam Pressure at Terminal Point bara 129.2 130.3 125.0 74.5 55.4HP Blowdown Rate % 0.0 0.0 0.0 0.0 0.0HP Pinch Point °C 6.3 6.5 6.0 9.3 6.9HP Approach Temperature °C 9.0 8.6 8.9 3.1 1.1HP Desuperheater Spraywater Flow kg/s 0.00 0.00 0.77 0.00 0.00HP Feedwater Temperature °C 112.7 112.5 112.6 113.6 114.2Hot RH Steam Flow kg/s 81.53 83.37 79.03 83.64 62.02Hot RH Steam Temperature °C 566.5* 558.5 572.8 565.2 557.9Hot RH Steam Pressure at Terminal Point bara 23.4 23.7 23.1 13.2 9.7RH Desuperheater Spray kg/s 0.00 0.00 0.83 0.00 0.00Cold RH Steam Flow to HRSG kg/s 70.03 71.12 67.57 73.94 54.80Cold RH Steam Temperature °C 330.2 325.5 332.8 357.2 354.2Cold RH Steam Pressure at Terminal Point bara 25.5 25.5 24.9 15.7 11.8Reheater Pressure Drop bar 2.1* 1.80 1.80 2.50 2.10IP Steam Flow to Cold RH Inlet (1) kg/s 11.50* 12.25 10.63 9.70 7.22IP Steam Temperature (+/- 3°C) °C 324.4 324.3 323.0 296.9 277.4IP Steam Pressure at Terminal Point bara 25.5 25.5 24.9 15.7 11.8IP Pegging Steam Flow to Deaerator (4) kg/s 0.0 0.0 0.0 0.0 0.0IP Blowdown Rate % 0.0 0.0 0.0 0.0 0.0IP Pinch Point °C 16.2 17.0 15.3 15.5 12.6IP Approach Temperature °C 15.8 16.0 15.8 9.9 9.4IP Feedwater Temperature °C 112.0 112.0 112.0 112.1 112.2LP Steam Flow to Steam Turbine (1) kg/s 8.47* 9.43 8.35 8.59 6.45LP Steam Temperature (+/- 3°C) °C 296.0* 297.2 293.6 268.9 253.8LP Steam Pressure at Terminal Point bara 5.2 5.2 5.0 3.0 2.2LP Pegging Steam Flow to Deaerator (4) kg/s 0.37 1.56 0.60 1.99 1.77LP Blowdown Rate % 0.0 0.0 0.0 0.0 0.0LP Pinch Point °C 24.1 25.4 23.7 24.0 19.3LP Approach Temperature °C 48.5 47.9 45.8 33.4 22.8LP Feedwater Temperature °C 111.4 111.4 111.4 111.4 111.4Deaerator Operating Pressure bara 1.5 1.5 1.5 1.5 1.5FW Flow at Deaerator Inlet kg/s 91.19 92.33 89.36 92.97 68.90FW Preheater Bypass Flow kg/s 0.0 0.0 0.0 0.0 0.0FW Preheater Outlet Water Temperature
°C 109.3 101.0 107.3 98.5 96.1
FW Preheater Inlet Water Temperature °C 51.7 51.7 51.7 51.7 51.7FW Preheater Recirculation Flow kg/s 12.10 40.00 12.75 28.00 24.75FW Preheater Supply Water Temperature
°C 44.0 30.3 43.7 37.5 35.7
Gas Temperature Leaving HRSG °C 122.6 121.6 119.9 115.0 105.2Gas Side Static Pressure Loss (2) mm water 255.0* 274.9 231.1 258.7 153.1Inside Fouling Factor m2-°C/W 0.0000176 0.0000176 0.0000176 0.0000176 0.0000176Outside Fouling Factor m2-°C/W 0.000335 0.000335 0.000335 0.000335 0.000335
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Case Number 6 7 8 9Case Name CASE06 CASE07 CASE08 CASE09Case Description OIL, 27C
ambient, 100% load,2x2x1
OIL, 15C ambient, 100%
load, 2x2x1
OIL, 40C ambient, 100% load, 2x2x1
NG, 20.7C ambient, 100%
load, 1x1x1Ambient Temperature °C 27.0 15.0 40.0 20.7Relative Humidity % 65 60 60 65Atmospheric Pressure bara 1.01 1.01 1.01 1.01HRSG Performance Status Guaranteed Predicted Predicted PredictedGas Turbine Load % 100 100 100 100Number of Gas Turbines Operating 2X2X1 2X2X1 2X2X1 1X1X1Gas Turbine Fuel OIL OIL OIL OILGas Turbine Exhaust Flow kg/s 647.80 678.80 610.50 664.70Gas Turbine Exhaust Temperature °C 575.0 566.8 586.8 570.4. O2 11.78 11.93 11.46 11.87Exhaust Gas N2 71.53 72.41 70.06 72.03Constituents CO2 5.06 5.12 5.01 5.09% by Volume H2O 10.76 9.67 12.62 10.14. Ar 0.84 0.85 0.82 0.84Miscellaneous Heat Loss kW 734 739 718 746Casing Heat Loss kW 734 739 718 746HP Steam Flow at Terminal Point (1) kg/s 69.64* 70.59 68.91 75.95HP Steam Temperature (+/- 3°C) °C 549.0* 541.2 559.8 546.6HP Steam Pressure at Terminal Point bara 123.4 125.0 123.2 72.3HP Blowdown Rate % 0.0 0.0 0.0 0.0HP Pinch Point °C 6.5 6.7 6.1 9.5HP Approach Temperature °C 7.0 6.7 7.9 1.7HP Desuperheater Spraywater Flow kg/s 0.00 0.00 0.00 0.00HP Feedwater Temperature °C 142.4 149.5 149.6 150.2Hot RH Steam Flow kg/s 78.38 77.96 75.45 76.99Hot RH Steam Temperature °C 548.2* 541.3 559.5 547.8Hot RH Steam Pressure at Terminal Point bara 22.8 22.4 22.2 12.5RH Desuperheater Spray kg/s 0.00 0.00 0.00 0.00Cold RH Steam Flow to HRSG kg/s 68.52 69.24 67.33 72.56Cold RH Steam Temperature °C 319.9 310.3 324.2 342.0Cold RH Steam Pressure at Terminal Point bara 24.6 24.1 23.8 15.5Reheater Pressure Drop bar 1.80 1.70 1.60 3.00IP Steam Flow to Cold RH Inlet (1) kg/s 9.86* 8.72 8.12 4.43IP Steam Temperature (+/- 3°C) °C 318.4 317.7 318.9 290.9IP Steam Pressure at Terminal Point bara 24.6 24.1 23.8 15.5IP Pegging Steam Flow to Deaerator (4) kg/s 2.8 4.97 3.78 6.93IP Blowdown Rate % 0.0 0.0 0.0 0.0IP Pinch Point °C 17.3 18.4 16.5 17.2IP Approach Temperature °C 10.9 9.7 10.1 3.1IP Feedwater Temperature °C 141.6 148.7 148.7 148.8LP Steam Flow to Steam Turbine (1) kg/s 0.0 0.0 0.0 0.0LP Steam Temperature (+/- 3°C) °C 293.2* 294.1 291.7 270.5LP Steam Pressure at Terminal Point bara 4.6 4.7 4.7 4.6LP Pegging Steam Flow to Deaerator (4) kg/s 10.86 11.53 10.43 8.89LP Blowdown Rate % 0.0 0.0 0.0 0.0LP Pinch Point °C 26.5 27.9 26.0 23.1LP Approach Temperature °C 18.5 11.1 9.5 6.8LP Feedwater Temperature °C 140.9 148.0 148.0 148.0Deaerator Operating Pressure bara 3.7 4.5 4.5 4.5FW Flow at Deaerator Inlet kg/s 79.51 79.31 77.03 80.38FW Preheater Bypass Flow kg/s 79.51 79.31 77.03 80.38FW Preheater Outlet Water Temperature
°C 42.6 28.0 41.8 36.6
FW Preheater Inlet Water Temperature °C N/A N/A N/A N/AFW Preheater Recirculation Flow kg/s N/A N/A N/A N/AFW Preheater Supply Water Temperature
°C 42.6 28.0 41.8 36.6
Gas Temperature Leaving HRSG °C 171.5 174.9 172.0 168.5Gas Side Static Pressure Loss (2) mm water 272.9* 294.4 247.4 277.8Inside Fouling Factor m2-°C/W 0.0000176 0.0000176 0.0000176 0.0000176Outside Fouling Factor m2-°C/W 0.000335 0.000335 0.000335 0.000335
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Notes: 1) Steam productions rates based on specified feedwater inlet temperature. 2) Static gas side pressure loss from HRSG ductwork inlet to exhaust stack outlet including: Stack Damper, Stack Silencer, Exhaust Stack 3) Stack Height: 82 m, Stack I.D.: 6.86 m, Site Elevation: 9 m 4) From superheated steam line. 5) The performance guarantee(s) for steam flow is given without tolerance. However, a measuring uncertainty as allowed by ASME PTC 4.4 will be considered for evaluation of any performance deviation. 6) Cold reheat steam flow and temperature before mixing with IPSH steam is as stated in Specification 10037-9-3PS-MBPR-00001 Appendix C Table 7.0A. (*) These points guaranteed. All others predicted.
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1 - 26" (or 30") 106C/40 Manifold to beprovided by DA
SECTION 3: AUXILIARY SYSTEMS AND EQUIPMENT 3.1 LEARNING OBJECTIVES Describe the purpose, function and basic operation of the auxiliary system and components of the HRSG. 3.2 SAFETY VALVES Safety valves are devices that protect the steam and water circuits of the boiler against accidental over pressurization. They provide the final protection against pressure part damage when other means, such as control and interlock systems fail or cannot react fast enough. The A.S.M.E. Boiler and Pressure Vessel Code states that safety valves are required on every pressure vessel. The boiler code also requires that the safety valves have a total steam relieving capacity at least equal to the rated full load steam flow of the boiler. 3.2.1 Description Each safety valve consists of a valve disc and seat, which form the seating surfaces. The disc is attached to the valve stem, called spindle, which extends up through the valve body. See Figure 3-11. A spring is used to provide the necessary force to hold the disk against the valve seat until the steam pressure below the disk forces the valve open, overcoming the spring compression. The compression screw is used to adjust spring compression or the popping pressure at which the safety valve opens. Upper and lower adjusting rings are provided inside the valve body near the valve disc and seat. The upper adjusting ring is used to adjust the “blowdown” or the difference between the valve opening and closing pressure. The lower adjusting ring is provided to obtain a quick popping action and to cushion the closing of the valve.
3.2.2 Hydrostatic Test Plugs and Valve Gags Hydrostatic test plugs are installed between the valve disc and seat for two purposes. • To protect the valve seating surfaces during shipment. • To increase spring compression to prevent the valve from opening during initial hydrostatic
testing. These plugs must be removed before initial valve setting during boiler start-up. Safety valve gags prevent the safety valve from opening during hydrostatic tests and are also used when setting safety valves and when making valve adjustments. A typical Safety Valve Gag is shown in Figure 3-2.
NOTE:
Under no circumstances should gags be left on during normal operation.
3.2.3 Safety Valve Operation Steam pressure in the drum or header is applied directly to the valve disc through the inlet nozzle. When the popping pressure is reached the steam pressure overcomes the force of the spring and the disc and spindle is pushed up opening the valve. This is called the “full life” position. The reaction force of the steam blowing between the disc and the seat holds the valve open. With the safety valve open the system steam pressure drops. When the spring pressure overcomes the steam pressure, the disc and spindle return to the closed position. Figure 3-3 shows a typical safety valve in both the open and closed positions.
3.2.5 Safety Valve Precautions The following are suggested guidelines to follow when working with or near safety valves. • Do not go near the discharge side of a safety valve. • The safety valve body drain must be piped to a safe area. If left open, steam will escape
and present a burn hazard to personnel near the valve. • Always gag a safety valve before making ring adjustments. • Exercise caution when examining a safety valve for audible leakage. Superheated steam is
3.2.6 Exhaust Piping Arrangement The exhaust from the safety and the relief valves are not attached to the building steel, and are free to move inside the vent pipe that vents the steam to the atmosphere. Only the vent pipe is attached to the building steel framework. Drains from the drip pan and exhaust vent pipe remove condensate. Vent piping is not connected to the valve body and should discharge the steam to a safe location. Proper drainage installation will prevent condensate buildup in the valve body and drip pan.
3.3 WATER LEVEL GAUGE The primary function of water gauges and indicators is to provide the operator with a readily visible means of monitoring the water level within the steam drums at all times. Proper water level in steam drums is crucial during HRSG operation for the following reasons: • Too low a water level in a steam drum may cause reduction and/or loss of circulation in the
tube circuits. • Too high a water level will reduce the effectiveness of the steam separators and dryers in
the drums causing water carry-over to the superheating tube assemblies. 3.3.1 Location The water gauge level indicator is attached to the end of each steam drum to allow visual monitoring of the steam drum water level. In accordance with the A.S.M.E. code for power boilers, a minimum of two (2) steam drum level indicators must be in service on the boiler steam drum at all times. In addition to the water level gauge, three level transmitters are also attached to the steam drum. 3.3.2 Description Normal operating water level in the steam drum is approximately the centerline of the drum. (See Figures 4-3, 4-4 and 4-5 for Drum Level Setpoints for the LP, IP, and HP Drums). The centerline of the gauge glass is located slightly below the normal water level (NWL) to correct for sub-cooling effects during operation. The gauge assembly typically consists of a steel body with flat glass faces. The tie-bar (necessary on only one end of these drums) includes upper and lower valves, which provide isolation of the water gauge for servicing and a connection for draining. This type of gauge requires a rear positioned illuminator. The illuminator is a device, which provides an electric lamp source for better viewing. The centerline of the water gauge glass is location slightly below the normal water level to correct for sub cooling effects during operation. Sub cooling is a condition when the water in the lower gauge glass connection is cooler than the water in the steam drum. The level in the water gauge will be lower than the actual level in the drum because the density in the gauge is greater than that of the steam drum. Placing the gauge centerline below the drum centerline compensates for the density difference between the water gauge and the steam drum. The water gauge body is attached vertically to a support column, which is connected to the water and steam sides of the steam drum through connections provided on the end of the steam drum. The water gauge is assembled from glass along with the necessary gaskets for sealing against drum pressure and temperature.
The drum water level is visible in the water gauge at all times, no matter how rapidly the water may rise or fall within the steam drum. This enables the operator to take an accurate reading at any time during operation. 3.3.3 Operation Water gauges use the principle of liquid seeking a level between two connected vessels. The top of the gauge glass is connected to the steam space of the drum. The bottom of the gauge connection is below the normal water level of the drum. This arrangement will allow the liquid in the gauge to rise to a level indicative of the level in the steam drum. Water in the gauge glass is cooler than water in the vessel and is denser. This results in a gauge water level, which is lower than the true water level in the vessel. Although this is compensated for, the operator must be cautioned to look for any other conditions, which may also lead to variations in gauge levels, such as: • Plugged connection lines that will cause abnormal level readings, which can be corrected by
proper lowdown. • Steam leaks that will reduce the pressure in the steam space of the gauge and will cause
the water level in the gauge to rise. Steam leaks should be properly corrected to prevent damage to the gauge gasket-seating surface as well as to prevent false readings.
3.3.4 Water Gauge Blowdown The procedure for water gauge blowdown is as follows:
a. Make sure that the gauge glass can be isolated and drained separately from the transmitter. (See Figure 3-5)
b. Close the upper and lower gauge valves. c. Open the drain valves and drain the gauge. d. Crack open the upper valve and allow the rush of steam to pass through the gauge,
cleaning the glass. e. Close the upper valve. f. Inspect the gauge for cleanliness and if necessary repeat 3 and 4. g. Close the drain valve and slowly open the upper and lower gauge valves.
The gauge should now be clean and ready for service.
Figure 3-5: Gauge Glass and Drum Level Indicators For operation and care of the gauge glasses and level transmitters, refer to the unit Instruction Manuals.
3.4 SELECTIVE CATALYTIC REDUCTION SYSTEM (SCR) Not Applicable (N/A) to Nubaria 3.5 COEN DUCT BURNER N/A to Nubaria 3.6 NITROGEN OXIDE(S) N/A to Nubaria
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SECTION 4: DRUM LEVEL and PROCESS CONTROL 4.1. LEARNING OBJECTIVES • Explain the drum three-element drum level control function using drum level, feedwater flow,
and steam flow. Additionally, provide a fundamental list of other process controls typical to this type of three-drum HRSG system.
• Describe the monitoring and supervision provided for on the HRSG and supervision
provided for on the HRSG and list what parameters will initiate a unit Gas Turbine run back or possible trip.
4.2 CONCEPT for LP, IP, and HP DRUM LEVEL CONTROLS The Feedwater control system modulates the rate of feedwater flow to the boiler to match the steam demand leaving the boiler. A relatively constant drum level is maintained by the control system throughout the operating load range of the boiler. Controlled steam drum level is important for two significant reasons. • An excessively low water flow will expose boiler tubes resulting in overheating of the tube
metal. • An excessively high water level will interfere with the steam-water separating equipment in
the steam drum. Water separation becomes less effective and some water will be entrained in the steam leaving the drum. Water is then carried over with the steam, resulting in damage to plant equipment.
When load demand changes occur, the amount of steam required by the turbine/process changes. The flow of feedwater to the boiler must also change to meet the new load demands. The drum level control system provides for the necessary balance between the turbine and the boiler. An accurate measure of the balance between boiler fluid input and steam flow output is steam drum level. The feedwater control system sustains this balance by maintaining the proper fluid storage level within the boiler at all times. 4.2.1 Drum Level Control HP Drum Level Control (Drum level will be corrected by the drum pressure). Normal Level: The drum level control will regulate the rate of feed water flow to maintain a proper drum level throughout the operation range of the steam generator. To get the maximum benefit from a three-element system, the feed water flow should be proportional to steam flow with reset action on drum level which means that the mass of feed water entering should always be equal to the mass of steam leaving, with continuous corrections made for deviations from level set points.
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• HP FW By-pass Control Valve (V-108) will open & close (modulate) to maintain drum NWL set point, when HP FW Control Valve (V-100) is opened <20%.
• HP FW Control Valve (V-100) will open & close (modulate) to maintain drum NWL set point, when HP FW By-pass control valve (LV-D05B) reaches 80% opening.
• When HP FW Control Valve (V-100) is opened >20%, then HP FW By-pass Control Valve (V-108) shall be closed fully.
• HP FW Control Valve (V-100) shall be closed fully if valve opening < 15%. Required actions: High High level: Sound the alarm. Close the HP Feedwater Stop Valve (HV-102). Ensure that HP Feedwater By-pass Control Valve is closed (V-108) GT protective load shedding (*). HP Feedwater Stop Valve (HV-102) remains closed. High level: Sound the alarm. Open the HP Evap Intermittent Blow-off Isolation Valve (HV-180). Low level: Sound the alarm. Low Low Level: Sound the alarm. GT protective load shedding (*). GT trip (after 2 min. of total elapsed time) if alarm not cleared. (*) PLS will bring GT to zero load within 2 minutes (GT gas temperature is expected to be
~50% of its full scale). PLS will continue until correcting the cause of problem and process returns to normal.
IP Drum Level Control: (Drum level will be corrected by the drum pressure). Normal Level: The drum level control will regulate the rate of feed water flow to maintain a proper drum level throughout the operation range of the steam generator. To get the maximum benefit from a three-element system, the feed water flow should be proportional to steam flow with reset action on drum level which means that the mass of feed water entering should always be equal to the mass of steam leaving, with continuous corrections made for deviations from level set points.
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• IP FW Control Valve (LV-430) will open & close (modulate) to maintain drum NWL set point. Required actions: High High level: Sound the alarm. Close the IP Feedwater Stop Valve (HV-400). GT protective load shedding (*). IP Feedwater Stop Valve (HV-400) remains closed. High level: Sound the alarm. Open the IP Evap Intermittent Blow-off Isolation Valve (HV-480). Low level: Sound the alarm. Low Low Level: Sound the alarm. GT protective load shedding (*). GT trip after 2 minutes (maximum total elapsed time) if alarm not cleared. (*) PLS will bring GT to zero load within 2 minutes (GT gas temperature is expected to be
~50% of its full scale). PLS will continue until correcting the cause of problem and process returns to normal.
LP Drum Level Control: (Drum level will be corrected by the drum pressure). Normal Level: The drum level control will regulate the rate of feed water flow to maintain a proper drum level throughout the operation range of the steam generator. To get the maximum benefit from a three-element system, the feed water flow should be proportional to steam flow with reset action on drum level which means that the mass of feed water entering should always be equal to the mass of steam leaving, with continuous corrections made for deviations from level set points. • LP FW By-pass Control Valve (V-819) will open & close (modulate) to maintain drum NWL
set point, when LP FW Control Valve (LV-801) is opened <20%. • LP FW Control Valve (LV-801) will open & close (modulate) to maintain drum NWL set point,
when LP FW By-pass control valve (V-819) reaches 80% opening. • When LP FW Control Valve (LV-801) is opened >20%, then LP FW By-pass Control Valve
(V-819) shall be closed fully. • LP FW Control Valve (LV-801) shall be closed fully if valve opening < 15%.
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Required actions: High High level: Sound the alarm. Close the LP Feedwater Stop Valve (HV800) GT protective load shedding (*). LP Feedwater Stop Valves (HV-800) remains closed. High level: Sound the alarm Open LP Evap Intermittent Blow-off Isolation Valve (HV-825). Low level: Sound the alarm. Low Low Level: Sound the alarm. GT protective load shedding (*). GT trip (after 2 minutes maximum total elapsed time) if alarm not cleared. (*) PLS will bring GT to zero load within 2 minutes (GT gas temperature is expected to be
~50% of its full scale). PLS will continue until correcting the cause of problem and process returns to normal.
Dearator Storage Tank and Condensate Preheater Condensate Preheater Bypass Operation When operating the HRSG Unit with high sulfur fuel, the Condensate Preheater should be bypassed. To bypass the Condensate Preheater, the Condensate Preheater Feedwater Stop Valve (HV-002) is closed and the Condensate Preheater Bypass Stop Valve (HV-003) is opened, resulting in all of the flow bypassing the Condensate Preheater. Online Switch Over to Engage Condensate Preheater Recirculation In order to accomplish an on-line switch over while the HRSG is in operation and reengage the Condensate Preheater Recirculation, turn on the Condensate Preheater Recirculation Pump (PMP-040) and open the Recirculation Pump Discharge Control Valve to 100% open. To prevent thermal shock of the Preheater manifold, keep the Condensate Preheater Bypass Stop Valve (HV-003) open for 15 minutes after opening the Condensate Preheater Feedwater Stop Valve (HV-002). Set the Feedwater Heater Recirculation Control in AUTO mode. Pegging Steam Control Pegging steam flow from the IP and LP Systems will be controlled by the Pegging Steam Control Valves (PV-001D, PV-002D and PV-003D) to maintain the Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at a set point established by the heat balance and process requirements.
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4.2.2 Description The feedwater control system is a control loop that, when in automatic maintains a balance of feedwater entering the boiler with the amount of steam leaving the boiler. The control system also keeps the volume of boiler water within the steam drum to an established set point level during operation. The feedwater control system is referred to as a “three-element control system” because three system measurements, or variables, are used to determine the required feedwater rate to the boiler. The three elements monitored are: • Drum level • Feedwater flow • Steam flow The three monitored elements, steam flow, steam drum level and feedwater flow, are measured and converted into electrical signals. The signals are transmitted as feedback control signals, to the control room. The use of three different elements provides a quick response when transients, or changes, occur during unit operation. The Feedwater control system is an analog control system. Drum level is the controlled variable. Feedwater flow is the manipulated variable. 4.2.3 Principles of Operation Drum level is related to, but is not a direct indicator of the quantity of water in the steam drum. Under different and varying steam loads, the steam bubbles occupy a different and varying volume of steam and water mixture. The mixture volume is related to the pressure in the steam drum. Two conditions can affect accurate drum level control. Figure 4-1 depicts these two conditions, called Shrink and Swell. 4.2.4 Shrink In the case of shrink, an increase in pressure in the steam drum due to decreased steam flow results in the water in the steam drum dropping to a temperature lower than saturation. This will cause some of the steam bubbles to condense back into water and others to contract under the increased pressure. The level in the steam drum decreases. The amount of level decrease, or shrink, is dependent on the steam pressure within the steam drum. The greater the rise in steam pressure, the more the level will decrease. The effect shrink produces is a decreasing level even though less mass is actually leaving the steam drum.
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4.2.5 Swell If the steam pressure within the drum decreases due to an increase in steam flow, the water temperature within the drum is raised above the saturation temperature for that pressure. This causes some of the water to form additional steam bubbles, and the steam bubbles that are raising in the riser tubes will also expand. To maintain the continued flow of water through the riser tubes, the drum level will increase (swell). The amount of level rise is dependent on the steam pressure within the steam drum. The more the steam pressure decreases the greater the rise in drum level. The result of swell is that the level in the steam drum increases even though additional mass is actually leaving the steam drum.
Figure 4-1: Shrink and Swell in a Steam Drum
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4.2.6 Functional Level Control Operation This use of the steam flow and feedwater flow signals minimizes the effects of shrink and swell. The three-element control system provides a smoother control of the drum level. (Figure 4-2).
Figure 4-2: Three Element Control With no load changes, steam flow and feedwater flow should be equal to maintain a steady steam drum water level. The steam flow and feedwater flow signals are compared with each other to develop an error signal. This is the flow error (FR) signal. The measured drum level drum level is then compared with the flow error to provide a total error or level-flow error (LE)
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signal that is then sent to the level controller (LC). The total error is compared with the setpoint to provide the error signal that positions the feedwater control valve. • In a swell condition (water level is increasing), the water level signal alone will call for less
water. However, this would starve the boiler because the swell condition is caused by an increased steam flow (decreased steam pressure), which means more water is needed. By comparing the water level error with the steam flow, the amount of increased water flow called for by the steam and water flow error is balanced against the decrease in flow called for by the rising drum level. This action will continue to occur until steam pressure is restored to normal by stabilizing load demand at a new level. As the water level decreases to normal, more water is allowed to enter the boiler until feedwater flow equals steam flow.
• The drum level signal is density compensated to generate a corrected drum level signal to
the drum level controller. • To control swell during start-up, drum levels are maintained at a lower control level, just
above its low water alarm setpoint, until steam flow reaches 10% of full flow for that system.
NOTE: The following process control statements are generic for a typical 3 drum HRSG with reheater, fed by a GT and coupled to an HP/IP/LP steam turbine set. Please review final operating recommendation for your actual unit operating process logic: 4.3 DEAERATOR STORAGE TANK LEVEL (Set Points for 3658 mm (144”) OD DA
STORAGE TANK)
Level Comments or Control actions Start-up Set Points
Normal Operating Set Points
High High • Sound the alarm • After time delay, close the feedwater stop valve • Feedwater control valve should be closed.
+1372mm (+54”)
+1372mm (+54”)
High • Sound the alarm, permit opening of the feedwater valve
+1219mm (+48”)
+1219mm (+48”)
Normal • The DA storage tank level controls will regulate the rate of feedwater flow to maintain a proper drum level throughout the operation range of the steam generator.
+566 mm (+22.3”)
+566 mm (+22.3” )
Low • Sound the alarm • Open the feedwater stop valve (automatic).
-1524 mm (-60”)
-1524 mm (-60”)
Low Low • Alarm • Feedwater Control Valve should be open • Initiate GT normal runback • Stop and hold runback if low level alarm is cleared.
-1676 mm (-66”)
-1676 mm (-66”)
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LP DRUM LEVEL (Gage Visibility = XX) Set Points for 1524 mm (60”) ID LP Drum
Level Comments or Control actions Start-up Set Points
Normal Operating Set Points
High High • Sound the alarm • After time delay, close the feedwater stop valve • Feedwater control valve should be closed.
+229 mm (+9”)
+229 mm (+9”)
High • Sound the alarm, permit opening of the feedwater valve
+178 mm (+7”)
+178 mm (+7”)
Normal • The drum level controls will regulate the rate of feedwater flow to maintain a proper drum level throughout the operation range of the steam generator.
-533 mm (-21”)
0 mm (0” )
Low • Sound the alarm • Open the feedwater stop valve (automatic).
-584 mm (-23”)
-102 mm (-4” )
Low Low • Alarm • Feedwater Control Valve should be open • Initiate GT normal runback • Stop and hold runback if low level alarm is cleared.
-635 mm (-25”)
-635 mm (-25”)
Figure 4-3: Table of LP Drum Level Control Settings
4.4 LP STEAM VENT VALVE CONTROL • Open if drum pressure is less than 25 psig. • Closed if drum pressure is greater than 25 psig. • Provide manual override for nitrogen blanketing. Note: For lay-up with nitrogen blanket, valve shall remain closed independent of pressure.
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4.5 IP DRUM LEVEL (Gage visibility = XX) Set Points for 1372 mm (54”) ID IP Drum
The drum level controls will regulate the rate of feedwater flow to maintain a proper drum level throughout he operation range of the steam generator. Level Comments or Control action Start-up
Set Points
Normal Operating Set Points
High High Sound the alarm After time delay, close the feedwater stop valve Feedwater control valve should be closed
+229 mm (+9”)
+229 mm (+9”)
High Sound the alarm, permit opening of feedwater stop valve
+178 mm (+7”)
+178 mm (+7”)
Normal The drum level controls will regulate the rate of feedwater flow to maintain a proper drum level throughout the operation range of the steam generator.
-457 mm (-18”)
0 mm (0”)
Low Sound the alarm Open the feedwater stop valve. Close the IP drum continuous blowdown motor operated stop valve.
-508 mm (-20”)
-102 mm (-4”)
Low Low Alarm Feed control valve should be open Initiate GT normal runback. Stop and hold runback until low level alarm is cleared and reset by operator.
-559 mm (-22”)
-559 mm (-22”)
Figure 4-4: Table of IP Drum Level Control Settings
To get the maximum benefit from a three-element system, feedwater flow should be proportional to steam flow with reset action on drum level. This means that the mass of feedwater entering should always equal the mass of steam leaving, with periodic small corrections made to correct deviations from level set points. The best drum level control is achieved through the mass flow balance. 4.6 IP DRUM CONTINUOUS BLOWDOWN ISOLATION VALVE • Open if level is > than low AND superheated steam flow is > than 30%. • Close if level is < than low OR superheated steam flow is < than 30%.
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4.7 HRSG IP MAIN STEAM VENT VALVE • Open if drum pressure is less than 25 psig. • Closed if superheated steam flow is great than 10% • Provide manual override for nitrogen blanketing. Note: For lay-up with nitrogen blanket, valve shall remain closed independent of pressure. 4.8 IP TO LP PEGGING STEAM CONTROL Where provided, a pegging steam control valve will regulate the flow of IP Superheated steam to the LP drum to maintain minimum LP drum pressure based on operator decision. The pegging steam control valve may be left in “active” mode during natural gas firing at operator’s option. 4.9 HP DRUM CONTINUOUS BLOWDOWN ISOLATION VALVE • Open if level is > than low AND superheated steam flow is > than 30%. • Close if level is > OR superheated steam flow is < than 30%. 4.10 HP DRUM LEVEL (Gage visibility = XX) Set Points for 1829 mm (72”) ID HP Drum Level Comments or Control Action Start-up
Set Points
Normal Operating Set Points
High High Sound the alarm After time delay, close the feedwater stop valve. Feed water control valve should be closed
+292 mm (+11.5”)
+292 mm (+11.5”)
High Sound the alarm +241 mm (+9.5”)
+241 mm (+9.5”)
Normal The drum level controls will regulate the rate of feedwater flow to maintain a proper drum level throughout the operation range of the steam generator. To get the maximum benefit from a three-element system, feedwater flow should be proportional to steam flow with reset action on drum level
-686 mm (-27”)
+64 mm (+2.5”)
Low Sound the alarm Open the feedwater stop valve Close the HP drum cascade blowdown motor operated stop valve.
-737 mm (-29”)
-38 mm (-1.5”)
Low Low Alarm Feed control valve should be open Initiate GT normal runback. Stop and hold runback if low level alarm is cleared.
-787 mm (-31”)
-787 mm (-31”)
Figure 4-5: Table of HP Drum Level Control Settings
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4.11 HP STEAM TEMPERATURE CONTROL Startup Operation Required actions: Open the following valves if HP Steam Temperature (TE-1114A & TE-1114B) >568°C (1055°F): • HP Desup Spraywater Control Valve (TV-301) • HP Desup Spraywater Power Block Valve (HV-300) • Close when HP Steam Temperature (TE-1114A & TE-1114B) ≤ 568 °C (1055 °F): • Close when HP Steam Flow < min
Alarm steam temperature high ≥ 576.67 °C (1070 °F) Alarm steam temperature low ≤ 537.78 °C (1000 °F) for Natural Gas Alarm steam temperature low ≤ 530.56 °C (987 °F) for Distillate Oil Trip Duct Burner when temp. alarm = 586.7°C (1080 °F) GT protective load shedding (*) when temp. alarm ≥ 586.7°C (1080 °F) GT trip (after 2 min. of total elapsed time) if alarm not cleared. Ramp setpoint of HP Spraywater Controller based on commissioning test and on CTG signal
of 10% load. Set ramp rate according to overall design. The HP spray water block valve to open when the demand on the control valves is greater
than 3%. The HP spray water block valve to close when the demand on the control valves is less than
3% for 5 minutes. Alarm steam temperature high – equal to or greater than design plus a safe margin. Alarm steam temperature low – less than or equal or design. Initiate GT normal runback when temperature high high is equal to or greater than plus 10
degrees. Stop and hold runback if alarm is cleared. Close the HP Spraywater Control Valves on CTG trip. 4.12 HP OVERPRESSURE Required actions: Trip Duct Burner (If supplied) when HP steam pressure (PT-342) = 148.237 bar (2150 psig ) GT protective load shedding (*) when HP steam pressure (PT-342) ≥ 148.237 bar (2150 psig ), GT trip after 2 minutes of PLS, if HP steam pressure (PT-342) > 126.519 bar (1835 psig ). Set the GT normal load runback slightly below the safety valve set pressure to avoid lifting
the safety valve.
NOTE: No safety valve should be permitted to blow for more than a 15 minute period. If safety valve open continues beyond 15 minutes, the operator shall take corrective action.
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4.13 HP MAIN STEAM OUTLET VENT VALVE Open if drum pressure is less than 1.724 bar (25 psig).
Close if superheated steam flow is greater than 10%.
NOTE:
Provide manual override for nitrogen blanketing. For lay-up with nitrogen blanket, valve shall remain closed independent of pressure. 4.14 RH STEAM TEMPERATURE CONTROL Startup Operation Required actions: Open the following valves if RH Desup. Outlet Steam Temp. (TE-781A & TE-781B) > 1053 °F: • RH Desup Spraywater Control Valve (TV-701) • RH Desup Spraywater Power Block Valve (HV-700) • Close when RH Desuperheater Outlet Steam Temperature (TE-781A & TE-781B) ≤ 1053 °F
Alarm steam temperature high ≥ 570 °C (1058 °F) Alarm steam temperature low ≤ 541 °C (1006 °F) for Natural Gas Alarm steam temperature low ≤ 532 °C ( 990 °F) for Distillate Oil Trip Duct Burner (If supplied) when temp. alarm = 572.78 °C (1063 °F) GT protective load shedding (*) when temp. alarm ≥ 572.78 °C (1063 °F) GT trip (after 2 min. of total elapsed time) if alarm not cleared Ramp setpoint of Reheat Spraywater Controller based on commissioning test and on CTG
signal of 10% load. Set ramp rate according to overall design. Ramp setpoint of Reheat Spraywater Controller based on commissioning test and on
release from Turbine control. Set ramp according to overall design. At all times, maintain design minimum Superheat.
Normal Operation Set RH spray water control valves at design plus a safe margin.
The RH spray water block valve to open when the demand on the control valves is greater
than 3%. The RH spray block valve to close when the demand on the control valves is less than 3%
for 5 minutes. Alarm steam temperature high – equal to or greater than design plus a safe margin plus 10
degrees.
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Alarm steam temperature low – less than or equal to design.
Initiate GT normal runback when temperature high high is equal to or greater than 1067 °F or
575 °C . Stop and hold runback if alarm is cleared. Close the RH spraywater Control valves on CTG trip.
At all times maintain a safe minimum of Superheat.
4.15 FEEDWATER HEATER RECIRCULATION CONTROL: The condensate recirculation pump will be activated (manually) when condensate temperature (TE-005A & B) is less than the temperature set point of 135 °F. Control valve (TV-040) will start to open when pump is switched on and modulate to keep up the corresponding condensate temperature set point. 4.16 BOILER PROTECTION The water is kept constant in both drums. For HP and IP, during normal operation the signal
setting for the feed water control valve is derived from the feedwater flow minus boiler water extraction, the steam flow and the drum water level (three-element control).
4.16.1 Drum Level Low Low Level – Initiate GT normal runback. Stop and hold runback if low level alarm is
cleared.
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SECTION 5: OPERATION 5.1 LEARNING OBJECTIVES • Given a start-up condition (cold, hot) describe the actions and criteria needed to
proceed up to full load. • Given an abnormal condition, describe the proper procedures to bring the condition
back to normal state. 5.2 HRSG BOILER OPERATIONAL OVERVIEW
These procedures are intended to serve as a guide during the initial operating stages of a Heat Recovery Steam Generator (HRSG). They include the proper operating sequences for the steam generator and auxiliary equipment furnished by ALSTOM Power inc. Refer to the Piping and Instrumentation Diagram. The sequential procedures do not include detailed reference to equipment not furnished by ALSTOM Power inc., such as the feed pumps, or the gas turbine, etc. Because the steam generator is only one part of the power plant, and all equipment must operate in unison, specific procedures and detailed values cannot be included in this manual. As operating experience is gained and the controls are fine-tuned, the characteristics and operating requirements of the unit will become apparent. Refer to manufacturer's instructions for further operating details for specific equipment supplied by ALSTOM Power inc. 5.3 COMPLETION OF MAINTENANCE PRIOR TO OPERATION
Check the HRSG to make sure that all maintenance work has been completed, all tools and debris have been removed, the handhole plates and manhole covers have been installed and secured, and all access doors have been installed and secured. Check the safety valves to see that the gags have been removed, the lifting levers have been replaced, and the valves are not fouled or hung up.
NOTE: Some equipment such as Valves, Instrumentation, Pumps, etc. mentioned in this manual may not be part of Alstom Power Scope of supply, so it may not shown on the Alstom Power’s P&ID drawing or referred documents.
5.4 INITIAL FILLING
This section describes the recommended procedure for fiIIing an empty HRSG with water.
If the unit is hot, filling of a pressure level system with cold water should not be initiated until the drum metal temperature for that pressure level has cooled to within 56°C (100°F) of the incoming feedwater temperature. Filling should be done slowly, with the feedwater control valve at 10% open, to avoid severe temperature strains. Otherwise, damage may result due to relatively cool water coming into contact with heated pressure parts.
Also, since deposits of solids in a superheater can cause corrosion or inhibit heat transfer, introduction of solids by carryover of boiler water from the drum during filling, hydrostatic testing or chemical cleaning must be avoided.
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Proceed as follows:
1. Prepare feedwater pumps and plant feed piping for start-up.
2. Align all HRSG valves as shown under the column labeled “START FROM COLD” on Tables 1 through 6.
3. Make sure all drain valves are closed.
4. Before starting the Demineralized Water Pump (not in ALSTOM Power’s scope) used in initial filling operation, all feed system control valve stations should be positioned to allow for filling of the boiler, including the following (Refer to Piping and Instrumentation Diagrams):
a. Open HP Feedwater Stop Valve (HV-102).
b. Open the HP Feedwater Control Valve (LV-100) to allow for filling.
c. Open IP Feedwater Stop Valve (HV-400).
d. Open IP Feedwater Control Valve (LV-430) to allow for filling.
e. Open LP Feedwater Stop Valve (HV-800).
f. Open LP Drum Control Valve (LV-801) to allow for filling.
g. Open Condensate Preheater Feedwater Stop Valve (HV-002). Ensure that Condensate Preheater Outlet Stop Valve (V-029) is open. Condensate Preheater Bypass Stop Valve (HV-003) remains closed.
h. Open Condensate Preheater Outlet Feedwater Control Valve (LV-064) to allow for filling.
i. Open Condensate Preheater Recirc. Pump Suction Isolation Valve (V-049) and lock in open position. Open the Condensate Preheater Recirc. Pump Discharge Stop Valve (V-053) and lock in open position. Open the Condensate Preheater Recirculation Control Valve (TV-040).
j. Ensure that HP/IP Boiler Feedwater Pump Suction Stop Valve (PV-056) and LP Boiler Feedwater Pump Suction Stop Valve (V-034D) are open.
k. Ensure that HP/IP Boiler Feedwater Pump Recirculation Stop Valves (V-031D, V-032D and V-033D) and LP Boiler Feedwater Pump Recirculation Stop Valves (V-028D, V-029D and V-030D) are open.
5. Start the Demineralized Water Pump (not in ALSTOM Power’s scope) used for initial filling operations and open (approximately 4 turns) the Deaerator Feedwater Heater Vent Valves (V-016D and V-017D) and the Condensate Preheater Vent Valves (V-026 through V-027, V-080 through V-081, V-082 through V-083 (Units 1B and 2B only), and V-086 through V-087 (Units 1B and 2B only)). Fill the Deaerator Storage Tank until the Cold Start-up NWL has been cleared (see Table 10). DO NOT OVERFILL THE STORAGE TANK. Close the Condensate Preheater Vent Valves for each section when all air has been displaced from that section. Close the Deaerator Feedwater Heater Vent Valves when the Storage Tank fill is complete.
6. Maintain the level of the Deaerator Storage Tank by running the condensate pump as required. Storage Tank water level must be maintained since the HP/IP and LP Feedwater Pumps take suction from the Deaerator Storage Tank.
7. Start the Demineralized Water Pump (not in ALSTOM Power’s scope) used during initial filling operations and open (approximately 4 turns) the HP and IP Saturated
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Steam Outlet Vent Valves (V-280, V-281, V-580 and V-581) and the HP and IP Economizer Vent Valves (V-141 thru V-144, V-148 thru V-153, V-161 thru V-168 and V-433 thru V-434). Fill the HP Economizer, HP Evaporator, IP Economizer, and IP Evaporator until the Cold Start-up NWL has been cleared in the HP and IP Drums (see Tables 7 & 8). DO NOT OVERFILL THE DRUMS. Close the HP and IP Economizer Vent Valves for each section when all air has been displaced from that section. Close the HP and IP Saturated Steam Outlet Vent Valves when the HP and IP Drum fills are complete.
8. Start the Demineralized Water Pump (not in ALSTOM Power’s scope) used during initial filling operations and crack open (approximately 4 turns) the LP Saturated Steam Outlet Vent Valves (V-906 and V-907) and the LP Feedwater Inlet Vent Valves (V-901 and V-902). Fill the LP Evaporator until the Cold Start-up NWL has been cleared in the LP Drums (see Table 9). DO NOT OVERFILL THE DRUM. Close the LP Feedwater Inlet Vent Valves when all the air has been displaced from that section. Close the LP Saturated Steam Outlet Vent Valves when the LP Drum fill is complete.
9. After the drum fill is complete close HP Feedwater Control Valve (LV-100), IP Feedwater Control Valve (LV-430), LP Feedwater Control Valve (LV-801) and Condensate Preheater Outlet Feedwater Control Valve (LV-064). Place all feed system control valve stations including associated drum level controls in AUTO MODE.
All feedwater pumps can be temporarily off-line while waiting for pre-operation equipment checks and valve alignments prior to start-up. The HRSG is now ready to be started using the procedure for “START-UP FROM A COLD CONDITION”.
5.5 PRE-OPERATIONAL EQUIPMENT CHECKS
Have all HRSG auxiliary equipment lined up for operation prior to allowing flow of the gas turbine exhaust to the HRSG.
Prior to initial operation:
1. Open the Stack Damper before rolling the Gas Turbine.
2. Make sure that:
a. All instrument valves should be lined up for service.
b. Ensure that all the drum level transmitter reference legs are filled.
c. All sample line valves should be closed.
d. All chemical and nitrogen feed valves should be closed.
e. All drain valves should be closed.
3. Open and close the following valves to ensure that water level gauges are reading correctly:
a. HP Drum Level Indicator Drains (V-219, V-220, V-241 and V-242).
b. HP Drum Remote Water Level Indicator Drains (V-204 and V-205).
c. IP Drum Level Indicator Drains (V-519, V-520, V-541 and V-542).
d. IP Drum Remote Water Level Indicator Drains (V-504 and V-505).
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e. LP Drum Level Indicator Drains (V-854, V-855, V-876 and V-877).
f. LP Drum Remote Water Level Indicator Drains (V-839 and V-840).
g. Deaerator Storage Tank Level Indicator Drains (V-047D and V-048D).
h. Blowdown Tank Level indicator Drain (V-005B).
5.6 CONDENSATE PREHEATER OPERATION
Condensate Preheater Recirculation Operation The Condensate Preheater Recirculation System Functional Group should be switched ON, during normal operation of the gas turbine on Natural Gas fuel.
During normal, base load operation of the HRSG, when the GT is using Natural Gas, the Condensate Preheater Recirculation Pump (PMP-040) is switched ON when the condensate feedwater temperature is < 51.7°C (125°F). The pump is switched OFF automatically when the condensate feedwater temperature is > 55°C (131°F). The Condensate Preheater Feedwater Stop Valve (HV-002) is positioned in the fully-opened position and the Condensate Preheater Bypass Stop Valve (HV-003) Is positioned in the fully-closed position.
NOTE: A minimum temperature difference of approximately 2.5°C must be maintained between the saturation temperature in the Deaerator based on the operating pressure (PIT-001D and PIT-002D) and the incoming feedwater temperature (TE-066A and TE-066B) in order to ensure proper operation of the Deaerator.
CAUTION: The Condensate Preheater Recirculation Pump (PMP-040) must never be run with suction and discharge valves closed. Damage to the pump will occur if there is no water flow through the pump. Ensure that the Minimum Recirculation Stop Valve (V-062) is fully open before starting the pump.
5.7 START-UP FROM A COLD CONDITION
This section describes the recommended procedure for starting the HRSG from a cold condition with no pressure in the HP, IP and LP boiler sections. Proceed as follows:
1. Purge the HRSG in accordance with NFPA 85, Chapter 8.9.2 (Combustion Turbine Exhaust Systems) guidelines.
It is understood that purging is accomplished by using air at ambient temperatures. The ambient air temperatures during a normal purge cycle will not have any damaging effect on any of the HRSG components.
2. Align all HRSG valves as shown under the column labeled “START FROM COLD” on Tables 1 through 6.
NOTE: Some of the following procedures are redundant to what is shown on Tables 1 through 6. This is done to emphasize the importance of performing these procedures.
3. Open the Stack Damper before rolling the Gas Turbine.
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4. The HP Desuperheater Spray Water Control Valve (TV-301) is in ‘AUTO’. The HP Desuperheater Spraywater Control Valve Isolation Valves (V-313 and V-317) shall remain open. The HP Desuperheater Spraywater Power Block Valve (HV-300) is in ‘AUTO’.
5. The RH Desuperheater Spray Water Control Valve (TV-701) is in ‘AUTO’. The RH Desuperheater Spraywater Control Valve Isolation Valves (V-713 and V-717) shall remain open. The RH Desuperheater Spraywater Power Block Valve (HV-700) is in ‘AUTO’.
NOTE: Although desuperheating is not required except at peak turbine load, it is good practice to have the control station available whenever the unit is operating.
6. The following Drain Valves are in AUTO:
HP Superheater 1 Drain Valve (HV-284),
HP Superheater 2 Drain Valve (HV-282),
HP Superheater 3 Drain Valve (HV-280),
Allow any condensate in these sections to drain.
7. The following Drain Valves are in AUTO:
Reheater 1 Drain Valve (HV-765),
Reheater 2 Drain Valve (HV-760),
IP Superheater Drain Valve (HV-580)
Allow any condensate in these sections to drain.
8. The LP Steam Outlet Drain Valves (HV-948 and HV-949) are in AUTO. Allow any condensate to drain.
9. Prior to start up, reset the water level set points in the feedwater control system to ensure that the water levels in the HP, IP, and LP Drums and Deaerator Storage Tank are just above the Cold Start-up NWL (see Tables 7 through 10). Use the HP Evaporator (HV-180), IP Evaporator (HV-480) and LP Evaporator (HV-825) Intermittent Blow-off Valves as necessary to reduce water levels.
10. Open the HP Feedwater Stop Valve (HV-102), IP Feedwater Stop Valve (HV-400) and LP Feedwater Stop Valve (HV-800).
11. Place the Condensate Preheater in bypass by closing the Condensate Preheater Feedwater Stop Valve (HV-002) and opening the Condensate Preheater Bypass Stop Valve (HV-003). Set the Preheater Recirculation Pump (PMP-040) and Control to OFF.
12. Close the HP Main Steam Outlet Stop Valve (HV-001), open the HP Steam Startup Vent (HV-342). Engage the HP to RH Bypass Valve (not in ALSTOM Power scope) to control the HP Steam Outlet Pressure to 58.99 barg (60.00 bara).
13. Open the IP Main Steam Outlet Stop Valve (HV-604), IP Steam Startup Vent (HV-600), and the RH Steam Outlet Startup Vent (FV-780). Close the HRH Stop Valve (not in ALSTOM Power scope) and the HRH to Condenser Bypass (not in ALSTOM Power scope).
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14. Close the LP Main Steam Outlet Stop Valve (HV-919) and open the LP Steam Startup Vent (FV-915).
NOTE: When starting the second gas turbine/HRSG train, with the first train already operating, the HP Main Steam Outlet Stop Valve (HV-001), and the LP Main Steam Outlet Stop Valve (HV-919) shall remain closed until the pressure is within 5% and temperature is within 28°C of downstream piping. After permissives clear and stop valves open, the NRV in the respective lines will open once the pressures match and will then begin admitting steam.
15. If needed, restart feedwater pumps and ensure that pumps are running and all feed system valves are lined up. (See ‘START FROM COLD’ on Tables 1 through 6.)
16. Allow gas turbine exhaust flow to the HRSG by starting the gas turbine.
17. While the steam generator is being brought up to pressure, all cold steam piping should be gradually heated and drained of condensate. The HP Startup Vent Valve (HV-342), RH Steam Outlet Startup Vent Valve (FV-780), IP Startup Vent Valve (HV-600), and the LP Startup Vent Valve (FV-915) must stay opened to insure a positive flow of steam which will reduce thermal expansion.
To warm the piping downstream of ALSTOM Power scope, open the bypass valve on the HP Main Steam Outlet Stop Valve (HV-001A), the bypass valve on the LP Main Steam Outlet Stop Valve (HV-919A). Next, open a drain or vent downstream of ALSTOM Power scope to allow the steam from the bypass valve to warm the piping. Ensure that all steam piping downstream of the boiler piping is drained prior to admitting steam.
NOTE: When starting the second gas turbine/HRSG train with the first train already operational, the bypass valves on the Main Steam Outlet Stop Valves are used to warm piping.
18. Once the LP steam lines have been properly warmed, the LP steam section is “on line” with steam ready to be introduced to the Deaerator. Open the LP Main Steam Stop Valve (HV-919) and close the bypass (HV-919A). The LP Startup Vent Valve (FV-915) will modulate open / closed in order to maintain the LP Steam Outlet Pressure (PIT-915A and PIT-915B) at 4.19 barg (5.20 bara).
19. Warm the Pegging Steam Lines and drain the lines of any condensate by opening the following valves:
Low Range LP Pegging Steam Drain Valve (HV-072D).
High Range LP Pegging Steam Drain Valve (HV-004D).
IP Pegging Steam Drain Valve (HV-008D).
Close the Drain Valves after a period of at least 5 minutes.
NOTE: When starting the second gas turbine/HRSG train with the first train already operational, the Pegging Steam Lines will not require warming.
For Startup on Natural Gas Operation:
20. Modulate open / closed the Low Range Pegging Steam Control Valve (PV-002D) to maintain Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 0.99 barg (2.00 bara).
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When the Low Range Pegging Steam Control Valve (PV-002D) has reached 100% open and the Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) falls below 0.99 barg (2.00 bara), this indicates that the required pegging steam is more than the available steam from the Low Range LP Pegging Steam Control Valve (PV-002D). Switch over control of the pegging steam flow to the High Range LP Pegging Steam Control Valve (PV-001D). Completely close the Low Range LP Pegging Steam Control Valve (PV-002D). Modulate open / closed the High Range LP Pegging Steam Control Valve (PV-001D) to maintain Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 0.99 barg (2.00 bara). The High Range LP Pegging Steam Line will automatically be drained of condensate for 5 minutes using the High Range LP Pegging Steam Drain Valve (HV-004D) prior to opening the High Range LP Pegging Steam Control Valve (PV-001D) if the line has been out of service for at least one (1) hour.
When the required pegging steam is more than the available LP steam, the IP Pegging Steam Control Valve (PV-003D) is to be enabled and modulated open / closed in conjunction with High Range LP Pegging Steam Control Valve (PV-001D) to maintain Deaerator set pressure. The IP Pegging Steam Line will automatically be drained of condensate for 5 minutes using the IP Pegging Steam Drain Valve (HV-008D) prior to opening the IP Pegging Steam Control Valve (PV-003D) if the line has been out of service for at least one (1) hour.
NOTE: The IP Pegging Steam Control Valve (PV-003D) is being used to maintain the Deaerator Storage Tank pressure at 0.99 barg (2.0 bara) once the High Range LP Pegging Steam Control Valve (PV-001D) has reached 70% of the fully open position.
During startup, control setpoint for Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) will be set at 0.99 barg (2.00 bara).
For Startup on Solar Fuel (Oil) Operation:
21. Modulate open / closed the Low Range Pegging Steam Control Valve (PV-002D) to maintain Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 3.49 barg (4.50 bara).
When the Low Range Pegging Steam Control Valve (PV-002D) has reached 100% open and the Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) falls below 3.49 barg (4.50 bara), this indicates that the required pegging steam is more than the available steam from the Low Range LP Pegging Steam Control Valve (PV-002D). Switch over control of the pegging steam flow to the High Range LP Pegging Steam Control Valve (PV-001D). Completely close the Low Range LP Pegging Steam Control Valve (PV-002D). Modulate open / closed the High Range LP Pegging Steam Control Valve (PV-001D) to maintain Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 3.49 barg (4.50 bara). The High Range LP Pegging Steam Line will automatically be drained of condensate for 5 minutes using the High Range LP Pegging Steam Drain Valve (HV-004D) prior to opening the High Range LP Pegging Steam Control Valve (PV-001D) if the line has been out of service for at least one (1) hour.
When the required pegging steam is more than the available LP steam, the IP Pegging Steam Control Valve (PV-003D) is to be enabled and modulated open / closed in conjunction with High Range LP Pegging Steam Control Valve (PV-001D) to maintain Deaerator set pressure. The IP Pegging Steam Line will automatically be drained of condensate for 5 minutes using the IP Pegging Steam Drain Valve
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(HV-008D) prior to opening the IP Pegging Steam Control Valve (PV-003D) if the line has been out of service for at least one (1) hour.
NOTE: While the IP Pegging Steam Control Valve (PV-003D) is being used to maintain the Deaerator Storage Tank pressure at 3.49 barg (4.50 bara) the High Range LP Pegging Steam Control Valve (PV-001D) is to be maintained at 70% of the fully open position
During startup, control setpoint for Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) will be set at 3.49 barg (4.50 bara).
For Startup on All Fuels:
22. When a measurable HP steam flow is established (approximately 10% of full flow), the HP steam section is “on line” and the HP Main Steam Outlet Stop Valve (HV-001) may be opened and the HP Startup Vent Valve (HV-342) may be closed. Close the bypass on the HP Main Steam Outlet Stop Valve (HV-001A) if opened for warming the piping.
23. When a measurable IP steam flow is established (approximately 10% of full flow), the IP steam section is “on line” and the IP Startup Vent Valve (HV-600) may be closed.
24. The Condenser is available when the vacuum has been established. At that time, the HRH to Condenser Bypass is ready to be engaged. The RH section is “on line” and the RH Outlet Startup Vent Valve (FV-780) may be closed over a period of 2 minutes. Prior to the Condenser being available, the RH Outlet Vent Valve (FV-780) will modulate open / closed in order to maintain a minimum pressure of 10.99 barg (12.00 bara) at the HRH Outlet (PIT-780A and PIT-780B).
Note that the RH Outlet Startup Vent Valve may remain open up to but not exceeding 50% flow rate.
25. Once the LP Turbine is ready to receive steam, the LP Startup Vent Valve (FV-915) may be closed.
Note that the LP Startup Vent Valve (FV-915) may remain open up to but not exceeding 100% flow rate.
26. The water level set points in the feedwater control system for the HP, IP, and LP Drums and Deaerator Storage Tank will return to the normal operating water level settings automatically when the respective system steam flow > 10%.
Flowrates by Pressure Section (kg/s) Normal Op. Setpoints
(Case 1) Startup Setpoints
Section 100% 10% HP 71.19 7.12 HRH 81.57 8.16 IP 11.54 1.15 LP 8.94 0.89 DA 91.30 9.13
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For Startup on Natural Gas Operation:
27. Prior to beginning the final temperature step increase of the GT while operating at 50% load, complete the following change-overs:
• Disengage the bypass of the Condensate Preheater by turning on the Preheater Recirculation Pump (PMP-040) and opening the Recirculation Pump Discharge Control Valve (TV-040) to 100% open.
To prevent thermal shock of the Preheater manifold, keep the Condensate Preheater Bypass Stop Valve (HV-003) open for 15 minutes after opening the Condensate Preheater Feedwater Stop Valve (HV-002).
Set Feedwater Heater Recirculation Control in AUTO mode.
The amount of recirculation flow should be such that the temperature entering the Condensate Preheater (TE-005A and TE-005B) is at or above the set point of 51.7°C. (Refer to Condensate Preheater Recirculation Operation section.) A minimum temperature differential of approximately 2.5°C must be maintained between the saturation temperature in the Deaerator based on the operating pressure (PIT-001D and PIT-002D) and the incoming feedwater temperature (TE-066A & B) in order to ensure proper operation of the Deaerator.
• The Low Range LP Pegging Steam Control Valve (PV-002D) should be in AUTO mode so as to be able to control the pegging steam flow to the Deaerator as the total required pegging steam flow decreases.
As the temperature of the feedwater entering the Deaerator increases the total amount of pegging steam required while maintaining the Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 0.99 barg (2.00 bara) will decrease. Modulate closed as required the IP Pegging Steam Control Valve (PV-003D) first and then the High Range LP Pegging Steam Control Valve (PV-001D). Prior to completely closing the High Range LP Pegging Steam Control Valve (PV-001D), switch control of the LP pegging steam flow over to the Low Range Pegging Steam Control Valve (PV-002D). The Low Range LP Pegging Steam Line will automatically be drained of condensate for 5 minutes using the Low Range LP Pegging Steam Drain Valve (HV-072D) prior to opening the Low Range LP Pegging Steam Control Valve (PV-002D) if the line has been out of service for at least one (1) hour.
28. Once the GT has reached Base Load, change the control setpoint for the Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) to 0.49 barg (1.50 bara).
For Startup on All Fuels:
29. Open the following continuous blowdown isolation valves:
a. HP Drum Continuous Blowdown Stop Valve (HV-181).
b. IP Drum Continuous Blowdown Stop Valve (HV-482).
c. LP Drum Continuous Blowdown Stop Valve (HV-827).
Blowdown flow should be controlled with the following valves:
a. HP Drum Continuous Blowdown Metering Valve (HV-182).
b. IP Drum Continuous Blowdown Metering Valve (HV-484).
c. LP Drum Continuous Blowdown Metering Valve (HV-829).
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5.8 START-UP FROM A WARM CONDITION
This section describes the recommended procedure for starting the HRSG from a Warm / Hot condition, which is when the HP Drum Pressure (PIT-260 and PIT-261) > 1.72 barg (2.74 bara). Proceed as follows:
1. Purge the HRSG in accordance with NFPA 85, Chapter 8.9.2 (Combustion Turbine Exhaust Systems) guidelines.
It is understood that purging is accomplished by using air at ambient temperatures. The ambient air temperatures during a normal purge cycle will not have any damaging effect on any of the HRSG components.
2. Align all HRSG valves as shown under the column labeled “START FROM WARM” on Tables 1 through 6.
NOTE: Some of the following procedures are redundant to what is shown on Tables 1 through 6. This is done to emphasize the importance of performing these procedures.
3. Open the Stack Damper before rolling the Gas Turbine.
4. The HP Desuperheater Spray Water Control Valve (TV-301) is in ‘AUTO’. The HP Desuperheater Spray Water Control Valve Isolation Valves (V-313 and V-317) shall remain open. The HP Desuperheater Spraywater Power Block Valve (HV-300) is in ‘AUTO’.
5. The RH Desuperheater Spray Water Control Valve (TV-701) is in ‘AUTO’. The RH Desuperheater Spray Water Control Valve Isolation Valves (V-713 and V-717) shall remain open. The RH Desuperheater Spraywater Power Block Valve (HV-700) is in ‘AUTO’.
NOTE: Although desuperheating is not required except at peak turbine load, it is good practice to have the control station available whenever the unit is operating.
6. The following Drain Valves are in AUTO:
HP Superheater 1 Drain Valve (HV-284),
HP Superheater 2 Drain Valve (HV-282),
HP Superheater 3 Drain Valve (HV-280),
Allow any condensate in these sections to drain.
7. The following Drain Valves are in AUTO:
Reheater 1 Drain Valve (HV-765),
Reheater 2 Drain Valve (HV-760),
IP Superheater Drain Valve (HV-580)
Allow any condensate in these sections to drain.
8. The LP Steam Outlet Drain Valves (HV-948 and HV-949). Allow any condensate to drain.
9. Prior to start up, reset the water level set points in the feedwater control system to ensure that the water levels in the HP, IP, and LP Drums and the Deaerator Storage
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Tank are just above the start up NWL (see Tables 7 through 10). Use the HP Evaporator (HV-180), IP Evaporator (HV-480) and LP Evaporator (HV-825) Intermittent Blow-off Valves as necessary to reduce water levels.
10. Open the HP Feedwater Inlet Stop Valve (HV-102), IP Feedwater Stop Valve (HV-400) and LP Feedwater Stop Valve (HV-800).
11. Place the Condensate Preheater in bypass by closing the Condensate Preheater Feedwater Stop Valve (HV-002) and opening the Condensate Preheater Bypass Stop Valve (HV-003). Set the Preheater Recirculation Pump (PMP-040) and Control to OFF.
12. Close the HP Main Steam Outlet Stop Valve (HV-001), open the HP Steam Startup Vent (HV-342). Engage the HP to RH Bypass Valve (not in ALSTOM Power scope) to control the HP Steam Outlet Pressure to 58.99 barg (60.00 bara).
13. Open the IP Main Steam Outlet Stop Valve (HV-604), IP Steam Startup Vent (HV-600), and the RH Steam Outlet Startup Vent (FV-780). Close the HRH Stop Valve (not in ALSTOM Power scope) and the HRH to Condenser Bypass (not in ALSTOM Power scope).
14. Close the LP Main Steam Outlet Stop Valve (HV-919) and open the LP Steam Startup Vent (FV-915).
NOTE: When starting the second gas turbine/HRSG train, with the first train already operating, the HP Main Steam Outlet Stop Valve (HV-001), and the LP Main Steam Outlet Stop Valve (HV-919) shall remain closed until the pressure is within 5% and temperature is within 28°C of downstream piping. After permissives clear and stop valves open, the NRV in the respective lines will open once the pressures match and will then begin admitting steam.
15. If needed, restart feedwater pumps and ensure that pumps are running and all feed system valves are lined up. (See ‘START FROM WARM’ on Tables 1 through 6.)
16. Allow gas turbine exhaust flow to the HRSG by starting the gas turbine.
17. While the steam generator is being brought up to pressure, all cold steam piping should be gradually heated and drained of condensate. The HP Startup Vent Valve (HV-342), RH Steam Outlet Startup Vent Valve (FV-780), IP Startup Vent Valve (HV-600), and the LP Startup Vent Valve (FV-915) must stay opened to insure a positive flow of steam which will reduce thermal expansion.
To warm the piping downstream of ALSTOM Power scope, open the bypass valve on the HP Main Steam Outlet Stop Valve (HV-001A), and the bypass valve on the LP Main Steam Outlet Stop Valve (HV-919A). Next, open a drain or vent downstream of ALSTOM Power scope to allow the steam from the bypass valve to warm the piping. Ensure that all steam piping downstream of the boiler piping is drained prior to admitting steam.
NOTE: When starting the second gas turbine/HRSG train with the first train already operational, the bypass valves on the Main Steam Outlet Stop Valves are used to warm piping.
18. Once the LP steam lines have been properly warmed, the LP steam section is “on line” with steam ready to be introduced to the Deaerator. Open the LP Main Steam Stop Valve (HV-919) and close the bypass (HV-919A) when the system is ready to receive the LP steam. The LP Startup Vent Valve (FV-915) will modulate open /
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closed in order to maintain the LP Steam Outlet Pressure (PIT-915A and PIT-915B) at 4.19 barg (5.20 bara).
19. Warm the Pegging Steam Lines and drain the lines of any condensate by opening the following valves:
Low Range LP Pegging Steam Drain Valve (HV-072D).
High Range LP Pegging Steam Drain Valve (HV-004D).
IP Pegging Steam Drain Valve (HV-008D).
Close the Drain Valves after a period of at least 5 minutes.
NOTE: When starting the second gas turbine/HRSG train with the first train already operational, the Pegging Steam Lines will not require warming.
For Startup on Natural Gas Operation:
20. Modulate open / closed the Low Range Pegging Steam Control Valve (PV-002D) to maintain Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 0.99 barg (2.00 bara).
When the Low Range Pegging Steam Control Valve (PV-002D) has reached 100% open and the Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) falls below 0.99 barg (2.00 bara), this indicates that the required pegging steam is more than the available steam from the Low Range LP Pegging Steam Control Valve (PV-002D). Switch over control of the pegging steam flow to the High Range LP Pegging Steam Control Valve (PV-001D). Completely close the Low Range LP Pegging Steam Control Valve (PV-002D). Modulate open / closed the High Range LP Pegging Steam Control Valve (PV-001D) to maintain Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 0.99 barg (2.00 bara), while the Low Range LP Pegging Steam Control Valve (PV-002D) is closed. The High Range LP Pegging Steam Line will automatically be drained of condensate for 5 minutes using the High Range LP Pegging Steam Drain Valve (HV-004D) prior to opening the High Range LP Pegging Steam Control Valve (PV-001D) if the line has been out of service for at least one (1) hour.
When the required pegging steam is more than the available LP steam, the IP Pegging Steam Control Valve (PV-003D) is to be enabled and modulated open / closed in conjunction with High Range LP Pegging Steam Control Valve (PV-001D) to maintain Deaerator set pressure. The IP Pegging Steam Line will automatically be drained of condensate for 5 minutes using the IP Pegging Steam Drain Valve (HV-008D) prior to opening the IP Pegging Steam Control Valve (PV-003D) if the line has been out of service for at least one (1) hour.
NOTE: While the IP Pegging Steam Control Valve (PV-003D) is being used to maintain the Deaerator Storage Tank pressure at 0.99 barg (2.00 bara) the High Range LP Pegging Steam Control Valve (PV-001D) is to be maintained at 70% of the fully open position
During startup, control setpoint for Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) will be set at 0.99 barg (2.00 bara).
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For Startup on Solar Fuel (Oil) Operation:
21. Modulate open / closed the Low Range Pegging Steam Control Valve (PV-002D) to maintain Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 3.49 barg (4.50 bara).
When the Low Range Pegging Steam Control Valve (PV-002D) has reached 100% open and the Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) falls below 3.49 barg (4.50 bara), this indicates that the required pegging steam is more than the available steam from the Low Range LP Pegging Steam Control Valve (PV-002D). Switch over control of the pegging steam flow to the High Range LP Pegging Steam Control Valve (PV-001D). Completely close the Low Range LP Pegging Steam Control Valve (PV-002D). Modulate open / closed the High Range LP Pegging Steam Control Valve (PV-001D) to maintain Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 3.49 barg (4.50 bara). The High Range LP Pegging Steam Line will automatically be drained of condensate for 5 minutes using the High Range LP Pegging Steam Drain Valve (HV-004D) prior to opening the High Range LP Pegging Steam Control Valve (PV-001D) if the line has been out of service for at least one (1) hour.
When the required pegging steam is more than the available LP steam, the IP Pegging Steam Control Valve (PV-003D) is to be enabled and modulated open / closed in conjunction with High Range LP Pegging Steam Control Valve (PV-001D) to maintain Deaerator set pressure. The IP Pegging Steam Line will automatically be drained of condensate for 5 minutes using the IP Pegging Steam Drain Valve (HV-008D) prior to opening the IP Pegging Steam Control Valve (PV-003D) if the line has been out of service for at least one (1) hour.
NOTE: While the IP Pegging Steam Control Valve (PV-003D) is being used to maintain the Deaerator Storage Tank pressure at 3.49 barg (4.50 bara) the High Range LP Pegging Steam Control Valve (PV-001D) is to be maintained at 70% of the fully open position
During startup, control setpoint for Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) will be set at 3.49 barg (4.50 bara).
For Startup on All Fuels:
22. When a measurable HP steam flow is established (approximately 10% of full flow), the HP steam section is “on line” and the HP Startup Vent Valve (HV-342) may be closed. Close the bypass on the HP Main Steam Outlet Stop Valve (HV-001A) if opened for warming the piping.
23. When a measurable IP steam flow is established (approximately 10% of full flow), the IP steam section is “on line” and the IP Startup Vent Valve (HV-600) may be closed.
24. The Condenser is available when the vacuum has been established. At that time, the HRH to Condenser Bypass is ready to be engaged. The RH section is “on line” and the RH Outlet Startup Vent Valve (FV-780) may be closed over a period of 2 minutes. Prior to the Condenser being available, the RH Outlet Vent Valve (FV-780) will modulate open / closed in order to maintain a minimum pressure of 10.99 barg (12.00 bara) at the HRH Outlet (PIT-780A and PIT-780B).
Note that the RH Outlet Startup Vent Valve may remain open up to but not exceeding 50% flow rate.
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25. Once the LP Turbine is ready to receive steam, the LP Startup Vent Valve (FV-915) may be closed.
Note that the LP Startup Vent Valve (FV-915) may remain open up to but not exceeding 100% flow rate.
26. The water level set points in the feedwater control system for the HP, IP, and LP Drums and Deaerator Storage Tank will return to the normal operating water level settings automatically when the respective system steam flow >10%.
Flowrates by Pressure Section (kg/s) Normal Op. Setpoints
(Case 1) Startup Setpoints
Section 100% 10% HP 71.19 7.12 HRH 81.57 8.16 IP 11.54 1.15 LP 8.94 0.89 DA 91.30 9.13
For Startup on Natural Gas Operation:
27. Prior to beginning the final temperature step increase of the GT while operating at 50% load, complete the following change-overs:
• Disengage the bypass of the Condensate Preheater by turning on the Preheater Recirculation Pump (PMP-040) and opening the Recirculation Pump Discharge Control Valve (TV-040) to 100% open.
To prevent thermal shock of the Preheater manifold, keep the Condensate Preheater Bypass Stop Valve (HV-003) open for 15 minutes after opening the Condensate Preheater Feedwater Stop Valve (HV-002).
Set Feedwater Heater Recirculation Control in AUTO mode.
The amount of recirculation flow should be such that the temperature entering the Condensate Preheater (TE-005A and TE-005B) is at or above the set point of 51.7°C. (Refer to Condensate Preheater Recirculation Operation section). A minimum temperature differential of approximately 2.5°C must be maintained between the saturation temperature in the Deaerator based on the operating pressure (PIT-001D and PIT-002D) and the incoming feedwater temperature (TE-066A & B). This temperature differential is required in order to ensure proper operation of the Deaerator.
• The Low Range LP Pegging Steam Control Valve (PV-002D) should be in AUTO mode so as to be able to control the pegging steam flow to the Deaerator as the total required pegging steam flow decreases.
As the temperature of the feedwater entering the Deaerator increases the total amount of pegging steam required while maintaining the Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) at 0.99 barg (2.00 bara) will decrease. Modulate closed as required the IP Pegging Steam Control Valve (PV-003D) first and then the High Range LP Pegging Steam Control Valve (PV-001D). Prior to completely closing the High Range LP Pegging Steam Control Valve (PV-001D), switch control of the LP pegging steam flow over to the Low Range Pegging Steam Control Valve (PV-002D). The Low Range LP Pegging Steam Line will
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automatically be drained of condensate for 5 minutes using the Low Range LP Pegging Steam Drain Valve (HV-072D) prior to opening the Low Range LP Pegging Steam Control Valve (PV-002D) if the line has been out of service for at least one (1) hour.
28. Once the GT has reached Base Load, change the control setpoint for the Deaerator Storage Tank Pressure (PIT-001D and PIT-002D) to 0.49 barg (1.50 bara).
For Startup on All Fuels:
29. Open the following continuous blowdown isolation valves:
a. HP Drum Continuous Blowdown Stop Valve (HV-181).
b. IP Drum Continuous Blowdown Stop Valve (HV-482).
c. LP Drum Continuous Blowdown Stop Valve (HV-827).
Blowdown flow should be controlled with the following valves:
a. HP Drum Continuous Blowdown Metering Valve (HV-182).
b. IP Drum Continuous Blowdown Metering Valve (HV-484).
c. LP Drum Continuous Blowdown Metering Valve (HV-829).
5.9 SECURING TO A WARM LAY-UP CONDITION
SECURING TO WARM LAY-UP CONDITION WITHIN 24 HOURS IMMEDIATELY FOLLOWING THE GAS TURBINE SHUT DOWN.
This section describes the recommended procedure for securing the HRSG to a warm lay-up condition. Proceed as follows:
1. Prevent the gas turbine exhaust flow to the HRSG by shutting down the gas turbine or closing the Bypass Stack Diverter Damper to the HRSG.
2. Align all HRSG valves as shown under the column labeled “SECURE TO WARM” on Table 1 through 6. In particular, ensure that the following valves are closed:
14. IP Pegging Steam to DA Control Valve (PV-003D).
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15. Low Range LP Pegging Steam to DA Control Valve (PV-002D).
16. High Range LP Pegging Steam to DA Control Valve (PV-001D).
17. When required, close the Stack Damper in order to minimize boiler heat loss as soon as the Gas Turbine rotation has stopped.
18. When the HP Drum pressure falls below 1.72 barg (2.74 bara), the drum pressure may be allowed to decrease to atmospheric pressure by opening the HP Saturated Steam Outlet Vent Valves (V-280 and V-281) or a nitrogen blanket may be maintained by opening the HP Nitrogen Stop Valve (V-263).
19. When the IP Drum pressure falls below 1.72 barg (2.74 bara), the drum pressure may be allowed to decrease to atmospheric pressure by opening the IP Saturated Steam Outlet Vent Valves (V-580 and V-581) or a nitrogen blanket may be maintained by opening the IP Nitrogen Stop Valve (V-563).
20. When the LP Drum pressure falls below 1.72 barg (2.74 bara), the drum pressure may be allowed to decrease to atmospheric pressure by opening the LP Saturated Steam Outlet Vent Valves (V-906 and V-907) or a nitrogen blanket may be maintained by opening the LP Nitrogen Stop Valve (V-888).
21. When the Deaerator pressure falls below 0.10 barg (1.11 bara), the storage tank pressure may be allowed to decrease to atmospheric pressure by opening the Deaerator FW Heater Vent Valves (V-016D and V-017D) or a nitrogen blanket may be maintained by opening the Deaerator Storage Tank Nitrogen Stop Valve (V-063D).
NOTE: Vent valves are provided with 13 mm (0.5 inch) orifice drilled into the gate disk. Therefore, blanking plates shall be installed before nitrogen blanketing of the deaerator and storage tank.
5.10 SECURING TO DRAIN (WITHOUT NITROGEN BLANKETING)
This section describes the recommended procedure for securing the HRSG without nitrogen blanketing in order to drain the unit prior to performing maintenance. Proceed as follows:
1. Prevent any gas turbine exhaust flow to the HRSG by shutting down the gas turbine.
2. Align all HRSG valves as shown under the column labeled “SECURE TO DRAIN” on Tables 1 through 6.
a. HP Feedwater Stop Valve (HV-102).
b. IP Feedwater Stop Valve (HV-400).
c. LP Feedwater Stop Valve (HV-800).
d. Condensate Preheater Stop Valve (HV-002).
e. Condensate Preheater Bypass Stop Valve (HV-003).
f. HP Main Steam Outlet Stop Valve (HV-001).
g. IP Main Steam Outlet Stop Valve (HV-604).
h. LP Main Steam Outlet Stop Valve (HV-919).
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i. HP Drum Continuous Blowdown Stop Valve (HV-181).
j. IP Drum Continuous Blowdown Stop Valve (HV-482).
k. LP Drum Continuous Blowdown Stop Valve (HV-827).
l. IP Pegging Steam to DA Control Valve (PV-003D).
m. Low Range LP Pegging Steam to DA Control Valve (PV-002D).
n. High Range LP Pegging Steam to DA Control Valve (PV-001D).
3. When the associated drum pressure falls to 1.72 barg (2.74 bara), open the HP Saturated Steam Outlet Vent Valves (V-280 and V-281), IP Saturated Steam Outlet Vent Valves (V-580 and V-581) and the LP Saturated Steam Outlet Vent Valves (V-906 and V-907). These main steam vent valves must be opened before the associated drum pressure falls any lower to prevent a vacuum from developing that may cause leakage of the drum manway gaskets.
4. When the Deaerator pressure falls to 0.10 barg (1.11 bara), open the Deaerator FW Heater Vent Valves (V-016D and V-017D).
5. The HRSG can be drained when it is completely cooled (when vapor no longer escapes from the vents).
6. Open the vent valves and drain valves one heat exchanger section at a time to avoid overloading the drain discharge system downstream of the HRSG. Open the Blowdown Stop Valves if the blowdown lines are to be drained.
5.11 CONTROLS AND INSTRUMENTATION
Controls
It is beyond the scope of this manual to discuss the design parameters and selection criteria of control systems. Instead, we will review the steam generator dynamics involved in tuning these systems and note problems we have found on actual operating units. When we discuss steam generator control, we are actually referring to the drum level controls; all other controls are supplied by others.
The drum level controls will regulate the rate of feedwater flow to maintain a proper drum level throughout the operating range of the steam generator.
To get maximum benefit from a three-element system, feedwater flow should be proportional to steam flow with reset action on drum level. This means that pounds of feedwater entering should always equal pounds of steam leaving, with periodic small corrections made to correct deviations from level set points. The best drum level control is achieved through mass flow balance.
Instrumentation
Even the most sophisticated and well-tuned control systems do not take the place of the judgment of an alert, motivated and trained operator. The only means that an operator has to make his judgements is through adequate and calibrated instrumentation.
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5.12 SAFETY VALVES
Safety valves serve to protect pressure vessels from overpressure. On superheater outlets they serve the additional purpose of protecting the superheater from overheating in the event of a sudden interruption in steam consumption.
The total relieving capacity of the safety valves on a boiler cannot be less than the design steaming capacity. It is a Code requirement that one or more safety valves on the steam drum be set at or below the design pressure of the unit. Any economizer which can be isolated from the boiler must have its own safety valve. The discharge capacity of any superheater safety valve or valves can be included in the total relieving capacity of the boiler, provided there is no way to isolate the superheater. Valves are to be designed to operate without chattering and to obtain full lift at no more than 3% above their set pressure. Valves are to close within 4% of set pressure, but no less than 2% of set pressure.
The popping point tolerance shall not exceed:
2 psig for pressures up to 70 psig.
3% for pressures up to 300 psig.
10 psig for pressures up to 1000 psig.
1% for pressures over 1000 psig.
ALSTOM Power recommends that all safety valves be lifted to check popping pressure and blowdown prior to annual maintenance outages. During these outages, valves that leaked or had a tendency to simmer or chatter should be disassembled and repaired. During valve testing, it is important to maintain drum level at or below normal water level to prevent water damage to drum valve seats and to prevent high solids boiler water from being drawn into superheaters.
Any time a valve is disassembled, its seat should be touched up with a lap and 1000 grit-lapping compound. If the seat is in poor shape, use a carborundum disc first, then progressively finer grits.
The following are safety tips and helpful hints:
1. Never set safety valves by holding set pressure and lowering the popping pressure setting with a wrench. This is extremely hazardous. Valve setting changes should be made with the boiler pressure considerably lower than set point. After the wrench adjustment is made the lifting gear should be replaced and boiler pressure should be raised to the new popping point.
2. Ring locking pins can vibrate loose when a valve is relieving. The pins should always be wired to each other except when one pin is removed to make a ring adjustment.
3. Entrained water will cause excessive blowdown on drum valves. Set drum valves with the drum water level a few inches below normal water level, if possible.
4. A rule of thumb: Vent pipes should be 2 inches larger in diameter than the valve discharge pipe.
5. The discharge pipe should extend no more than 14 inches into the vent pipe from the bottom of the drip pan.
6. A safety valve seat can be damaged by debris and water, which enters the valve body through the vent pipe. This debris is blown around when the valve lifts. Covering the vent pipe with a plastic bag can eliminate the problem.
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7. It is occasionally necessary to mount a vent pipe rigidly to the discharge elbow. This should be done only when there is no alternative. Care should be taken that the vent pipe is cut off square, not on the bias.
8. Do not exceed five pops on a valve. If more pops are required, allow valve to cool before proceeding.
9. Do not make adjustments on first pop. Always evaluate the necessary adjustment from two pops.
10. When popping a valve, always have the cap and drop lever assembly in place with a rope affixed. If the valve begins to chatter, it can be manually popped before the seating surfaces are damaged.
11. Observe the popping pressure on a suitable gauge mounted in the proximity of the valve being tested. A second gauge, preferably a dead weight gauge, should be used to validate the calibration of the observed gauge.
5.13 FW PREHEATER BYPASS OPERATION
When operating the HRSG Unit with Distillate Oil, the FW Preheater should be bypassed. To bypass the FW Preheater, ensure you isolate the LP Feedwater Stop After Bypass Valve (YV-D06). Ensure the FW Preheater Bypass Isolation Valves (ISV-D720A and ISV-D720B) are open and set the FW Preheater Bypass Modulating Valve in manual (or auto).
5.14 EMERGENCY PROCEDURES
High Water Level
Abnormally high water levels should be avoided, as it may lead to carry-over and even priming.
In the event of a high water level, there will be a high drum level alarm. Proceed as follows:
1. Isolate the feedwater supply for the appropriate drum using the HP Feedwater Control Valve (LV-100) and HP Feedwater Stop Valve (HV-102), IP Feedwater Control Valve (LV-430) and IP Feedwater Stop Valve (HV-400), LP Feedwater Control Valve (LV-801) and LP Feedwater Stop Valve (HV-800) and Condensate Preheater Outlet Control Valve (LV-064), Condensate Preheater Feedwater Stop Valve (HV-002) and Condensate Preheater Bypass Stop Valve (HV-003) as required.
2. Close the Bypass Stack Diverter Damper to HRSG using Normal Closing Speed (60 seconds). Damper may be reopened once the alarm clears, the cause of the alarm has been corrected and the GT is operating at or below 20% load. See Simple to Combined Cycle Operation for details.
3. Blowdown the appropriate drum until the water level is at the normal level. Use the HP Intermittent Blow-off Valve (HV-180), IP Intermittent Blow-off Valve (HV-480) and LP Intermittent Blow-Off Valve (HV-825) as required. The Intermittent Blow-off Valves may be used when the HRSG is operating at any pressure in order to reduce the drum water level.
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4. Isolate the steam outlet for the appropriate drum using the HP Main Steam Outlet Stop Valve (HV-001), IP Main Steam Outlet Stop (HV-HV-604) and the LP Main Steam Outlet Stop Valve (HV-919) as required. Open Superheater Drain Valves for appropriate drum using HP Superheater Drains (HV-284, HV-282 and HV-280), IP Superheater Drain (HV-580) and LP Superheater Drain (HV-948) as appropriate.
5. If the alarm has not cleared within 2 minutes and the Bypass Stack Diverter Damper is not completely closed to HRSG, initiate trip of gas turbine.
6. Investigate the water conditions (alkalinity and solids).
Low Water Level
If the water level falls out of sight in the water gauge, due to failure of the feedwater supply or neglect of the operator, appropriate action should be taken at once. The only exception is in the case of momentary fluctuations that might occur with extraordinary changes in load. Any decision to continue to operate, even if only for a short time at a reduced rating, would have to be made by someone in authority who is thoroughly familiar with the circumstances that led to the emergency and positively certain that the water level can be restored immediately without damaging the boiler. In the absence of such a decision:
1. Close the Bypass Stack Diverter Damper to HRSG using Normal Closing Speed (60 seconds). If the alarm does not clear within 2 minutes, initiate trip of the gas turbine. If the alarm is cleared within 2 minutes and if the cause of the alarm is identified and corrected, the Bypass Stack Diverter Damper may be reopened once the GT is at or below 20% load. See Simple to Combined Cycle Operation for details.
2. Isolate the steam outlet for the appropriate drum using the HP Main Steam Outlet Stop Valve (HV-001), IP Main Steam Outlet Stop (HV-604) and the LP Main Steam Outlet Stop Valve (HV-919) as required.
3. If the condition has not been stabilized and gas turbine trip has been initiated, allow HRSG to cool so that it may be inspected for damage if required. After correcting the cause, the unit may be restarted.
CAUTION: Do not attempt to add water until the steam generator has cooled down sufficiently to where the drum metal temperatures are within 56°C (100°F) of the feedwater temperature; otherwise, damage may result due to relatively cool water coming in contact with heated pressure parts.
Tube Failure
1. Immediately secure the gas turbine exhaust flow.
2. Secure unaffected sections of HRSG according to “Securing to Warm Lay-up Condition” instructions.
3. Isolate and drain affected sections of HRSG according to “Securing to Drain” instructions.
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Loss of Feedwater Supply
The loss of feedwater supply is a rare occurrence in a properly maintained steam plant. However, loss of the feedwater supply can happen and it is to be treated as an extreme emergency.
A steady persistent drop in the steam drum level indicates problems with the feed pump, feed pump recirculation control, steam generator feedwater valve control or a tube leak. By quickly comparing system pressures and flows with data taken at comparable loads during normal operation, the operators should be able to identify the problem area.
If feedwater flow is increasing relative to steam flow and the drum water level is still falling, a tube leak can be assumed. Secure the gas turbine exhaust flow and proceed with tube failure emergency procedures (see Emergency Procedures – Tube Failure section for details).
For the HP Drum, an alarm will sound when the drum water goes to the low level. At the low low HP Drum level the gas turbine exhaust flow should be secured.
If the problem is with the feed pump or controls, restrict steam generator steam flow to balance the ability of the crippled feedwater system to maintain drum level.
If it is not possible to stabilize drum levels by reducing load, secure the gas turbine exhaust flow and bottle up the steam generator, keeping all vents closed. When the feedwater system is repaired, restart the unit as detailed under the procedure titled “Start-Up From A Warm Condition”.
In any case, the first consideration must be the protection of the steam generator pressure parts from operation with low water.
As is true of any emergency situation with a steam plant, events do not always follow an orderly pattern. The procedures above may or may not fit the pattern for every circumstance. The intent is to emphasize what should be done in order to protect the steam generator and bring the plant back in operation as soon as possible.
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Table 1 - Valve Alignment: High Pressure Section
VALVE TAG DESIGNATION
VALVE DESCRIPTION
START FROM COLD
START FROM WARM
NORMAL OPERA-
TION
SECURE TO
WARM
SECURE TO
DRAIN LV-100 HP Feedwater Control Valve Auto Auto Auto Auto Auto V-105, V-109 HP Feedwater CV Isolation Valves Open Open Open Open Open V-106, V-107 HP Feedwater CV Drain Valves Closed Closed Closed Closed Closed V-108 HP Feedwater CV Manual Bypass
Valve Closed Closed Closed Closed Closed
V-133, V-134 HP Feedwater CV Bypass Drains Closed Closed Closed Closed Closed HV-102 HP Feedwater Stop MOV Open Open Open Closed Closed V-110, V-111, V-124, V-125
V-284 HP Superheater 3 Drain Valve Open Open Open Open Open HV-280 HP Superheater 3 Drain MOV Auto Auto Closed Closed Auto V-285, V-286 HP Superheater 2 & 3 Vent Valves Closed Closed Closed Closed Closed
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V-287 HP Superheater 2 Drain Valve Open Open Open Open Open HV-282 HP Superheater 2 Drain MOV Auto Auto Closed Closed Auto HV-300 HP Spraywater Power Block Valve Auto Auto Auto Off Off V-324, V-325 HP Spraywater Strainer Drain
TV-301 HP Spraywater Control Valve Auto Auto Auto Auto Auto V-313, V-317 HP Spraywater Stop Valves Open Open Open Open Open V-315, V-316 HP Spraywater CV Drain Valves Closed Closed Closed Closed Closed V-314 HP Spraywater CV Manual Bypass
Valve Closed Closed Closed Closed Closed
HV-302 HP Spraywater CV Bypass AOV Closed Closed Closed Closed Closed V-289, V-290 HP Desuperheater Vent Closed Closed Closed Closed Closed V-288 HP Superheater 1 Drain Valve Open Open Open Open Open HV-284 HP Superheater 1 Drain MOV Auto Auto Closed Closed Auto V-354 HP Steam Outlet Startup Vent
Valve Open Open Open Open Open
HV-342 HP Steam Outlet Startup Vent MOV
Open Open Closed Closed Closed
V-351 HP Steam Outlet ERV Isolation Valve
Open Open Open Open Open
HV-340 HP Steam Outlet ERV (Self Contained
Auto Auto Auto Auto Auto
V-356 HP Steam Outlet NRV Open Open Open Open Open V-357, V-358 HP Steam Outlet Tell Tale Drain
Valves Closed Closed Closed Closed Closed
HV-001A HP Steam Outlet Stop Valve Bypass MOV
Open Open Closed Closed Closed
HV-001 HP Steam Outlet Stop MOV Closed Closed Open Closed Closed * Open applies to after the drum pressure falls below 0.5 barg (1.51 bara) and HRSG is completely cooled (when
vapor no longer escapes from the vents.). ** Open applies to after the drum pressure falls below 1.72 barg (2.74 bara).
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DRAIN V-426 IP Feedwater Block Valve Open Open Open Open Open HV-400 IP Feedwater Stop MOV Open Open Open Closed Closed V-419, V-420 IP Feedwater Inlet Drain Valves Closed Closed Closed Closed Closed /
Open* LV-430 IP Feedwater Control Valve Auto Auto Auto Auto Auto V-435, V-439 IP Feedwater CV Isolation Valves Open Open Open Open Open V-436, V-437 IP Feedwater CV Drain Valves Closed Closed Closed Closed Closed V-438 IP Feedwater CV Manual Bypass
Valve Closed Closed Closed Closed Closed
V-480 IP Evap Intermittent Blow-off Metering Valve
V-584 IP SH Drain Valve Open Open Open Open Open HV-580 IP SH Drain MOV Auto Auto Closed Closed Auto V-623 IP Pegging Steam to DA NRV Open Open Open Open Open V-624 IP Pegging Steam to DA Stop Valve Open Open Open Open Open V-639, V-640 IP Pegging Steam to DA Tell Tale
Drain Valves Closed Closed Closed Closed Closed
V-641, V-642 IP Pegging Steam to DA Vent Valves
Closed Closed Closed Closed Closed
V-604, V-605 IP Steam Outlet Drain Valves Closed Closed Closed Closed Closed V-603 IP Steam Outlet Startup Vent Valve Open Open Open Open Open HV-600 IP Steam Outlet Startup Vent MOV Open Open Closed Closed Closed V-606 IP Steam Outlet ERV Isolation
Valve Open Open Open Open Open
HV-602 IP Steam Outlet ERV (Self Contained)
Auto Auto Auto Auto Auto
V-607 IP Steam Outlet NRV Valve Open Open Open Open Open V-608, V-609 IP Steam Outlet Tell Tale Drain
Valves Closed Closed Closed Closed Closed
HV-604A IP Steam Outlet Stop Bypass MOV Open Open Closed Closed Closed
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HV-604 IP Steam Outlet Stop MOV Open Open Open Closed Closed V-637, V-638 IP Steam Outlet Vent Valves Closed Closed Closed Closed Closed V-635, V-636 IP Steam Outlet Drain Valves Closed Closed Closed Closed Closed PV-601 IP Steam Outlet Backpressure
Control Valve Auto Auto Auto Auto Auto
V-644 IP Steam Outlet Isolation Valve Open Open Open Open Open V-760 RH 2 Drain Valve Open Open Open Open Open HV-760 RH 2 Drain MOV Auto Auto Closed Closed Auto HV-700 RH Spraywater Power Block Valve Auto Auto Auto Off Off V-724, V-725 RH Spraywater Strainer Drain
TV-701 RH Spraywater Control Valve Auto Auto Auto Auto Auto V-713, V-717 RH Spraywater Stop Valves Open Open Open Open Open V-715, V-716 RH Spraywater CV Drain Valves Closed Closed Closed Closed Closed V-714 RH Spraywater CV Manual Bypass
Valve Closed Closed Closed Closed Closed
HV-702 RH Spraywater CV Bypass AOV Closed Closed Closed Closed Closed V-766, V-767 RH Desuperheater Vent Valves Closed Closed Closed Closed Closed V-765 RH 1 Drain Valve Open Open Open Open Open HV-765 RH 1 Drain MOV Auto Auto Closed Closed Auto V-783 RH Steam Outlet Startup Vent
Valve Open Open Open Open Open
FV-780 RH Steam Outlet Startup Vent AOV Auto Auto Auto Auto Auto V-784 RH Steam Outlet ERV Isolation
Valve Open Open Open Open Open
HV-782 RH Steam Outlet ERV (Self Contained)
Auto Auto Auto Auto Auto
* Open applies to after the drum pressure falls below 0.5 barg (1.51 bara) and HRSG is completely cooled (when
vapor no longer escapes from the vents.). ** Open applies to after the drum pressure falls below 1.72 barg (2.74 bara).
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Table 3 - Valve Alignment: Low Pressure Section
VALVE TAG DESIGNATION
VALVE DESCRIPTION
START FROM COLD
START FROM WARM
NORMAL OPERA-
TION
SECURE TO
WARM
SECURE TO
DRAIN V-816 LP Feedwater Block Valve Open Open Open Open Open LV-801 LP Feedwater Control Valve Auto Auto Auto Auto Auto V-816, V-820 LP Feedwater CV Isolation Valves Open Open Open Open Open V-817, V-818 LP Feedwater CV Drain Valves Closed Closed Closed Closed Closed V-819 LP Feedwater CV Manual Bypass Closed Closed Closed Closed Closed V-903, V-904 LP Feedwater Inlet Drain Valves Closed Closed Closed Closed Closed /
V-918 LP Steam Outlet Startup Vent Valve Open Open Open Open Open FV-915 LP Steam Outlet Startup Vent MOV Open Open Closed Closed Closed V-919 LP Steam Outlet ERV Isolation Valve Open Open Open Open Open HV-917 LP Steam Outlet ERV (Self Contained) Auto Auto Auto Auto Auto V-920 LP Steam Outlet NRV Valve Open Open Open Open Open V-921, V-922 LP Steam Outlet Tell Tale Drain
Valves Closed Closed Closed Closed Closed
HV-919A LP Steam Outlet Stop Bypass MOV Open Open Closed Closed Closed HV-919 LP Steam Outlet Stop MOV Closed Closed Open Closed Closed V-948, V-949 LP Steam Outlet Drain Valve Open Open Open Open Open HV-948, HV-949 LP Steam Outlet Drain MOV Auto Auto Closed Closed Auto * Open applies to after the drum pressure falls below 0.5 barg (1.51 bara) and HRSG is completely cooled (when
vapor no longer escapes from the vents.). ** Open applies to after the drum pressure falls below 1.72 barg (2.74 bara). *** Open applies to after the drum pressure falls below 1.03 barg.
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V-062 Condensate Preheater Recirc. Pump Min. Recirc. Stop Valve
Open Open Open Open Open
* Closed applies to operation on Solar (Oil / High Sulfur) Fuel. ** Open applies to operation on Solar (Oil / High Sulfur) Fuel. *** Open applies to after the drum pressure falls below 0.10 barg (1.11 bara)and HRSG is completely cooled (when
vapor no longer escapes from the vents.).
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Table 5 - Valve Alignment: Deaerator System
VALVE TAG DESIGNATION
VALVE DESCRIPTION
START FROM COLD
START FROM WARM
NORMAL OPERA-
TION
SECURE TO
WARM
SECURE TO
DRAIN V-001D LP Pegging Steam Stop Valve Open Open Open Open Open V-012D, V-013D, V-071D
Low Range LP Pegging Steam Drain Valves
Open Open Open Open Open
HV-072D Low Range LP Pegging Steam Drain MOV
Closed Closed Closed Closed Closed / Open**
PV-002D Low Range LP Pegging Steam Control Valve
Auto Auto Auto Auto Auto
V-003D High Range LP Pegging Steam Drain Valve
Open Open Open Open Open
HV-004D High Range LP Pegging Steam Drain MOV
Closed Closed Closed Closed Closed / Open**
PV-001D High Range LP Pegging Steam Control Valve
Open Open Open Open Open
V-007D, V-009D, V-010D
IP Pegging Steam Drain Valves Open Open Open Open Open
PV-003D IP Pegging Steam Control Valve Auto Auto Auto Auto Auto V-016D, V-017D Deaerator FW Heater Vent Valve Closed Closed Closed Closed /
Open* Closed / Open*
V-028D, V-029D, V-030D
LP BFP Min. Recirc. Isolation Valves
Open Open Open Open Open
V-031D, V-032D, V-033D
HP/IP BFP Min. Recirc. Isolation Valves
Open Open Open Open Open
V-034D LP BFP Suction Isolation Valve Open Open Open Open Open V-056 HP/IP BFP Suction Isolation Valve Open Open Open Open Open V-035D, V-036D Deaerator Storage Tank Drain
Valves Closed Closed Closed Closed Closed /
Open** * Open applies to after the drum pressure falls below 0.10 barg (1.11 bara). ** Open applies to after the storage tank pressure falls below 0.10 barg (1.11 bara) and HRSG is completely cooled
(when vapor no longer escapes from the vents.).
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Table 6 - Valve Alignment: Blowdown Tank System & Gas Side
VALVE TAG DESIGNATION
VALVE DESCRIPTION
START FROM COLD
START FROM WARM
NORMAL OPERA-
TION
SECURE TO
WARM
SECURE TO
DRAIN TV-001B Blowdown Tank Cooling Water
Control Valve Auto Auto Auto Auto Auto
V-014B, V-015B Blowdown Tank Cooling Water Stop Valve
Open Open Open Open Open
V-007B Blowdown Tank Cooling Water Control Valve Manual Bypass
Closed Closed Closed Closed Closed
V-006B Blowdown Tank Drain Valve Closed Closed Closed Closed Closed DMP-001G Stack Damper Open Open Open Closed Open
Table 7 – HP Drum Level Setpoints
Drum Level Setpoints for 1829 mm (72 inch) ID HP Drum Cold Start-up Setpoints
[Pdrum < 1.72 barg (2.74 bara)] Normal Operating Setpoints
Level Value Level Value HHH +292 mm (+11.5”) HHH +292 mm (+11.5”) HH +241 mm (+9.5”) HH +241 mm (+9.5”) H +191 mm (+7.5”) H +191 mm (+7.5”) NWL -686 mm (-27”) NWL +64 mm (+2.5”) L -711 mm (-28”) L -38 mm (-1.5”) LL -737 mm (-29”) LL -737 mm (-29”) LLL -787 mm (-31”) LL -787 mm (-31”)
• Levels are referenced to drum centerline. • Dimensions are in inches and millimeters. • Drum level setpoints will be determined based on drum pressure. An HP Drum
Pressure (PIT-260 and PIT-261) < 1.72 barg (2.74 bara) will utilize Cold Startup Setpoints. An HP Drum Pressure (PIT-260 and PIT-261) between 1.72 barg (2.74 bara) and 60.00 barg (61.01 bara) will utilize a linear function for determining the setpoints. An HP Drum Pressure (PIT-260 and PIT-261) > 60.00 barg (61.01 bara) will utilize Normal Operating Setpoints.
• Field tuning of startup setpoints is permissible.
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Table 8 – IP Drum Level Setpoints
Drum Level Setpoints for 1372 mm (54 inch) ID IP Drum Cold Start-up Setpoints
[Pdrum < 1.72 barg (2.74 bara)] Normal Operating Setpoints
Level Value Level Value HHH +229 mm (+9”) HHH +229 mm (+9”) HH +178 mm (+7”) HH +178 mm (+7”) H +127 mm (+5”) H +127 mm (+5”) NWL -457 mm (-18”) NWL 0 mm (0”) L -483 mm (-19”) L -102 mm (-4”) LL -508 mm (-20”) LL -508 mm (-20”) LLL -559 mm (-22”) LLL -559 mm (-22”)
• Levels are referenced to drum centerline. • Dimensions are in inches and millimeters. • Drum level setpoints will be determined based on drum pressure. An IP Drum
Pressure (PIT-560 and PIT-561) < 1.72 barg (2.74 bara) will utilize Cold Startup Setpoints. An IP Drum Pressure (PIT-560 and PIT-561) between 1.72 barg (2.74 bara) and 14.00 barg (15.01 bara) will utilize a linear function for determining the setpoints. An IP Drum Pressure (PIT-560 and PIT-561) > 14.00 barg (15.01 bara) will utilize Normal Operating Setpoints.
• Field tuning of startup setpoints is permissible.
Table 9 – LP Drum Level Setpoints
Drum Level Setpoints for 1524 mm (60 inch) ID LP Drum Cold Start-up Setpoints
[Pdrum < 1.72 barg (2.74 bara)] Normal Operating Setpoints
Level Value Level Value HHH +229 mm (+9”) HHH +229 mm (+9”) HH +178 mm (+7”) HH +178 mm (+7”) H +127 mm (+5”) H +127 mm (+5 ”) NWL -533 mm (-21”) NWL 0 mm (0“) L -559 mm (-22”) L -102 mm (-4”) LL -584 mm (-23”) LL -584 mm (-23”) LLL -635 mm (-25”) LLL -635 mm (-25”)
• Levels are referenced to drum centerline. • Dimensions are in inches and millimeters. • Drum level setpoints will be determined based on drum pressure. An LP Drum
Pressure (PIT-890 and PIT-891) < 1.72 barg (2.74 bara) will utilize Cold Startup Setpoints. An LP Drum Pressure (PIT-890 and PIT-891) between 1.72 barg (2.74 bara) and 3.50 barg (4.51 bara) will utilize a linear function for determining the setpoints. An LP Drum Pressure (PIT-890 and PIT-891) > 3.50 barg (4.51 bara) will utilize Normal Operating Setpoints.
• Field tuning of startup setpoints is permissible.
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Table 10 – Deaerator Storage Tank Level Setpoints
Drum Level Setpoints for 3658 mm (144”) OD DA Storage Tank Cold Start-up Setpoints Normal Operating Setpoints
Level Value Level Value HHH +1372 mm (+54”) HHH +1372 mm (+54”) HH + 1295 mm (+51”) HH +1295 mm (+51”) H +1219 mm (+48”) H +1219 mm (+48”) NWL +566 mm (+22.3”) NWL +566 mm (+22.3”) L -1524 mm (-60”) L -1524 mm (-60”) LL -1600 mm (-63”) LL -1600 mm (-63”) LLL -1676 mm (-66”) LLL -1676 mm (-66”)
• Levels are referenced to drum centerline. • Dimensions are in inches and millimeters. • Field tuning of startup setpoints is permissible.
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REVISION LOG Rev. No.
Rev. Date
By Checked By
Change Code
Remarks
00 6/08/04 ALBrown FJS/VQT Initial Issue 01 02/07/05 ALBrown RGK C2 Revised per the latest changes to Item 19.11-
04 02 05/16/05 ALBrown RGK C1/C2 Revised based on Customer comments and
latest changes to Item 19.11-05.
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SECTION 6: FEEDWATER AND BOILER WATER CHEMISTRY LEARNING OBJECTIVES • List the criteria used in determining proper boiler feedwater treatment and boiler chemistry
with respect to feedwater quality, treatment, water conditioning and steam purity.
STANDARD SPECIFICATIONS FOR COMBINED CYCLES WITH DRUM-TYPE BOILERS ..........6-4 1. Demineralized Water (at Demineralizer Water Plant Outlet) .................................................6-4 2. Condensate (at Condensate Pump Discharge) ......................................................................6-4 3. Feedwater (at Boiler Inlet) ........................................................................................................6-5 4. Boiler Water (HP, IP and LP) ....................................................................................................6-5 5. Live Steam and Reheat Steam (at Boiler Outlet)....................................................................6-6 6. General remarks........................................................................................................................6-6
APPENDIX I........................................................................................................................................6-7 Feedwater Quality and Steam Purity...........................................................................................6-7 Boilerwater Quality .......................................................................................................................6-8 Figure 1. Steam cation conductivity at cold start .....................................................................6-9 Figure 2. Phosphate treatment zones:.....................................................................................6-10 Criteria for Maintaining Boiler Water Conditions.....................................................................6-10
APPENDIX III....................................................................................................................................6-14 Superheated Steam Purity Requirements For Normal Operation and Transients................6-14
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1. INTRODUCTION
The main objectives of water chemistry control are to insure the long term integrity of the materials of construction and the successful operation of the boiler-turbine power cycle. The particular types of chemical treatment may very depending on many factors such as the variety of materials, operating conditions, system design, etc. The treatment of the feedwater and boiler water is beyond the control of this company. This company does not assume the responsibility for water treatment and control. This is in accordance with practices established by the American Boiler and Affiliated Industries Standards Committee. The company does however, provide water chemistry guidelines that reflect good industry practices. These guidelines are generally in accordance with published guidelines from EPRI, VGB, ASME, as well as ABMA (American Boiler Manufacturers Association). One notable exception is that the feedwater and boilerwater qualities reflect the steam purity requirements specified by the steam turbine and gas turbine (if steam or water injected) supplier as opposed to those provided in the ABMA guidelines. Feedwater chemistry control is based on the following general considerations: a. Ammonia is used to control pH. b. An oxygen scavenger is not needed if the oxygen
concentration is below 10 ppb. If the use of an oxygen scavenger becomes necessary, hydrazine is preferable if allowed by local safety regulations.
c. To minimize the risk of flow assisted corrosion in the low-pressure systems (see Appendix II), the pH range has a relatively high limit and the use of organic treatment chemicals is not recommended.
Boiler water chemistry control is based on the following considerations: a. General and specific corrosion protection of the pressure parts
surfaces in the event of contamination ingress. b. Achieving the required steam purity. There are several accepted methods for controlling boiler water chemistry. The majority of drum type boilers, however, still use some form of phosphate treatment (see appendix I). The particular phosphate treatment (phosphate concentration and corresponding pH) should be selected based on the following main cycle considerations:
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1. Condenser cooling water chemistry 2. Presence of condensate polishing system 3. Phosphate hideout history or potential 4. Sodium limit in the steam It is understood that these are general guidelines and may need to be modified to meet plant specific requirements. Additional operational information, highlights, and criteria for selecting particular chemical controls are provided in Appendix I and III. A brief discussion on flow accelerated corrosion (FAC) is presented in Appendix II.
2. STANDARD SPECIFICATIONS FOR COMBINED CYCLES WITH DRUM-TYPE BOILERS
(Water Chemistry Requirements for Normal Operation) A. Demineralized Water
(at Demineralizer Water Plant Outlet)
B. Condensate
(at Condensate Pump Discharge)
Parameter Unit N Specific conductivity µS/cm < 0.20 Silica as SiO2 ppb < 20 Sodium + Potassium as Na+K ppb < 10 Iron as Fe ppb < 20 Copper as Cu ppb < 3 TOC ppb < 300
Parameter Unit N N copper alloy
tubed condenser
stainless steel or titanium tubed
condenser Specific conductivity µS/cm 2 - 6 3 - 11 Conductivity after cation exch. µS/cm < 0.20 < 0.20 pH-value - 8.8 - 9.3 9.0 - 9.6 Silica as SiO2 ppb < 20 < 20 Iron as Fe ppb < 20 < 20 Copper as Cu ppb < 3 < 3
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C. Feedwater (at Boiler Inlet)*
* Normal feedwater quality should be achieved after 30% unit load. * * For cation conductivity transient conditions, see criteria discussion.
D. Boiler Water (HP, IP and LP)
The tables below give the prime choice for HRSG drum boiler water treatment. In deviation to this specification, the following standards can also be adopted: - VGB guidelines R450L / 1988 - EPRI guidelines TR110051 - specifications of boiler suppliers approved by Alstom Note: These guidelines do not apply to the Low Pressure (LP) drum if used as a feedwater tank. In such a case, the feedwater guidelines are applicable to the LP boilerwater.
* estimated value, must be compatible with steam purity ** low phosphate concentration range applicable for all pressures *** see Table below
Boiler design criteria: - mechanical carry-over see Table above. - blowdown intermittent up to 5%, continuous 0.5...1%
Parameter Unit N N copper alloy
tubed condenser
stainless steel or titanium tubed
condenser Specific conductivity µS/cm 2 - 6 3 - 11 Conductivity after cation exch.** µS/cm < 0.20 < 0.20 pH-value - 8.8 - 9.3 9.0 - 9.6 Silica as SiO2 ppb < 20 < 20 Iron as Fe ppb < 20 < 20 Copper as Cu ppb < 3 < 3 Oxygen ppb < 10 < 10
Parameter Unit N Specific conductivity µS/cm < 40 * pH 9.1 - 9.6 Phosphate as PO4 ppm 2 – 6** Silica as SiO2 ppm ***
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E. Live Steam and Reheat Steam (at Boiler Outlet)
F. General Remarks
All conductivity’s and pH are referred to 77°F (25°C). Possible contributions from carbon dioxide may be excluded. Operation is desirable at the lowest achievable impurity levels, with the shortest and least frequent excursions. The specification is related to the following conditions: • Make-up water demand is < 1 % under normal conditions, up to
5 % maximum and intermittent. • Feedwater pH conditioning shall be done with ammonia.
Oxygen scavengers such as hydrazine are not required (if copper alloys present in the condensate system, the use of hydrazine can be evaluated).
• Organic based treatment chemicals are not recommended and should not be required in a combined cycle power plant generating electricity in which there is no process steam exported from the cycle.
Note: This is a general specification valid for the plant type mentioned only. The criteria should be reviewed for a specific application and at commissioning.
N Normal value. Values are consistent with long-term system
reliability. A safety margin has been provided to avoid concentration of contaminants at surfaces.
Parameter Unit N N copper alloy
tubed condenser
stainless steel or titanium tubed
condenser Specific conductivity µS/cm 2 - 6 3 - 11 Conductivity after cation exch. µS/cm < 0.20 < 0.20 pH-value - 8.8 - 9.3 9.0 - 9.6 Sodium + Potassium as Na+K ppb <10 <10 Silica as SiO2 ppb < 20 < 20 Iron as Fe ppb < 20 < 20 Copper as Cu ppb < 3 < 3
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APPENDIX I A. Feedwater Quality and Steam Purity.
Dissolved Solids and Oxides. The guidelines address the influence of both dissolved and suspended (i.e. oxides) solids. Since the feedwater is used for desuperheating (steam temperature control), its level of dissolved solids must be limited in order to prevent fouling of steam touched surfaces as well as achieve steam purity requirements. It should also be recognized that metallic oxides transported to the boiler (or superheater / reheater/turbine) by feedwater can foul these surfaces such that damage and/or efficiency losses may occur. Oxygen. It is indicated in the feedwater guidelines that the oxygen concentration should be limited to 10 ppb. At the same time, the use of oxygen scavengers such as hydrazine or hydrazine substitutes have been omitted. This is based on the experience from plants on Oxygenated Treatment (OT) where less reducing conditions in low cation conductivity waters (less than 0.2 µS/cm) help to form a more adherent / less soluble oxide film. This further minimizes the potential for flow assisted corrosion (FAC) as discussed in a later section. Cation Conductivity. Cation conductivity values do not include the influence of carbon dioxide. During normal operating conditions, levels of 0.06-0.2 µS/cm can be achieved. Higher values are observed during startup. Carbon dioxide, having entered the system with air during shutdown, is dissolved in the water. It requires some time until it is purged from the system. The removal rate depends on the efficiency of the deaeration devices (deaerator, condenser), as well as on cycle water pH. At cold start, normal specification values are usually obtained within a few hours for base loaded plants. Cyclic units with frequent cold starts require a significant proportion of the operating time to reach normal values. Therefore, the question is whether it is worthwhile to extend heat-up and bypass operation to achieve a low cation conductivity when solely influenced by carbon dioxide. We have investigated startup cation conductivity in several plants with an ion-chromatograph. One example is given in Figure 1. It is seen that cation conductivity started well above 1µS/cm, but with exclusion of carbon dioxide, it was never larger than 0.3 µS/cm when the turbine was on line. Such analytical techniques are normally not available in a power plant. Even if the plant would have such equipment installed, it is doubtful if it could be brought to full operating conditions by the beginning of a cold start. The same applies to degassed cation conductivity measurements. We therefore looked at substitute parameters for evaluating steam chemistry.
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The boiler water is a good indicator for the ingress of any impurities, and its relation to steam chemistry is fairly well understood. We have therefore formulated our requirement for steam cation conductivity at startup as follows: "The steam turbine can be kept in operation with boiler water purity within the specification and the conductivity of HP steam showing a large decrease in conductivity within one hour from the beginning of turbine operation."
B. Boilerwater Quality
The boilerwater quality and respective treatment is designed to produce steam with a sodium content not to exceed 10 ppb. Therefore, a low level sodium phosphate treatment has been selected. Figure 2 is a plot of phosphate vs. pH. This type of strong alkaline treatment provides good buffering capabilities in the event of impurity ingress. In those plants where phosphate treatment can be used in the LP boilers, it will also prevent the risk of Flow Accelerated Corrosion (FAC). The listed phosphate range is 2 to 6 ppm. This is limited by the sodium steam purity requirements and the steam drum mechanical or moisture carryover performance. It should be realized that the American Boiler Manufacturers Association (ABMA) guidelines allow a higher dissolved solids level (or sodium level) in the boilerwater. Consequently, for these high operating pressure ranges, the resulting sodium level in the steam will be higher than that allowed by turbine suppliers. Therefore, the turbine steam purity requirements as specified by the turbine suppliers’ control the level of phosphates and other dissolved solids in the boilerwater. All Volatile Treatment (AVT) and Equilibrium Phosphate Treatment (EPT) can be applied in specific cases should phosphate hideout occur. Each boiler is normally controlled and treated independently although the guidelines list the same level of treatment chemicals and conductivity. With demineralized feedwater, there really is no need to allow higher dissolved solids in lower pressure boilers just because it can handle it without adversely affecting steam purity. The use of Sodium Hydroxide is considered to be risky for low-staffed power plants, as it requires much more attention and control to be safely applied. In a typical combined cycle, the condensate or feedwater is relatively free of iron oxide during stable operation. Therefore, there is no need to use organic dispersants in the boilerwater. These organic substances can decompose to carbon dioxide as well as produce organic acids. These acids can then circulate throughout the cycle. As a consequence, they could destabilize (if only treated with ammonia) the magnetite layer on the LP boiler
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surfaces which can increase the potential for flow accelerated corrosion. The table titled “Criteria for Maintaining Boilerwater Conditions” provides some guidelines in the event of contamination ingress as measured by cation conductivity.
measuredcalculated all anionscalculated anions without CO2MW
Stea m HP-boiler 2
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Figure 2. Phosphate treatment zones: A – Coordinated phosphate-pH control with good buffering capabilities. B – Congruent phosphate-pH control used to buffer caustic contaminants. C – Phosphate-Caustic control used to buffer acidic contaminants. D – Equilibrium Phosphate control used where phosphate hideout might otherwise occur/buffering capacity is however limited.
Criteria for Maintaining Boiler Water Conditions
Boiler Water Chemistry Control Feedwater Conditions Phosphate Volatile Alternatives Operational Limits
Cation Conductivity <0.2 µS/cm
TDS <15 ppm pH* 9.1-9.6 PO4 2-6 ppm
TDS <2 ppm pH 8.6-9.0
See Figure 2 None.
Cation Conductivity 0.2-0.5 µS/cm
TDS <15 ppm pH 9.1-9.6 PO4 2-6 ppm
Not Suitable See Figure 2 Monitor steam purity. Increase blowdown if required.
Cation Conductivity > 0.5 µS/cm
TDS < 25ppm PO4 2-10 pH 9.1-10.1 *Boiler water pH under phosphate control should be higher (by a minimum of 0.2 units) than the feedwater pH
Not Suitable See Figure 2 Limited operation. Refer to turbine steam purity guidelines for abnormal conditions. Load will need to be reduced as well as the use of desuperheating spray water. If feedwater cation conductivity increases above 1.0 µS/cm, prepare for orderly shutdown.
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APPENDIX II
A. Flow Accelerated Corrosion (FAC)
Major parameters, which influence FAC, are: pH, turbulence (flow geometry and velocity), steam moisture in two-phase flow, temperature, oxygen concentration, and material composition. In the steam/water system, FAC is mainly observed in the temperature range between 175-450°F (80-230°C), with a maximum in the temperature range around 300-350°F (150-180°C). Regions of concern are: • Economizer tubes at HP and IP inlet headers • LP-evaporator surfaces at bends • LP-drum internals • LP horizontal evaporative tube bends To date, economizer, low pressure evaporative tubes (at bends), and drum internals have experienced FAC in several heat recovery steam generators in combined and co-generation cycle plants. Economizer inlet tubes have experienced FAC due to low pH conditions (in 3 plants, steam purity requirements did not allow the use of feedwater pH control chemicals, thus the pH was in the range of 6.5 to 7). Evaporative tubes and other LP components such as drum internals with few exceptions have normally not experienced this type of attack with either AVT treatment (pH in the range of 9.2 –9.6) and certainly not with strong alkaline chemical additives (such as phosphates). The exceptions (3 cases) involved FAC of drum internals in LP boilers where an organic water chemistry program (organic dispersants, organic amines, and organic oxygen scavengers) was used. In summary, a fluid environment needs to be provided that can promote oxide stability and at the same time meet plant requirements. In other words, high feedwater pH controlled with ammonia and no oxygen scavengers is recommended as long as the normal oxygen content is less than 10 ppb (the need to use organic amines for feedwater and condensate pH control in co-generation facilities should be evaluated for each specific site). Flow assisted corrosion of carbon steel is defined as the acceleration or increase in the rate of corrosion caused by the relative movement between a corrosive fluid (either single phase-water or two phases-water and steam mixture) and the metal surface. The main influence of fluid velocity and/or turbulence is the localized removal of protective surface films (magnetite) which then leads to accelerated corrosion of the base metal. The dissolution of the magnetite film is enhanced by the mass transport of soluble iron species (Fe II) away from the surface. If the rate of mass transfer of these species to the bulk of the fluid is
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accelerated by flow/turbulence, it will increase metal loss as iron oxidizes to replace the dissolved film. The 1988 American Power Conference paper by Henzel, et al "Erosion Corrosion in Power Plants under Single - and Two - Phase Flow Conditions - Updated Experience and Proven Counteractions" provides a useful summary of some of the research on FAC. Major parameters which influence erosion corrosion or FAC are 1) velocity, 2) temperature, 3) pH, and 4)-oxygen concentration. Velocity: The effect of velocity or turbulence is to increase the mass transfer of chemical species to and away from the metal surface. This is not a case of "mechanical" abrasion or erosion. Normally, the erosion corrosion studies cover high velocity ranges compared to what we might expect for mean velocity in boiler tubes or feed pipes, however, as we know from field experiences, even at "normal velocity", erosion corrosion can occur depending on the severity of the fluid properties. Under these conditions, FAC problems typically occur in turbulent areas (tubes in inlet headers, bends, tees, valves, etc.) where the local velocity vectors may be much higher than the mean. Temperature: The effect of temperature on metal loss parallels the effect of temperature on solubility of iron oxide (magnetite) in water. At low temperatures, the oxide that is formed is iron hydroxide; this shifts to magnetite at high temperatures. These two materials have different solubility characteristics, accounting for a temperature peak around 300 - 350 F (150-177C). Minimum and maximum temperature limits have been reported for the most part in the range of 170F (77C) and 450F (232C), respectively.
Oxygen: Oxygen would normally be thought to cause additional corrosion and in the presence of dissolved solids, it does increase corrosion. In an environment of high purity water, oxygen acts to stabilize the protective coating and actually reduces the rate of metal loss. This is the same principle being exploited for Oxygenated Treatment in once-through units. pH: The pH and the oxidation–reduction potential (ORP) of the fluid in a typical system are the more influential of these parameters since it directly affects the solubility of iron oxide/hydroxide. Either of these conditions such as low pH or a high negative ORP (reducing conditions) can cause this corrosion. Maintaining the pH as high as practical will minimize the dissolution of iron oxide. When the pH is reduced below 8.5, the potential for FAC is increased substantially. The maximum metal loss occurs from pH 7 and below into the acidic range. Although ORP is not usually a standard measurement, chemistry conditions that promote a reduced environment must be avoided. This topic is discussed in greater detail in a following section on iron oxide solubility.
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Iron Oxide Solubility Iron oxide or magnetite dissolution is typically represented by the Sweeton and Baes equilibrium reaction: 1/3Fe3O4 + (2-b)H+ + 1/3H2 = Fe(OH)b (2-b)+ + (4/3-b)H2O Ferrous hydroxide on the right side of the equation is the soluble product. As indicated by this equation, the dissolution of magnetite is influenced by the oxidation-reduction potential (ORP) of the solution as represented by hydrogen (H2). It is also influenced by the pH as represented by the hydrogen ion. Therefore, the dissolution increases as the ORP becomes more reducing (negative potential) and the pH decreases. The reaction is also a diffusion-gradient driven process, which involves the mass transfer of the ferrous ions from the oxide layer to the bulk fluid. Therefore, the dissolution rate is dependent on the local flow conditions. Turbulent flow increases the dissolution rate. Areas of turbulence in HRSG components which have been known to experience FAC are tube bends/elbows, inlet header tubes (simulates a “T” connection) and steam drum perforated/centrifugal separators.
Other chemical substances such as organic compounds can affect the solubility of iron oxide. For example, organic contaminants can thermally degrade at higher temperatures to form compounds such as acetates or acetic acid. These can affect the solubility of magnetite and at the same time form a soluble iron acetate compound. Ammonia, which is used for feedwater pH control, has a lower dissociation rate at higher temperatures so that the local high temperature pH can be substantially lower than measured at ambient temperature. This is normal behavior and taken into account in cycle water chemistry. However, organic substances could enter the cycle, become acidic at higher temperatures and significantly affect the pH even with ammonia present. Ammonia also volatilizes at higher temperatures. This will also have a lowering effect on pH. Unlike ammonia, strong alkaline substances such as trisodium phosphate used in the boilerwater provide a high pH unaffected by temperature and can form stable/non-volatile compounds. The potential for FAC in boiler or evaporator tubes is negligible if the boilerwater is properly treated with phosphate chemistry.
HRSG OPERATION AND MAINTENANCE
ALSTOM Power Revision: 0 6-14 Copyright 2005 04/02/05 Project: NUBARIA POWER STATION I & II APPENDIX
APPENDIX III A. Superheated Steam Purity Requirements For Normal Operation and Transients
Note: This table is similar to Table 5 from the guidelines with the addition of transient values which could also be used as a guide during start-up operations.
Sodium (Na) ppb ≤ 10 10-20 20-40 ≥ 40 C orM2 Silica (SiO2) ppb ≤ 20 > 203 - (> 100) C or M2 Iron (Fe) ppb ≤ 20 (> 100) M pH - 9.0-9.64 M5
(C = online monitoring, M = grab sample) 1) = Possible contributions from carbon dioxide may be excluded 2) = Preferably online 3) = Time permitted above 20 ppb SiO2: [hours]x[ppb]<105 4) = Preferably in the high range (9.4-9.6) in all ferrous systems 5) = Condensate pH may be used as indication of steam pH N Normal value. A1 Action Level 1. Potential for the accumulation of contaminants and corrosion attack. Return to normal values within one week. Maximum exposure is 336 cumulative hours per year, excluding start up conditions. A2 Action Level 2. Accumulation of impurities and corrosion attack will occur. Return to normal levels within 24 hours. Maximum exposure is 24 hours per year, excluding start up conditions. S Immediate shutdown. Immediate shutdown of the concerned system is required to avoid damage.
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SECTION 7: INSPECTION and MAINTENANCE
7.1 LEARNING OBJECTIVES Identify areas to inspect, possible inspection findings, and approaches for repair to major pressure parts. 7.2 HRSG INSPECTION RECOMMENDATIONS HRSG General Inspections should be carried out approximately once every twelve months. These inspections should be coordinated with the scheduled plant outages of other major combined cycle plant equipment and inspection requirements of the Authorized Inspector. In addition, detailed Inspections should be carried out every 5 - 10 years depending on plant operating history. This detailed inspection is primarily a visual inspection of all accessible pressure parts. The visual inspection will identify any areas of concern that require subsequent Non-Destructive Examination (NDE). Descriptions of the General Inspections and Detailed Pressure Part Inspections follow. General Inspection (Annual) Inlet Duct and Boiler Casing The following items are noted during the inspection. • External Casing is inspected externally to identify any areas of significant overheating or
cracking. • Internal Liners are inspected for severe warpage, excessive loss of stud/washer
attachments, liner cracking and loss of insulation. • Gas Baffles are inspected for mechanical integrity. • Flow Straighteners are inspected for overall mechanical and weld integrity. • Duct Burners are inspected for mechanical/weld integrity, burner component overheating,
fouling and wear. Detailed inspection of burner elements, ignitors and scanners should be made pursuant to manufacturer’s recommendations.
• Expansion Joints are inspected internally and externally. Pressure Parts All readily accessible pressure part components are visually inspected. Tubing within the gas path is inspected for severe or progressive bowing, fin/tube weld integrity and evidence of fouling, deposits or corrosion. Particular attention to the cold end sections is recommended. Internal inspection of the drums and deaerator should be carried out. All headers and connecting piping within the upper and lower vestibules should be visually inspected. All external piping and valves should be inspected noting hanger condition and valve condition. All pressure part casing penetrations should be inspected for evidence of cracking.
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Stack External and internal inspection of the stack should note mechanical integrity and evidence of internal corrosion. Stack Dampers should be inspected to verify full open and full closed capability and evidence of vibration and wear. Stack silencers should be inspected for mechanical integrity, warpage and integrity of fiber packing. SCR and CO Catalyst (If Applicable) SCR and CO Catalyst should be inspected for mechanical integrity of supports, erosion/corrosion of the catalyst elements and evidence of fouling or deposits within the catalyst elements. Ammonia injection grids should be inspected for integrity of the mechanical supports and condition of the injection nozzles. The ammonia supply system should be inspected pursuant to the manufacturer recommendations. Detailed Inspection (Every 5 - 10 Years) Visual Inspection This inspection usually includes the following:
• Steam Drums and Steam/Water Separator
• Upper and lower evaporator headers adjacent to access areas
• Upper and lower economizer headers adjacent to access areas
• Upper and lower superheater and reheater headers adjacent to access areas
• Downcomers, risers, connecting lines
• Superheat and reheat piping
• Feedwater piping
• Boiler water circulating pumps
• RH and SH desuperheaters
• Deaerator
• Orifices
• Strainers
This visual inspection is a more detailed inspection that that required annually. This may require removal of insulation and lagging in order to access drum and external piping.
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The following is noted during the inspection:
• The external surfaces, internal surfaces and associated equipment of all drums or steam/water separator should be visually examined for indications of cracks, erosion, corrosion, loose or broken hangers/supports, loose or missing internals that might be indicative of a variety of failure mechanisms and their condition documented.
• Condition of full penetration welds and their heat affected zones, (including longitudinal seams for those headers fabricated from plate, girth welds, welds at tees or formed openings and end closures).
• Condition of selected socket welds and their heat affected zones (including connecting pipes, vent and drain piping).
• Selected bore-holes.
• Machined corners of manway seating surfaces.
• The steam drum liner or baffling should be visually examined, preferably by means of wet test, for indications of cracks.
• The circulating pumps, suction and discharge valves should be checked for fatigue cracking. One of the pumps and one of the suction valves should be internally inspected.
• The external surfaces of a header are visually examined for indications of cracks, corrosion, erosion, swelling, exfoliation, discoloration, bowing, loose or broken hangers/supports that might be indicative of a variety of failure mechanisms and their condition documented.
• The internal surfaces of a header and bore-holes of terminal tubes may be examined visually for indications of cracks and for abnormalities such as excessive deposits or corrosion.
• Desuperheater liners should be inspected for erosion and cracking utilizing a standard boroscope.
Nondestructive Examination (NDE)
Following Visual Inspection additional NDE tests should be carried out in any areas of concern. The following techniques may be used.
• Radiograph
• Weld Seam Etching
• Diameter and Circumference Measurements
• Borehole Examination
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One examination routinely performed during a header condition assessment is the examination of header bore-holes. This examination detects the presence of borehole cracking through the use of an oxide cleaning method, fluorescent dye-penetrant examination and visual/dimensional inspection.
• Magnetic Particle Examination
Magnetic particle examination or testing (MT) and/or wet fluorescent magnetic particle examination (WFMT) should be used at selective locations to determine the existence of mIcrocracks that may not be apparent. Surface discontinuities and shallow subsurface discontinuities can be detected by using this method. Check circumferential seams and a number of socket welds and their heat affected zones (including supply tubes, terminal tubes, vent and drain nozzles).
• Liquid-Penetrant Examination
Liquid-penetrant examination or testing (PT) is a highly sensitive non-destructive method for detecting discontinuities (flaws) such as cracks, pores and porosity which are open to the surface of solid and essentially nonporous materials.
The fluorescent-penetrant inspection (FPT) uses penetrants that fluoresce brilliantly under ultraviolet light. The sensitivity of the fluorescent penetrant (solvent removable) technique is considered to be very high and recommended for areas where minute defects may be present.
• Ultrasonic Shearwave Examination
Ultrasonic examination, utilizing O° longitudinal sound waves and 45° and 60° refracted shear waves, is extremely useful in detecting the presence of surface and internal discontinuities or non-homogenous areas in materials. This technique provides useful information on whether or not the crack(s) can or should be weld repaired. • Ultrasonic Thickness Measurements
Wall thickness readings shall be taken at the dimensional test locations, on selected elbows and bends, and where recordable indications are found. Readings should be taken around the whole circumference of the pipe (0°, 90°, 1800 and 270°) and on the outer wall in the arc of the bend on selected elbows and bends.
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7.3 TUBE CIRCUITS
The purpose of the internal inspection is to take a close look at the inside components and areas which are not accessible when the unit is in service in order to find potential problem areas and to repair these areas at a convenient time. Refer to Pressure Part General Arrangement Drawings behind Tab 10.
• The inspection begins only after the unit is down, has been cooled, cleaned, and secured.
• Make all safety checks and obtain all necessary clearances before opening any of the access doors.
• Enter the HRSG through access doors.
• A safer and more efficient way of inspecting the interior is with the use of scaffolding, a method that will save time and money in the long run. With an arrangement of scaffolding, a more complete and thorough inspection can be performed, maintenance and repair personnel have easy access to the unit, and continuous access is provided to the entire HRSG.
• During the internal inspection, check historic problem areas based on OEM Service Engineering reports.
• Use visual observations, comparisons, measurements, and non-destructive examination techniques as methods for the inspection.
Recommended Inspection General Areas
The tube circuits are arranged in both horizontal and vertical assemblies with the water/steam flow countercurrent to gas flow.
• Inspect each of the tube banks for alignment and possible signs of overheating using an outside micrometer.
• Check clearance between tube assemblies and casing sidewalls.
• Examine all supports.
• Examine all baffles and partition plates.
• Examine all header assemblies. Inspect welds around tube nipples and headers for cracks and erosion.
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7.4 DRUMS AND HEADERS
Steam Drum
The material used to make up the drum and internals is primarily high strength carbon steel. The nozzles in the drum heads are provided for attachment of water level gauges and indicators, vent valves, and safety valves.
Prior to an outage, take steam samples individually from the sampling nozzles installed in the steam outlet tubes along the drum. These samples will detect the presence of localized carryover
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CHEMICAL FEED FEED LINE INLET
CONTINUOUS BLOWDOWN LINE
Figure 7-1: HRSG Steam Drum, Typical
WARNING:
Before entering the drum, ensure that the drum has been purged and that the environment is safe.
WARNING:
If the unit has been laid up with nitrogen, make sure that the steam drum is vented completely before any inspection is performed. Place an air mover in the end of the drum not being inspected; this will provide adequate ventilation. A second person should remain outside the drum as a safety precaution.
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As previously stated, the steam drum serves several functions: • Provides a point for separating the steam and water
• Houses the equipment used for purifying the steam after separation
• Houses the header used to distribute the incoming feedwater. Examine the steam/water
separating equipment. Inspect the separators, both the primary and secondary stages.
Look for corrosion, deposits, erosion, missing parts, etc. Examine the condition of the
corrugated plate dryers and the return piping. Drum Inspection Reminders:
• Check the condition of the seal around the manway door.
• Check the area around the inside of the manway door.
• Check the interior of the drum for corrosion and deposits.
• Check the condition and mounting of the blowdown pipe and the feedwater
distribution header.
• Check the downcomer nozzles, screens, and vortex eliminators.
• Check all drum internals for wear and fit.
• Pay particular attention to the areas behind the primary and secondary separators.
• Thoroughly examine the drum internals for cracks. Missing fasteners or separation of
the plates will allow boiler water to bypass the steam separation equipment and allow
the carryover of boiler water into the superheater.
Headers Headers are located throughout the water and steam circuits of the boiler. They collect water or steam from a group of tubes and are not physically accessible for entrance. However, they may have handhole inspection ports which allow for a visual internal inspection. During an inspection, thoroughly inspect the headers inside and out. Header Internal Inspection To perform an internal inspection, remove the handhole inspection ports on the header. Examine the interior for corrosion, deposits, or any other foreign material. Check the area around the handhole for any signs of cracking. Check the handhole seal.
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ALSTOM Power
D4006-Bu042
Figure 7-2: Typical Header Connections
Header External Inspection During an external inspection, visually check the entire header for corrosion, erosion, etc. Visually check the header nipple welds for signs of cracking. If any cracking is found, determine the depth and location, and consult the manufacturer for recommended repairs. Inspect the area around each header for signs of potential problems. 7.5 DESUPERHEATERS To assist in controlling the final temperature of the steam going to the turbine, a superheater desuperheater is located at the superheater outlet. (Figure 7-3) A desuperheater is also located in the reheat outlet line to provide final reheat steam temperature control during transient conditions. A spray type desuperheater employs spraywater as a cooling medium to the superheated steam. Water is sprayed directly into the steam flow thus adjusting the steam temperature.
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FROM SPRAY WATER SOURCE
(BOILER FEED PUMP)
Figure 7-3: Desuperheater Schematic
A replaceable liner is installed for protection against erosion and thermal shocking of the desuperheater heavy wall-connecting link by the cooler spraywater. Spraywater desuperheaters must utilize feedwater quality water because of the location of the desuperheater in the steam circuitry. By design, there is sufficient time for evaporation of the spray water over the control range of the unit before the steam reaches the turbine for either the superheater or the reheater.
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Monitor condition of spray water control and block valves to insure valves maintain tight seals when spray is not required. Inspection The purpose of the desuperheater is to control steam temperature through the use of cool tempering water. Desuperheaters are installed in both the superheater and reheater circuits. The typical in-line desuperheater, shown in Figure 7-4, consists of a shell, liner, and spray nozzle assembly. The shell acts as housing. The spray nozzle assembly introduces the tempering water. The liner protects the shell from thermal shock when the relatively cold tempering water is injected into the steam system.
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Figure 7-4: Typical Desuperheater Details Superheater and desuperheater liner inspections should be conducted every three to five years. This inspection is accomplished with a boroscope. The boroscope is inserted through the spray water nozzle opening after removing the spray water control valve or via a hand hole plate. Examine the liner for any gross deformations. Examine the spray nozzles for any enlargement of the nozzle holes. If extensive wastage is found, replace the spray nozzle. 7.6 TUBE FAILURE ANALYSIS (Short Term Overheating) For a specific tube material, there is a maximum allowable stress at a particular temperature. If the tube metal temperature increases beyond this point, creep will occur and the tube will eventually fail by stress rupture. Superheaters and reheaters can experience interruptions and/or reductions in steam flow that can increase tube metal temperatures that lead to stress rupture failures. With ferritic steel, a "fish mouth" or longitudinal rupture, with a thin edge fracture is most likely. With other tube materials, still other appearances are possible. The causes for this type of failure are the following: • Abnormal coolant flow from a blockage in the tube • Blockage due to debris in the tube • Blockage due to scale in the tube • Blockage due to condensate in the tube following an incomplete boilout • Excessive combustion gas temperatures • High temperatures from over-firing during start-up
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Figure 7-5: Short Term Overheating Appearance
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High Temperature Creep A small fracture may be associated with a blister, while a large fracture could have a thick edged, “fish mouth”, longitudinal crack. The area around the fracture may have an alligator hide appearance, with significant oxide scale penetration. The root causes for high temperature, longer term failure such as these are the following:
• High heat flux into a section of the boiler that could have used a higher grade of steel
• Excessive hot gas flow through an area that is plugged
• Excessive heat absorption from an adjacent lug, or other welded attachment • Partial pluggage from blockage or internal scale
Figure 7-6: High Temperature Creep
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Dissimilar Metal Welds The weld failures will normally have one side of the weld that responds to a magnet, while the other does not. The weld crack will be circumferential at the weld; over on the side that responds to the magnet; the ferritic side. The cause of failure relate the stress of the two metals expanding differently plus:
• Stress from internal steam pressure • Stress from the vertical weight on the weld • Stress from the constraints of how the tube is supported or attached • Internal thermal gradients, which add up to the total stress. The higher the value, the sooner the weld fails.
Figure 7-7: Dissimilar Metal Welds
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Appearance Welding Defects If the defect is most notable on the inside, it can become a failure from an internal scale build-up, and resultant corrosion, or corrosion fatigue failure. If the defect is with the integrity of the weld itself, the failures often appear as a brittle failure, where stress is concentrated in a small area. Causes again relate to quality control: • The procedure. • Weld material used. • Preparation of the tube ends before the first pass.
Pitting - Localized Corrosion (Water-Side Corrosion) Water containing dissolved oxygen is highly corrosive to many metals; therefore everything must be done to minimize the introduction of oxygenated water into the boiler and pre-boiler systems. Oxygen corrosion can dramatically affect various components in operating and non-operating boilers. Much of the suspended crud that enters an operating boiler is the direct result of oxygen attack of components in the pre-boiler system. Localized pitting is found where oxygen is allowed to come in contact with the inside of the tubes, which is just about anywhere. It appears as a steep edged crater with red iron oxide surrounding the pit. The tube surface near the pit may show little or no attack. Sometimes there is a series of smaller pits. The typical cause starts with: • High levels of oxygen in the feedwater, i.e., poor deaeration at start-up • Filling of condensate in low point, such as bends, when the steam cools • Outages where air gets inside the assembly from adjacent repairs, or vents being left open
as the steam condenses
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Figure 7-8: Localized Pitting Appearance
Stress Corrosion Cracking (Water-Side Corrosion) These thick-edged fractures can be either circumferential or longitudinal, depending on how the stress is oriented. Typically the chemical attack is on the inside of the tube and works its way out through the growing crack. Far less commonly, the chemical attack exists on the outside (gas side) and works its way inward. The root cause is the coupling of more than one factor working on the same location: From the chemistry side are the contaminants of chlorides, sulfates, or hydroxides on either the inside (common) or outside (less common) • Contaminants can come from boiler steam drum carry over • Contaminants can come from contamination in the desuperheater spray • External contaminants come from acidic components to the fuel • Additionally there must be a stress possibly from a bend in the tube • Weld attachments from initial assembly • Or possibly from cyclic unit operation
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Figure 7-9: Stress Corrosion Appearance Low Temperature Corrosion (Gas Side) External surfaces of economizer tubes that are exposed to a moist environment containing flue gases can experience acid corrosion. Certain acidic salts (ferrous sulfate for example) can hydrolyze in moist environments to produce low pH conditions that will attack carbon steel. Sulfur trioxide (SO3), present in the cooler flue gas areas, and can react with water vapor to produce sulfuric acid. If the temperature is below the dew point, sulfuric acid condenses along metal surfaces and corrodes the metal. Water washing can also produce acid attack. A gouged exterior and a thin ductile failure characterize this form of failure. When the pressure becomes too great, the pressure inside blows out a hole. The root cause for low temperature failures are: • The presence of sulfur in the oil, which has an opportunity to condense on the last rows of
economizer tubes.
• The condensing of sulfur and ash when the exit gas temperature is low.
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Figure 7-10: Low Temperature Corrosion Appearance
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Vibration Fatigue In locations where boiler tubes are welded to support lugs, a thick edge failure can form at the toe of the weld. This fracture is circumferential, running at right angles to the weld. The root cause is: • The vibration of the tube, caused by the steady flow of exhaust gases. • Along with a lug location that induces a rigid point that will concentrate the force into a short
distance.
Figure 7-11: Vibration Fatigue Appearance
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Corrosion Fatigue Like the previous fatigue mechanism, cyclic stresses produce a series of parallel surface cracks, however this time the corrosive environment adds to the deterioration by forcing the oxide wedge into the cracks, further leveraging the fracture. The thick edge fracture will be coated with an oxide layer. Pits can often be found on the inside surface of the cracks. The causes have two key ingredients which are Corrosion and Stress. There is either induced stress from the way the tube connects to another pressure part or there is induced stress from the way the tube is tied to a structural support. • There is residual stress left over from fabrication. • Internal pits from dissolved oxygen or acidic corrosion from the pre-boiler circuit
aggravate the cracking process in the water cooled tubes. • External corrosion in steam cooled units aggravates the cyclic flexing where the tube
enters the header.
Figure 7-12: Corrosion Fatigue Appearance
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SECTION 8: HRSG START UP CURVES 8.1 LEARNING OBJECTIVES Understand HRSG operational phenomena under various conditions 8.2 DESCRIPTION OF CURVES Analysis Method Startup curves for the triple pressure, reheat HRSGs have been developed to describe the dynamic response of the HRSG under Cold Start, Warm Start and Hot Start conditions. HRSG process conditions (pressure, temperature, and flow) for the HP, IP, and LP sections have been predicted based on field experience with other triple pressure reheat HRSGs. In addition, response profiles have also been estimated by reference to detailed computational models developed for dynamic analysis prediction of dual pressure HRSGs. Basis for Predictions: Startup Curves (9 total) have been prepared for the following conditions. Pressure Decay curves (3 total) have also been prepared to show pressure response to the system during shutdown. 1. HP Cold Start (> 72 hours) 2. IP Cold Start (> 72 hours) 3. LP Cold Start (> 72 hours) 4. HP Warm Start (> 8 hours < 48) 5. IP Warm Start (> 8 hours < 48) 6. LP Warm Start (> 8 hours < 48) 7. HP Hot Start (< 8 hours) 8. IP Hot Start (< 8 hours) 9. LP Hot Start (< 8 hours) 10. Pressure Decay- HP 11. Pressure Decay- IP 12. Pressure Decay- LP These self-explanatory curves describe the change in boiler process conditions (pressure, temperature and flow) versus time in response to the Gas Turbine operating conditions summarized above.
Notes: 1. 100% Speed = 3600 rpm.
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HRSG Performance Curve Selection Sheet Summary List
1 HRSG Start-up - HP Hot Start Hot Start Curves Revised to Account for Operation of MHI Ventilator Valve from ST speed of 0 rpm to speed of 100% and load of 10%
1 HRSG Start-up - HRH/IP Hot Start 1 HRSG Start-up - LP Hot Start
1 HRSG Start-up - HP 1x1x1 to 2x2x1 Start Added curves at request of customer. 1 HRSG Start-up - HRH/IP 1x1x1 to 2x2x1
Start
1 HRSG Start-up - LP 1x1x1 to 2x2x1 Start
1 HRSG Shut Down - HP Pressure Decay 1 HRSG Shut Down - IP Pressure Decay 1 HRSG Shut Down - LP Pressure Decay
Notes: Cold Start is startup after 72 hour shutdown or longer. Warm Start is startup after 48 hour shutdown. Hot Start is startup after 8 hour shutdown.
References: 1. Start up and Load diagram for a Diverter Downstream of a Gas Turbine, Nubaria Power Station I & II, V94.3A date 02/07/03. 2. Nubaria Power Plant II 2 x 750MW GTCC (Start-up Curve (Cold)). 3. Nubaria Power Plant II 2 x 750MW GTCC (Start-up Curve (Warm)). 4. Nubaria Power Plant II 2 x 750MW GTCC (Start-up Curve (Hot)).
HRSG OPERATION AND MAINTENANCE
ALSTOM Power Revision: 0 8-4 Copyright 2005 04/02/05 Project: NUBARIA POWER STATION I & II
14 STRAINERSBD Tank Cooling System Strainer BM BM STR-001B (Supplied by BD Tank vendor) 1 4 150 40/6.23 SA-106C 150 40/6.23 SA-106C 100 3.5 150 Y Strainer BW N SSI SSI Series 150Y 150YBWSB 150 304SS N/A N/A 08003-1D0017 19581000Cond PRHTR Recirc Line Strainer AA AA STR-040 1 4 150 40/6.23 SA-106C 150 40/6.23 SA-106C 150 26 178 Y Strainer BW N SSI SSI Series 300Y 300YBWSB 300 CS N/A 08003-10.77 08003-1D0016 19581000HP DSH Spray Strainer AA AA STR-300 1 4 50 160/7.65 SA-106C 50 160/7.65 SA-106C 50 225 180 Y Strainer SW N SSI SSI Series 1500Y 1500YSWSB 1500 CS N/A 08003-10.77 08003-1D0012 19581000RH DSH Spray Strainer AA AA STR-700 1 4 50 80/4.85 SA-106C 50 80/4.85 SA-106C 50 88.9 180 Y Strainer SW N SSI SSI Series 600Y 600YTST 600 CS N/A 08003-10.77 08003-1D0013 19581000
Notes:1. These valves will be shipped loose by AP to install customer piping. They will installed by customer. 2. Quantities shown are for One (1) unit. There are Four (4) units on this contract. Except for the quantities shown with "*" are for Two (2) units only.
For the complete tagging, prefix the tag number with the following:For Four (4) units.: For Two (2) units with "*":Unit 1 1A-System Locator Code Unit 1 1X-System Locator CodeUnit 2 1B-System Locator Code Unit 2 2X-System Locator CodeUnit 3 2A-System Locator Code Unit 4 2B-System Locator Code Tagging example as follows for Four (4) units.: Tagging example with "*" as follows for Two (2) units.:Unit 1 1A-AA-V-001 Unit 1 1X-AA-V-001DUnit 2 1B-AA-V-001 Unit 2 2X-AA-V-001DUnit 3 2A-AA-V-001 Unit 4 2B-AA-V-001
3. Upstream and downstream piping information are available at document # 9.72 - Pipe List and 9.78 - Trim Pipe List.Rev. Date Rev Log
0 01/15/04 Initial Release of Valve List1 C1 02/27/04 Revised per AP trim line standards and per new pegging steam configuration.
Moved RH Desup Check valve from trim valve list to check valves.Added 4 isolation valves for HP FW FT redundant.Added 4 isolation valves for HP desup DPI.
2 C1 3/18/2004 Revised per customer tagging system (no four digit tags)Added V-830, 831 and V-822,823.Revised design pressure and temperature.Corrected line sizes.
3 C1 5/6/04 Revised per customer comments. Added vendor information. Revised instrument air valves. 4 C2 8/13/2004 Revised per customer comments. Added vendor information. Added valves. Revised design temp and press per customer request.5 C2/C1 9/3/2004 Revised per customer comments. Added vendor information. Revised flow/pressure transmitters to flow/pressure indicating transmitters.6 C2 11/03/04 Revised some safety valves manuf dwg numbers and set pressures. Changed V-356 valve size to 300mm. Added control valve manuf dwg numbers. Revised some block valves manuf dwg numbers.
Relocated ERV press sensing isolation valves to trim valve section.Revised some trim valves manuf dwg numbers. Added Inlet Duct PIT Isolation and transition Duct PIT Isolation valves.
7 C2 12/21/04 Added HP and RH Desup Outlet ventsChanged the total quantity for V-080, V-081 from 8 to 4.Removed HP, IP and LP Evap chem cleaning connection isolation valves.Corrected model numbers for some trim valves and instrument isolation valves.Changed the line size to DN20 for DA Cond pot vent.
8 C2 2/18/2005 Revised some of the trim valve model numbers.Added LP stm PIT isolation valves. Added Owner system locator code.
9 C1 6/08/05 Added HP Nitrogen and Chemical feed isolation valves.Added cleaning connection isolation valves.
10 C2 7/29/2005 Revised valve tag No. V-010D & V-013D to motor operated valves tag No.: HV-010D & HV-013D.Revised Valve tag no. from V-272 to V-276 for HP Nitrogen Feed Isolation ValveRevised Design pressure from 150 barg to 10 barg for cleaning connection valves Changed Description for HV-004D valve
ALSTOM POWER Inc.Project Name: Nubaria Power Station I & IIContract No.: 66008003
INSTRUMENT LIST Item No.: 11.01Rev. No.: 11
Date: 06/29/05Doc. Type: E
RevCate Desc
OwnerSystem
AlstomSystem Tag Number Qty Qty DesignT DesignP
Process Conn Process Instrument Instrument Service Instrument Type Vendor/Manuf Manuf Drawing Model Number Local/ Calibrated Range Calibrated Range Process Range Process Range
Electrical Range Datasheet/Ref Number P&ID Drawing
gory
Locator Code
Locator Code
Total for contract (°C) (barg) (mm) End Conn Conn (mm) End Conn Description Remote SI (See Note 2)
English Units (See Note 2) SI English Units
01 FLOW ELEMENTSCond PRHTR FW FE AA AA FE-001 1 4 55 26 200 FLG 20 NPT Water Orifice Fluidic Techniques V-2499R1-4 8" 300# Series 300 Local 0-5080 mm wg 0-200" wg 0-97.62 kg/s 0-774774 lb/hr N/A 08003-11.16 08003-1D0016CPH Recirc pump min recirc RO AA AA RO-042 1 4 178 33.5 50 FLG 20 NPT Water Orifice Fluidic Techniques P-22217-1 2" 300# Local 21.43 mm 54/64 inch dia N/A N/A N/A 08003-11.19 08003-1D0016HP DSH FE AA AA FE-300 1 4 180 225 50 FLG 20 NPT Water Orifice Fluidic Techniques V-2499R1-5 2" 2500# Series 300 Local 0-5080 mm wg 0-200" wg 0-4.20 kg/s 0-33334 lb/hr N/A 08003-11.16 08003-1D0012HP FW FE AA AA FE-100 1 4 180 225 200 FLG 20 NPT Water Orifice Fluidic Techniques V-2499-1 8" 2500# Series 300 Local 0-6350 mm wg 0-250" wg 0-90.0 kg/s 0-714297 lb/hr N/A 08003-11.16 08003-1D0012HP Stm Outlet FE AA AA FE-340 1 4 579 150 350 FLG 20 NPT Steam Flow Nozzle Fluidic Techniques V-2499R1-1 14"-Model V-200 Local 0-12700 mm wg 0-500" wg 0-90.0 kg/s 0-714297 lb/hr N/A 08003-11.16 08003-1D0012IP FW FE AA AA FE-400 1 4 180 88.9 80 FLG 20 NPT Water Orifice Fluidic Techniques V-2499-2 3" 600# Series 300 Local 0-6350 mm wg 0-250" wg 0-14.32 kg/s 0-113653 lb/hr N/A 08003-11.16 08003-1D0013IP Stm Outlet FE AA AA FE-600 1 4 374 31.5 200 FLG 20 NPT Steam Flow Nozzle Fluidic Techniques V-2499R1-2 8" Model V-200 Local 0-5080 mm wg 0-200" wg 0-12.86 kg/s 0-102065 lb/hr N/A 08003-11.16 08003-1D0013LP FW FE AA AA FE-800 1 4 180 40 80 FLG 20 NPT Water Orifice Fluidic Techniques V-2499-3 3" 300# Series 300 Local 0-3810 mm wg 0-150" wg 0-11.99 kg/s 0-95160 lb/hr N/A 08003-11.16 08003-1D0014LP Stm Outlet FE AA AA FE-915 1 4 314 8.5 400 FLG 20 NPT Steam Flow Nozzle Fluidic Techniques V-2499R1-3 16" Model V-200 Local 0-1270 mm wg 0-50" wg 0-9.02 kg/s 0-71588 lb/hr N/A 08003-11.16 08003-1D0014RH DSH FE AA AA FE-700 1 4 180 88.9 50 FLG 20 NPT Water Orifice Fluidic Techniques V-2499R1-6 2" 900# Series 300 Local 0-5080 mm wg 0-200" wg 0-4.52 kg/s 0-35874 lb/hr N/A 08003-11.16 08003-1D0013
02 FLOW INDICATING TRANSMITTERSCond PRHTR FW FIT AD AA FIT-001A, FIT-001B 2 8 55 26 N/A N/A 15 NPT Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 2 A 5 2 A 1 A M5 Q4 Remote 0-5080 mm wg 0-200" wg 0-97.62 kg/s 0-774774 lb/hr 4-20mA 08003-11.06 08003-1D0016HP DSH Spray FIT AE AA FIT-300 1 4 180 225 N/A N/A 15 NPT Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 3 A 5 2 A 1 A M5 Q4 Remote 0-5080 mm wg 0-200" wg 0-4.20 kg/s 0-33334 lb/hr 4-20mA 08003-11.06 08003-1D0012HP FW FIT AE AA FIT-100A, FIT-100B 2 8 180 225 N/A N/A 15 NPT Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 3 A 5 2 A 1 A M5 Q4 Remote 0-6350 mm wg 0-250" wg 0-90.0 kg/s 0-714297 lb/hr 4-20mA 08003-11.06 08003-1D0012HP Stm Outlet FIT AA AA FIT-340A, FIT-340B 2 8 579 150 N/A N/A 15 NPT Steam Diff. Press. Transmitter Rosemount 03031-1011 3051CD 3 A 5 2 A 1 A M5 Q4 Remote 0-12700 mm wg 0-500" wg 0-90.0 kg/s 0-714297 lb/hr 4-20mA 08003-11.06 08003-1D0012IP FW FIT AE AA FIT-400A, FIT-400B 2 8 180 88.9 N/A N/A 15 NPT Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 3 A 5 2 A 1 A M5 Q4 Remote 0-6350 mm wg 0-250" wg 0-14.32 kg/s 0-113653 lb/hr 4-20mA 08003-11.06 08003-1D0013IP Stm Outlet FIT AA AA FIT-600A, FIT-600B 2 8 374 31.5 N/A N/A 15 NPT Steam Diff. Press. Transmitter Rosemount 03031-1011 3051CD 2 A 5 2 A 1 A M5 Q4 Remote 0-5080 mm wg 0-200" wg 0-12.86 kg/s 0-102065 lb/hr 4-20mA 08003-11.06 08003-1D0013LP FW FIT AE AA FIT-800A, FIT-800B 2 8 180 40 N/A N/A 15 NPT Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 2 A 5 2 A 1 A M5 Q4 Remote 0-3810 mm wg 0-150" wg 0-11.99 kg/s 0-95160 lb/hr 4-20mA 08003-11.06 08003-1D0014LP Stm Outlet FIT AA AA FIT-915A, FIT-915B 2 8 314 8.5 N/A N/A 15 NPT Steam Diff. Press. Transmitter Rosemount 03031-1011 3051CD 2 A 5 2 A 1 A M5 Q4 Remote 0-1270 mm wg 0-50" wg 0-9.02 kg/s 0-71588 lb/hr 4-20mA 08003-11.06 08003-1D0014RH DSH Spray FIT AE AA FIT-700 1 4 180 88.9 N/A N/A 15 NPT Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 3 A 5 2 A 1 A M5 Q4 Remote 0-5080 mm wg 0-200" wg 0-4.52 kg/s 0-35874 lb/hr 4-20mA 08003-11.06 08003-1D0013
03 PRESSURE INDICATING TRANSMITTERSCond PRHTR FW PIT AD AA PIT-001A, PIT-001B 2 8 55 26 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-26 bar 0-377 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0016Cond PRHTR Outlet PIT AD AA PIT-064A, PIT-064B 2 8 178 26 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-26 bar 0-377 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0016Cond PRHTR Recirc Line Suction PIT AD AA PIT-040 1 4 178 26 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-26 bar 0-377 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0016Deaerator Storage Tank PIT AD AA PIT-001D, PIT-002D 2 * 4 178 8.5 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-10 bar 0-145 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0016HP Drum PIT AE AA PIT-260, PIT-261 2 8 343 150 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 4 A 2B 2 1 A B4 M5 Q4 Remote 0-165 bar 0-2393 psig 0-276 bar -14.7-4000 psig 4-20mA 08003-11.03 08003-1D0012HP DSH PIT AE AA PIT-300 1 4 180 225 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 4 A 2B 2 1 A B4 M5 Q4 Remote 0-225 bar 0-3263 psig 0-276 bar -14.7-4000 psig 4-20mA 08003-11.03 08003-1D0012HP FW PIT AE AA PIT-100A 1 4 180 225 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 4 A 2B 2 1 A B4 M5 Q4 Remote 0-225 bar 0-3263 psig 0-276 bar -14.7-4000 psig 4-20mA 08003-11.03 08003-1D0012HP FW PIT AE AA PIT-100B 1 4 343 165.5 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 4 A 2B 2 1 A B4 M5 Q4 Remote 0-225 bar 0-3263 psig 0-276 bar -14.7-4000 psig 4-20mA 08003-11.03 08003-1D0012HP Stm Outlet PIT AA AA PIT-340A, PIT-340B 2 8 579 150 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 4 A 2B 2 1 A B4 M5 Q4 Remote 0-150 bar 0-2176 psig 0-276 bar -14.7-4000 psig 4-20mA 08003-11.03 08003-1D0012HP Stm Outlet PIT AA AA PIT-342 1 4 579 150 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 4 A 2B 2 1 A B4 M5 Q4 Remote 0-150 bar 0-2176 psig 0-276 bar -14.7-4000 psig 4-20mA 08003-11.03 08003-1D0012IP Drum PIT AE AA PIT-560, PIT-561 2 8 238 31.5 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-35 bar 0-508 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0013IP FW PIT AE AA PIT-400A 1 4 180 88.9 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 4 A 2B 2 1 A B4 M5 Q4 Remote 0-88.9 bar 0-1289 psig 0-276 bar -14.7-4000 psig 4-20mA 08003-11.03 08003-1D0013IP FW PIT AE AA PIT-400B 1 4 238 88.9 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 4 A 2B 2 1 A B4 M5 Q4 Remote 0-88.9 bar 0-1289 psig 0-276 bar -14.7-4000 psig 4-20mA 08003-11.03 08003-1D0013IP Stm Outlet PIT AA AA PIT-600A, PIT-600B 2 8 374 31.5 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-31.5 bar 0-457 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0013LP Drum PIT AE AA PIT-890, PIT-891 2 8 178 8.5 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-10 bar 0-145 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0014LP FW PIT AE AA PIT-800A, PIT-800B 2 8 180 40 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-40 bar 0-580 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0014LP Stm Outlet PIT AA AA PIT-915A, PIT-915B, PIT-915 3 12 314 8.5 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-8.5 bar 0-123 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0014RH DSH PIT AE AA PIT-700 1 4 180 88.9 N/A N/A 15 NPT Water Pressure Transmitter Rosemount 03031-2097 3051T G 4 A 2B 2 1 A B4 M5 Q4 Remote 0-88.9 bar 0-1289 psig 0-276 bar -14.7-4000 psig 4-20mA 08003-11.03 08003-1D0013RH Stm Inlet PIT AA AA PIT-740A, PIT-740B 2 8 374 31.5 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-35 bar 0-508 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0013RH Stm Outlet PIT AA AA PIT-780A, PIT-780B 2 8 578 31.5 N/A N/A 15 NPT Steam Pressure Transmitter Rosemount 03031-2097 3051T G 3 A 2B 2 1 A B4 M5 Q4 Remote 0-31.5 bar 0-457 psig 0-55.2 bar -14.7-800 psig 4-20mA 08003-11.03 08003-1D0013Inlet Duct PIT BA BA PIT-001G, PIT-002G, PIT-003G 3 12 649 20 ""WG (50 mbar) N/A N/A 15 NPT Flue gas Pressure Transmitter Rosemount 03031-1011 3051CG 1 A 5 2 A 1 A B4 L4 M5 Q4 Remote 0-508 mm wg 0-20" wg 0-635 mm wg 0-25" wg 4-20mA 08003-11.03 08003-1D0015Transition Duct PIT BA BA PIT-004G, PIT-005G, PIT-006G 3 12 177 20 ""WG (50 mbar) N/A N/A 15 NPT Flue gas Pressure Transmitter Rosemount 03031-1011 3051CG 1 A 5 2 A 1 A B4 L4 M5 Q4 Remote 0-508 mm wg 0-20" wg 0-635 mm wg 0-25"wg 4-20mA 08003-11.03 08003-1D0015
04 LEVEL TRANSMITTERSBlowdown Tank LT BM BM LT-001B 1 4 148 3.5 N/A N/A 15 NPT Steam/Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 2 A 5 2 A 1 A M5 Q4 Remote 0-1150 mm wg 0 TO -45.28" wg -6350-6350 mm wg -250 to 250" wc/2.5"wc 4-20mA 08003-11.05 08003-1D0017
11 Deaerator Tank LT AD AA LT-001D, LT-002D 2 * 4 178 8.5 N/A N/A 15 NPT Steam/Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 2 A 5 2 A 1 A M5 Q4 Remote 0-4040 mm wg 0 TO -159.1" wg -6350-6350 mm wg -250 to 250" wc/2.5"wc 4-20mA 08003-11.05 08003-1D0016HP Drum LT AE AA LT-200, LT-201, LT-202, LT-203 4 16 343 150 N/A N/A 15 NPT Steam/Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 2 A 5 2 A 1 A M5 Q4 Remote 0-1896 mm wg 0 TO -74.6" wg -6350-6350 mm wg -250 to 250" wc/2.5"wc 4-20mA 08003-11.05 08003-1D0012IP Drum LT AE AA LT-500, LT-501, LT-502, LT-503 4 16 238 31.5 N/A N/A 15 NPT Steam/Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 2 A 5 2 A 1 A M5 Q4 Remote 0-1409 mm wg 0 TO -55.5" wg -6350-6350 mm wg -250 to 250" wc/2.5"wc 4-20mA 08003-11.05 08003-1D0013LP Drum LT AE AA LT-835, LT-836, LT-837, LT-838 4 16 178 8.5 N/A N/A 15 NPT Steam/Water Diff. Press. Transmitter Rosemount 03031-1011 3051CD 2 A 5 2 A 1 A M5 Q4 Remote 0-1471 mm wg 0 TO -57.9" wg -6350-6350 mm wg -250 to 250" wc/2.5"wc 4-20mA 08003-11.05 08003-1D0014
06 THERMOWELLSCond PRHTR FW TW AA AA TW-001, TW-002, TW-003 3 12 178 26 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0016Cond PRHTR FW TW (After Bypass) AA AA TW-004, TW-005, TW-006 3 12 178 26 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0016Cond PRHTR Outlet TW AA AA TW-064, TW-065, TW-066, TW-067 4 16 178 26 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0016Deaerator/Storage Tank TW AA AA TW-001D, TW-002D 2 * 4 178 8.5 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0016HP DSH Inlet TW AA AA TW-320, TW-321 2 8 543 150 40 Welded 15 FNPT Steam Thermowell Alstom E-HRSG-1569 IND-5 Local N/A N/A N/A N/A N/A N/A 08003-1D0012HP DSH Outlet TW AA AA TW-330, TW-331, TW-332 3 12 533 150 40 Welded 15 FNPT Steam Thermowell Alstom E-HRSG-1569 IND-5 Local N/A N/A N/A N/A N/A N/A 08003-1D0012HP Econ Outlet TW AA AA TW-161, TW-162, TW-163 3 12 343 156.9 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0012HP FW TW AA AA TW-100 1 4 180 225 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0012HP FW TW AA AA TW-101, TW-102, TW-103 3 12 343 165.5 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0012HP Stm Outlet TW AA AA TW-113, TW-114, TW-115, TW-116 4 16 579 150 40 Welded 15 FNPT Steam Thermowell Alstom E-HRSG-1569 IND-5 Local N/A N/A N/A N/A N/A N/A 08003-1D0012IP Econ Outlet TW AA AA TW-430, TW-431, TW-432 3 12 238 39.4 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0013IP FW TW AA AA TW-401 1 4 180 88.9 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0013IP FW TW AA AA TW-400, TW-402, TW-403 3 12 238 88.9 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0013IP Stm Outlet TW AA AA TW-600, TW-601, TW-602, TW-603 4 16 374 31.5 40 Welded 15 FNPT Steam Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0013LP FW TW AA AA TW-800, TW-801, TW-802, TW-803 4 16 180 40 40 Welded 15 FNPT Water Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0014LP Stm Outlet TW AA AA TW-915, TW-916, TW-917, TW-918 4 16 314 8.5 40 Welded 15 FNPT Steam Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0014RH DSH Inlet TW AA AA TW-760, TW-761 2 8 497 31.5 40 Welded 15 FNPT Steam Thermowell Alstom E-HRSG-1569 IND-3 Local N/A N/A N/A N/A N/A N/A 08003-1D0013RH DSH Outlet TW AA AA TW-765, TW-766, TW-767 3 12 497 31.5 40 Welded 15 FNPT Steam Thermowell Alstom E-HRSG-1569 IND-3 Local N/A N/A N/A N/A N/A N/A 08003-1D0013RH Stm Inlet TW AA AA TW-740, TW-741, TW-742, TW-743 4 16 374 31.5 40 Welded 15 FNPT Steam Thermowell Alstom E-HRSG-1569 IND-1 Local N/A N/A N/A N/A N/A N/A 08003-1D0013RH Stm Outlet TW AA AA TW-780, TW-781, TW-782, TW-783 4 16 578 31.5 40 Welded 15 FNPT Steam Thermowell Alstom E-HRSG-1569 IND-3 Local N/A N/A N/A N/A N/A N/A 08003-1D0013Module 2 TW BA BA TW-004G, TW-005G, TW-006G 3 12 475 20 ""WG (50 mbar) 50 150# RF 15 FNPT Flue Gas Thermowell Temp-pro 92 92 Local N/A N/A N/A N/A N/A N/A 08003-1D0015Module 3 TW BA BA TW-007G, TW-008G, TW-009G 3 12 356 20 ""WG (50 mbar) 50 150# RF 15 FNPT Flue Gas Thermowell Temp-pro 92 92 Local N/A N/A N/A N/A N/A N/A 08003-1D0015Module 4 TW BA BA TW-010G, TW-011G, TW-012G 3 12 260 20 ""WG (50 mbar) 50 150# RF 15 FNPT Flue Gas Thermowell Temp-pro 92 92 Local N/A N/A N/A N/A N/A N/A 08003-1D0015Inlet Duct TW BA BA TW-001G, TW-002G, TW-003G 3 12 649 20 ""WG (50 mbar) 50 150# RF 15 FNPT Flue gas Thermowell Temp-pro 92 92 Local N/A N/A N/A N/A N/A N/A 08003-1D0015Stack TW BA BA TW-016G, TW-017G, TW-018G 3 12 177 20 ""WG (50 mbar) 50 150# RF 15 FNPT Flue gas Thermowell Temp-pro 92 92 Local N/A N/A N/A N/A N/A N/A 08003-1D0015Transition Duct TW BA BA TW-013G, TW-014G, TW-015G 3 12 177 20 ""WG (50 mbar) 50 150# RF 15 FNPT Flue gas Thermowell Temp-pro 92 92 Local N/A N/A N/A N/A N/A N/A 08003-1D0015Blowdown Tank Outlet TW BM BM TW-001B, TW-003B (By Sterling) 2 8 150 3.5 20 Welded 15 FNPT Steam Thermowell Sterling N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0017
07 PRESSURE TEST PORTSCond PRHTR FW PP AA AA PP-001 1 4 55 26 N/A N/A 15 NPT Water Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0016Cond PRHTR Outlet PP AA AA PP-064 1 4 178 26 N/A N/A 15 NPT Water Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0016Cond PRHTR Recirc Line PP AA AA PP-040 1 4 178 26 N/A N/A 15 NPT Water Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0016HP Drum PP AA AA PP-260 1 4 343 150 N/A N/A 15 NPT Steam Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0012HP Econ Outlet PP AA AA PP-160 1 4 343 156.9 N/A N/A 15 NPT Water Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0012HP FW PP AA AA PP-100 1 4 343 165.5 N/A N/A 15 NPT Water Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0012HP Stm Outlet PP AA AA PP-340 1 4 579 150 N/A N/A 15 NPT Steam Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0012IP Drum PP AA AA PP-560 1 4 238 31.5 N/A N/A 15 NPT Steam Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0013IP Econ Outlet PP AA AA PP-430 1 4 238 39.4 N/A N/A 15 NPT Water Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0013IP FW PP AA AA PP-400 1 4 238 88.9 N/A N/A 15 NPT Water Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0013IP Stm Outlet PP AA AA PP-600 1 4 374 31.5 N/A N/A 15 NPT Steam Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0013LP Drum PP AA AA PP-890 1 4 178 8.5 N/A N/A 15 NPT Steam Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0014LP FW PP AA AA PP-800 1 4 180 40 N/A N/A 15 NPT Water Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0014LP Stm Outlet PP AA AA PP-915 1 4 314 8.5 N/A N/A 15 NPT Steam Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0014RH Stm Inlet PP AA AA PP-740 1 4 374 31.5 N/A N/A 15 NPT Steam Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0013RH Stm Outlet PP AA AA PP-780 1 4 578 31.5 N/A N/A 15 NPT Steam Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0013
08 TEMPERATURE INDICATORSCond PRHTR FW TI AA AA TI-001 1 4 178 26 N/A N/A 15 NPT Water Temperature Indicator Winters G-Bimet T52120B33-S-TAG Local N/A N/A 0 - 200°C 0 - 392°F N/A 08003-11.07 08003-1D0016Cond PRHTR FW TI (After Bypass) AA AA TI-004 1 4 178 26 N/A N/A 15 NPT Water Temperature Indicator Winters G-Bimet T52120B33-S-TAG Local N/A N/A 0 - 200°C 0 - 392°F N/A 08003-11.07 08003-1D0016Cond PRHTR Outlet TI AA AA TI-065 1 4 178 26 N/A N/A 15 NPT Water Temperature Indicator Winters G-Bimet T52120B33-S-TAG Local N/A N/A 0 - 200°C 0 - 392°F N/A 08003-11.07 08003-1D0016HP Econ Outlet TI AA AA TI-162 1 4 343 156.9 N/A N/A 15 NPT Water Temperature Indicator Winters G-Bimet T52120B35-S-TAG Local N/A N/A 0 - 450°C 0 - 842°F N/A 08003-11.07 08003-1D0012HP FW TI AA AA TI-100 1 4 343 165.5 N/A N/A 15 NPT Water Temperature Indicator Winters G-Bimet T52120B35-S-TAG Local N/A N/A 0 - 450°C 0 - 842°F N/A 08003-11.07 08003-1D0012HP Stm Outlet TI AA AA TI-116 1 4 579 150 N/A N/A 15 NPT Steam Temperature Indicator Winters F-Gas Therm R24452002S-C-TAG Local N/A N/A 100 - 650°C 212 - 1202°F N/A 08003-11.07 08003-1D0012IP Econ Outlet TI AA AA TI-432 1 4 238 39.4 N/A N/A 15 NPT Water Temperature Indicator Winters G-Bimet T52120B34-S-TAG Local N/A N/A 0 - 300°C 0 - 572°F N/A 08003-11.07 08003-1D0013IP FW TI AA AA TI-403 1 4 238 88.9 N/A N/A 15 NPT Water Temperature Indicator Winters G-Bimet T52120B34-S-TAG Local N/A N/A 0 - 300°C 0 - 572°F N/A 08003-11.07 08003-1D0013IP Stm Outlet TI AA AA TI-603 1 4 374 31.5 N/A N/A 15 NPT Steam Temperature Indicator Winters G-Bimet T52120B35-S-TAG Local N/A N/A 0 - 450°C 0 - 842°F N/A 08003-11.07 08003-1D0013LP FW TI AA AA TI-800 1 4 180 40 N/A N/A 15 NPT Water Temperature Indicator Winters G-Bimet T52120B33-S-TAG Local N/A N/A 0 - 200°C 0 - 392°F N/A 08003-11.07 08003-1D0014LP Stm Outlet TI AA AA TI-918 1 4 314 8.5 N/A N/A 15 NPT Steam Temperature Indicator Winters G-Bimet T52120B35-S-TAG Local N/A N/A 0 - 450°C 0 - 842°F N/A 08003-11.07 08003-1D0014RH Stm Inlet TI AA AA TI-741 1 4 374 31.5 N/A N/A 15 NPT Steam Temperature Indicator Winters G-Bimet T52120B35-S-TAG Local N/A N/A 0 - 450°C 0 - 842°F N/A 08003-11.07 08003-1D0013RH Stm Outlet TI AA AA TI-783 1 4 578 31.5 N/A N/A 15 NPT Steam Temperature Indicator Winters F-Gas Therm R24452002S-C-TAG Local N/A N/A 100 - 650°C 212 - 1202°F N/A 08003-11.07 08003-1D0013Blowdown Tank Outlet TI BM BM TI-003B (By Sterling) 1 4 150 3.5 N/A N/A 15 NPT Water Temperature Indicator ASHCROFT N/A 50EI60R060 Local 0° - 150° C 0° - 302° F 10 - 150°C 50 - 302°F N/A N/A 08003-1D0017Deaerator Storage Tank TI AA AA TI-001D, TI-002D (By Sterling) 2 * 4 178 8.5 N/A N/A 15 NPT Water Temperature Indicator ASHCROFT N/A 50EI60R090 Local 0° - 300° C 0° - 572° F 0° - 300° C 0° - 572° F N/A N/A 08003-1D0016
ALSTOM POWER Inc.Project Name: Nubaria Power Station I & IIContract No.: 66008003
INSTRUMENT LIST Item No.: 11.01Rev. No.: 11
Date: 06/29/05Doc. Type: E
RevCate Desc
OwnerSystem
AlstomSystem Tag Number Qty Qty DesignT DesignP
Process Conn Process Instrument Instrument Service Instrument Type Vendor/Manuf Manuf Drawing Model Number Local/ Calibrated Range Calibrated Range Process Range Process Range
Electrical Range Datasheet/Ref Number P&ID Drawing
gory
Locator Code
Locator Code
Total for contract (°C) (barg) (mm) End Conn Conn (mm) End Conn Description Remote SI (See Note 2)
English Units (See Note 2) SI English Units
09 PRESSURE INDICATORSCond PRHTR Inlet PI AA AA PI-001 1 4 55 26 N/A N/A 15 NPT Water Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 70 Bar Local 0-70 bar N/A 0-70 bar N/A N/A 08003-11.03 08003-1D0016Cond PRHTR Outlet PI AA AA PI-064 1 4 178 26 N/A N/A 15 NPT Water Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 70 Bar + 50 1098SD Local 0-70 bar N/A 0-70 bar N/A N/A 08003-11.03 08003-1D0016
Cond PRHTR Recirc Line Discharge PI AA AA PI-040 1 4 178 33.5 N/A N/A 15 NPT Water Pressure Indicator ASHCROFT 70A91745 1279SSL 04L XNHSG 70 Bar + 50 1098SD + 50
1106S Local 0-70 bar N/A 0-70 bar N/A N/A 08003-11.03 08003-1D0016Deaerator Storage Tank PI AA AA PI-001D 1 * 2 178 8.5 N/A N/A 15 NPT Water Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 14 Bar +501098S Local 0-14 bar N/A 0-14 bar N/A N/A 08003-11.03 08003-1D0016HP FW PI AA AA PI-100 1 4 343 165.5 N/A N/A 15 NPT Water Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 250 Bar Local 0-250 bar N/A 0-250 bar N/A N/A 08003-11.03 08003-1D0012HP DSH PI AA AA PI-300 1 4 180 150 N/A N/A 15 NPT Water Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 250 Bar Local 0-250 bar N/A 0-250 bar N/A N/A 08003-11.03 08003-1D0012HP Stm Outlet PI AA AA PI-340 1 4 579 150 N/A N/A 15 NPT Steam Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 250 Bar +501098ND Local 0-250 bar N/A 0-250 bar N/A N/A 08003-11.03 08003-1D0012IP FW PI AA AA PI-400 1 4 238 88.9 N/A N/A 15 NPT Water Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 250 Bar Local 0-250 bar N/A 0-250 bar N/A N/A 08003-11.03 08003-1D0013RH DSH PI AA AA PI-700 1 4 180 31.5 N/A N/A 15 NPT Water Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 250 Bar Local 0-250 bar N/A 0-250 bar N/A N/A 08003-11.03 08003-1D0013IP Stm Outlet PI AA AA PI-600 1 4 374 31.5 N/A N/A 15 NPT Steam Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 70 Bar +501098ND Local 0-70 bar N/A 0-70 bar N/A N/A 08003-11.03 08003-1D0013LP FW PI AA AA PI-800 1 4 180 40 N/A N/A 15 NPT Water Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 70 Bar Local 0-70 bar N/A 0-70 bar N/A N/A 08003-11.03 08003-1D0014LP Stm Outlet PI AA AA PI-915 1 4 314 8.5 N/A N/A 15 NPT Steam Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 14 Bar +501098S Local 0-14 bar N/A 0-14 bar N/A N/A 08003-11.03 08003-1D0014RH Stm Inlet PI AA AA PI-740 1 4 374 31.5 N/A N/A 15 NPT Steam Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 70 Bar +501098ND Local 0-70 bar N/A 0-70 bar N/A N/A 08003-11.03 08003-1D0013RH Stm Outlet PI AA AA PI-780 1 4 578 31.5 N/A N/A 15 NPT Steam Pressure Indicator ASHCROFT 70A917 45 1279SSL 04L XNHSG 70 Bar +501098ND Local 0-70 bar N/A 0-70 bar N/A N/A 08003-11.03 08003-1D0013
09 DRUM PRESSURE INDICATORSHP Drum PI at drum AA AA PI-260 1 4 343 150 N/A N/A 15 NPT Steam Pressure Indicator WINTERS Winters Dwg. # M, C025 P6520-1-R11-SG-SFC-SM-TAG-SYS Local 0-250 bar N/A 0-250 bar N/A N/A 08003-11.03 08003-1D0012HP Drum PI at grade AA AA PI-261 1 4 343 150 N/A N/A 15 NPT Steam Pressure Indicator WINTERS Winters Dwg. # M, C025 P6520-1-R11-SG-SFC-SM-TAG-SYS Local 0-250 bar N/A 0-250 bar N/A N/A 08003-11.03 08003-1D0012IP Drum PI at drum AA AA PI-560 1 4 238 31.5 N/A N/A 15 NPT Steam Pressure Indicator WINTERS Winters Dwg. # L, C025 P6517-SG-R11-SFC-SM-TAG-SYS Local 0-70 bar N/A 0-70 bar N/A N/A 08003-11.03 08003-1D0013IP Drum PI at grade AA AA PI-561 1 4 238 31.5 N/A N/A 15 NPT Steam Pressure Indicator WINTERS Winters Dwg. # L, C025 P6517-SG-R11-SFC-SM-TAG-SYS Local 0-70 bar N/A 0-70 bar N/A N/A 08003-11.03 08003-1D0013LP Drum PI at drum AA AA PI-890 1 4 178 8.5 N/A N/A 15 NPT Steam Pressure Indicator WINTERS Winters Dwg. # K, C025 P6513-SG-R11-SFC-SM-TAG-SYS Local 0-14 bar N/A 0-14 bar N/A N/A 08003-11.03 08003-1D0014LP Drum PI at grade AA AA PI-891 1 4 178 8.5 N/A N/A 15 NPT Steam Pressure Indicator WINTERS Winters Dwg. # K, C025 P6513-SG-R11-SFC-SM-TAG-SYS Local 0-14 bar N/A 0-14 bar N/A N/A 08003-11.03 08003-1D0014
09 DIFFERENTIAL PRESSURE INDICATING SWITCHESCond PRHTR Recirc Line DPIS AD AA DPIS-040 1 4 178 26 N/A N/A 15 NPT Water Diff. Pressure Indicator ROSEMOUNT TBD PCS45S4BB.7B7P-TAG Local 0 - 0.7 bar N/A 0 - 0.7 bar N/A N/A 08003-11.03 08003-1D0016HP DSH Spray DPIS AE AA DPIS-300 1 4 180 225 N/A N/A 15 NPT Steam Diff. Pressure Indicator ROSEMOUNT TBD PCS45S4BB.7B7P-TAG Local 0 - 0.7 bar N/A 0 - 0.7 bar N/A N/A 08003-11.03 08003-1D0012RH DSH Spray DPIS AE AA DPIS-700 1 4 180 88.9 N/A N/A 15 NPT Water Diff. Pressure Indicator ROSEMOUNT TBD PCS45S4BB1B7P-TAG Local 0 - 1 bar N/A 0 - 1 bar N/A N/A 08003-11.03 08003-1D0013BD Tank After Cooling System DPIS BM BM DPIS-001B 1 4 150 3.5 N/A N/A 15 NPT Water Diff. Pressure Indicator ROSEMOUNT TBD PCS45S4BB.7B7P-TAG Local 0 - 0.7 bar N/A 0 - 0.7 bar N/A N/A 08003-11.03 08003-1D0017
ALSTOM POWER Inc.Project Name: Nubaria Power Station I & IIContract No.: 66008003
INSTRUMENT LIST Item No.: 11.01Rev. No.: 11
Date: 06/29/05Doc. Type: E
RevCate Desc
OwnerSystem
AlstomSystem Tag Number Qty Qty DesignT DesignP
Process Conn Process Instrument Instrument Service Instrument Type Vendor/Manuf Manuf Drawing Model Number Local/ Calibrated Range Calibrated Range Process Range Process Range
Electrical Range Datasheet/Ref Number P&ID Drawing
gory
Locator Code
Locator Code
Total for contract (°C) (barg) (mm) End Conn Conn (mm) End Conn Description Remote SI (See Note 2)
English Units (See Note 2) SI English Units
16 INSTRUMENT MANIFOLDSBlowdown Tank LT Manifold BM BM V-004B 1 4 150 3.5 15 NPT 15 NPT Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0017Blowdown Tank After Cooling System DPIS BM BM V-014B 1 4 150 3.5 15 NPT 15 NPT Water 3-Valve Manifold Anderson Greenwood M1 3-Valve Manifold M1VIS-4 Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0017Cond PRHTR FIT Manifold AA AA V-003, V-033 2 8 55 26 15 NPT 15 NPT Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016Cond PRHTR FW PI Manifold AA AA V-012 1 4 55 26 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016Cond PRHTR FW PIT Manifold AA AA V-015, V-018 2 8 55 26 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016Cond PRHTR Outlet PI Manifold AA AA V-068 1 4 178 26 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016Cond PRHTR Outlet PIT Manifold AA AA V-071, V-074 2 8 178 26 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016Cond PRHTR Recirc Line DPIS Manifold AA AA V-044 1 4 178 26 15 NPT 15 NPT Water 3-Valve Manifold Anderson Greenwood M1 3-Valve Manifold M1VIS-4 Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016Deaerator Storage Tank PI Manifold AA AA V-027D 1 * 2 178 8.5 15 NPT 15 NPT Steam/Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016Deaerator Storage Tank PIT Manifold AA AA V-024D, V-021D 2 * 4 178 8.5 15 NPT 15 NPT Steam/Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016Deaerator Tank LT Manifold AA AA V-044D, V-059D 2 * 4 178 8.5 15 NPT 15 NPT Steam/Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016HP Drum LT Manifold AA AA V-210, V-225, V-232, V-247 4 16 343 150 15 NPT 15 NPT Steam/Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP Drum PI Manifold AA AA V-270, V-279 2 8 343 150 15 NPT 15 NPT Steam/Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP Drum PIT Manifold AA AA V-273, V-276 2 8 343 150 15 NPT 15 NPT Steam/Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP DSH FIT Manifold AA AA V-302 2 8 180 225 15 NPT 15 NPT Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP DSH DPIS Manifold AA AA V-323 1 4 180 225 15 NPT 15 NPT Water 3-Valve Manifold Anderson Greenwood M1 3-Valve Manifold M1VIS-4 Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP DSH PIT Manifold AA AA V-307 1 4 180 225 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP DSH PI Manifold AA AA V-332 1 4 180 225 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP FW FIT Manifold AA AA V-104, V-132 2 8 180 225 15 NPT 15 NPT Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP FW PI Manifold AA AA V-117 1 4 343 165.5 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP FW PIT Manifold AA AA V-120 1 4 180 225 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP FW PIT Manifold AA AA V-123 1 4 343 165.5 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP Stm Outlet FIT Manifold AA AA V-363, V-368 2 8 579 150 15 NPT 15 NPT Steam 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP Stm Outlet PI Manifold AA AA V-350 1 4 579 150 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012HP Stm Outlet PIT Manifold AA AA V-344, V-347, V-369 3 12 579 150 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0012IP Drum LT Manifold AA AA V-510, V-532, V-547, V-V-525 4 16 238 31.5 15 NPT 15 NPT Steam/Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013IP Drum PI Manifold AA AA V-570, V-579 2 8 238 31.5 15 NPT 15 NPT Steam/Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013IP Drum PIT Manifold AA AA V-573, V-576 2 8 238 31.5 15 NPT 15 NPT Steam/Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013IP FW FIT Manifold AA AA V-413, V-423 2 8 180 88.9 15 NPT 15 NPT Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013IP FW PI Manifold AA AA V-402 1 4 180 88.9 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013IP FW PIT Manifold AA AA V-405 1 4 180 88.9 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013IP FW PIT Manifold AA AA V-408 1 4 238 88.9 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013IP Stm Outlet FIT Manifold AA AA V-627, V-632 2 8 374 31.5 15 NPT 15 NPT Steam 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013IP Stm Outlet PI Manifold AA AA V-620 1 4 374 31.5 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013IP Stm Outlet PIT Manifold AA AA V-614, V-617 2 8 374 31.5 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013Cond Recirc Pump Discharge PI Manifold AA AA V-056 1 4 178 33.5 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016Cond. Recirc Pump Suction PIT Manifold AA AA V-052 1 4 178 26 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0016LP Drum LT Manifold AA AA V-845, V-860, V-867, V-882 4 16 178 8.5 15 NPT 15 NPT Steam/Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0014LP Drum PI Manifold AA AA V-895, V-912 2 8 178 8.5 15 NPT 15 NPT Steam/Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0014LP Drum PIT Manifold AA AA V-898, V-901 2 8 178 8.5 15 NPT 15 NPT Steam/Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0014LP FW FIT Manifold AA AA V-813, V-832 2 8 180 40 15 NPT 15 NPT Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0014LP FW PI Manifold AA AA V-802 1 4 180 40 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0014LP FW PIT Manifold AA AA V-805, V-808 2 8 180 40 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0014LP Stm Outlet FIT Manifold AA AA V-938, V-943 2 8 314 8.5 15 NPT 15 NPT Steam 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0014LP Stm Outlet PI Manifold AA AA V-927 1 4 314 8.5 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0014LP Stm Outlet PIT Manifold AA AA V-930, V-933, V-950 3 12 314 8.5 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0014RH DSH Spray FIT Manifold AA AA V-702, V-734 2 8 180 88.9 15 NPT 15 NPT Water 5-Valve Manifold Anderson Greenwood MC 5-Valve Manifold MC5PHPS-4-XP-AM-R3V Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013RH DSH Spray DPIS Manifold AA AA V-721 1 4 180 88.9 15 NPT 15 NPT Water 3-Valve Manifold Anderson Greenwood M1 3-Valve Manifold M1VIS-4 Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013RH DSH Spray PIT Manifold AA AA V-707 1 4 180 88.9 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013RH DSH Spray PIT Manifold AA AA V-710 1 4 180 31.5 15 NPT 15 NPT Water 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013RH Stm Inlet PI Manifold AA AA V-744 1 4 374 31.5 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013RH Stm Inlet PIT Manifold AA AA V-747, V-750 2 8 374 31.5 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013RH Stm Outlet PI Manifold AA AA V-795 1 4 578 31.5 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013RH Stm Outlet PIT Manifold AA AA V-789, V-792 2 8 578 31.5 15 NPT 15 NPT Steam 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0013Inlet Duct PIT Manifold BA BA V-001G, V-002G, V-003G 3 12 649 20 ""WG (50 mbar) 15 NPT 15 NPT Flue gas 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0015Transition Duct PIT Manifold BA BA V-004G, V-005G, V-006G 3 12 177 20 ""WG (50 mbar) 15 NPT 15 NPT Flue gas 2-Valve Manifold Anderson Greenwood M25 Block & Bleed M25HPS-44F-XP Local N/A N/A N/A N/A N/A 08003-11.04 08003-1D0015
17 GAS TEST PORTSCEMS TP BA BA TP-047G, TP-048G, TP-049G, TP-050G 4 16 177 20 ""WG (50 mbar) 100 FLG N/A N/A Flue gas Test Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0015EPA TP BA BA TP-051G, TP-052G, TP-053G, TP-054G 4 16 177 20 ""WG (50 mbar) 150 FLG N/A N/A Flue gas Test Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0015
Inlet Duct Flow Measuring TP BA BATP-001G, TP-002G, TP-003G, TP-004G, TP-005G 5 20 649 20 ""WG (50 mbar) 50 FLG N/A N/A Flue gas Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0015
Inlet Duct Flow Measuring/NOx & O2 Monitoring TP BA BA
Inlet Duct PT Conn BA BATP-011G, TP-012G, TP-013G, TP-014G, TP-015G, TP-016G 6 24 649 20 ""WG (50 mbar) 25 NPT N/A N/A Flue gas Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0015
Module 2 TP BA BATP-017G, TP-018G, TP-019G, TP-020G, TP-021G, TP-022G 6 24 475 20 ""WG (50 mbar) 50 FLG N/A N/A Flue gas Test Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0015
Module 3 TP BA BATP-023G, TP-024G, TP-025G, TP-026G, TP-027G, TP-028G 6 24 356 20 ""WG (50 mbar) 50 FLG N/A N/A Flue gas Test Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0015
Module 4 TP BA BATP-029G, TP-030G, TP-031G, TP-032G, TP-033G, TP-034G 6 24 260 20 ""WG (50 mbar) 50 FLG N/A N/A Flue gas Test Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0015
Transition Duct PT Conn BA BATP-041G, TP-042G, TP-043G, TP-044G, TP-045G, TP-046G 6 24 177 20 ""WG (50 mbar) 25 NPT N/A N/A Flue gas Pressure Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0015
Transition Duct TP BA BATP-035G, TP-036G, TP-037G, TP-038G, TP-039G, TP-040G 6 24 177 20 ""WG (50 mbar) 50 FLG N/A N/A Flue gas Test Port Alstom N/A N/A Local N/A N/A N/A N/A N/A N/A 08003-1D0015
18 PUMPSCond PRHTR Recirc Line Pump AA AA PMP-040 1 4 178 26 / 33.5 150x80 FLG N/A N/A Water Pump ITT DG04021 3700 3x6-9 SX Remote N/A N/A 33.23 barg 481.8 psig N/A 08003-11.17 08003-1D0016
11 19 DEAERATOR STORAGE TANK LEVEL SWITCHESDA Storage Tank High, High, High Level Switch AA AA LS-001, LS-002, LS-003, LS-004(By Sterling) 4* 8 178 8.5 15 NPT N/A N/A Water Level Switch Dwyer 5729-BOM F7-HSS Remote N/A N/A N/A N/A N/A N/A 08003-1D0016DA Storage Tank High, High Level Switch AA AA LS-005, LS-006, LS-007, LS-008 (By Sterling) 4* 8 178 8.5 15 NPT N/A N/A Water Level Switch Dwyer 5729-BOM F7-HSS Remote N/A N/A N/A N/A N/A N/A 08003-1D0016
Notes:1 Quantities shown are for One (1) unit. There are Four (4) units on this contract. Except for the quantities shown with "*" are for Two (2) units only.
For the complete tagging, prefix the tag number with the following:For Four (4) units.: For Two For Two (2) units with "*":Unit1A-System Locator Code Unit 1 Unit 1 1X-System Locator CodeUnit1B-System Locator Code Unit 2 Unit 2 2X-System Locator CodeUnit2A-System Locator Code Unit2B-System Locator Code Tagging example as follows for Four (4) units.: Tagging Tagging example with "*" as follows for Two (2) units.:Unit1A-AA-PI-001 Unit 1 Unit 1 1X-AA-PI-001DUnit1B-AA-PI-001 Unit 2 Unit 2 2X-AA-PI-001DUnit2A-AA-PI-001 Unit2B-AA-PI-001
2 Calibrated ranges with "Metric Units" shall be used.3 All pressure indicators in steam service shall be provided with siphons.4 All dimensions are referenced to drum and blow down tank centerline.
ALSTOM POWER Inc.Project Name: Nubaria Power Station I & IIContract No.: 66008003
INSTRUMENT LIST Item No.: 11.01Rev. No.: 11
Date: 06/29/05Doc. Type: E
RevCate Desc
OwnerSystem
AlstomSystem Tag Number Qty Qty DesignT DesignP
Process Conn Process Instrument Instrument Service Instrument Type Vendor/Manuf Manuf Drawing Model Number Local/ Calibrated Range Calibrated Range Process Range Process Range
Electrical Range Datasheet/Ref Number P&ID Drawing
gory
Locator Code
Locator Code
Total for contract (°C) (barg) (mm) End Conn Conn (mm) End Conn Description Remote SI (See Note 2)
English Units (See Note 2) SI English Units
Rev. Date Rev Log0 01/15/04 Initial Release of Valve List1 C1 02/27/04 Revised per new pegging steam line configuration2 C1 3/18/2004 Revised per customer tagging system (no four digit tags)
Removed FT-040, added FT-002, FT-101, FT-401 and FT-801.Revised design pressure and design temperature.Added PI-001, DPI-300, SNOZ-700, MS-781 and V-323.
3 C2 4/27/2004 Added PT, LT, FT, Silencer, cond pot, FE, PI, LI, RWLI, and TE information.4 C2 5/3/2004 Added note 1 and column for total quantities.5 C1 5/7/2004 Added additional instrument information colums per customer comments6 C2 6/18/04 Revised per customer comments, revised instrument tagging.7 C2 6/30/2004 Revised Thermocouple model numbers for the gas side and Level Transmitter calibration ranges.8 C2 9/3/2004 Added TMTs for HPSH2. Added PI for each drum. Added desup outlet thermocouples. Revised design pressures per information from customer.
Added SH & RH 2nd D/SH TE, corrected Condensate TE labels and location. Revised vendor information.Revised PT/FT labels to PIT/FIT. Pressure/Flow transmitter descriptions were also modified to incorporate "indicating".
9 C2 10/25/04 Changed "CPH Recirc pump min recirc RO" tag number to RO-042.Revised manuf drawing numbers for FT, PT, PI, LTs and drum sampling nozzles. Added vendor information for Drum PIs.Added V-369.Revised calibrated ranges and process ranges for BD tank LT and Fes.Revised set points for LI, LTs and RWLIs.Added silencer process connection sizes.
10 C2 02/18/05 Revised HP Level transmitter calibrated range. Revised test port connection sizes for inlet duct and transition duct.Revised 5-valve manifold for diff press gages.Added manufacturing information on diff press gages.Added LP stm PIT and TE. Added Owner system locator code.
11 C2 6/29/2005 Added DA Storage Tank Level Switches.
NOTES:1. ALL TEST PORTS (TP) ARE 2" WITHTHREADED CAP UNLESS OTHERWISE NOTED.2. TEST PORTS WITH SUFFIXES A-C ARE TOBE LOCATED ON THE EAST SIDE OF THEHRSG WHILE TPs WITH SUFFIXES D-F ARE TOBE LOCATED ON THE WEST SIDE OF THEHRSG. UNLESS OTHERWISE SHOWN ORNOTED.3. FOR COMPLETE TAG NUMBER OF ANYCOMPONENT PREFIX TAG NUMBERS WITHTHE FOLLOWING:MODULE 1, UNIT 1 = 1A BAMODULE 1, UNIT 2 = 1B BAMODULE 2, UNIT 1 = 2A BAMODULE 2, UNIT 2 = 2B BA4. SEE HIGH PRESSURE P&ID (08003-1D0012)FOR LEGEND.
