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Basic ccpp overview Power plant

The document provides an overview and course outline for a training on combined cycle power plants. It discusses the key components of a heat recovery steam generator (HRSG) system including the low pressure, intermediate pressure and high pressure systems. It explains the Brayton and Rankine cycles used in combined cycle plants and how they improve overall efficiency compared to simple cycle plants. Key parameters and operational considerations for the low pressure system are also reviewed.

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Ras Laffan CCCP Introduction Manual
HRSG
Course Outline • Combined Cycle Theory Review • HRSG Steam Cycles & Flow Diagrams • HRSG Construction • HRSG Operational Considerations • SCR Introduction • SCR Operational Overview • HRSG/SCR Failure – Cause & Prevention
Combined Cycle Theory Review
What is a “Combined Cycle” Power Plant? A combined cycle system uses the same heat energy to generate power from two different thermodynamic cycles. The advantage of this arrangement is the overall efficiency of the plant unit – electrical energy out compared with heat energy in – is greatly improved over either the simple gas turbine cycle or simple steam turbine cycle.
This plant uses two distinctly different thermodynamic cycles to perform useful work (generate electricity). • The Brayton (Gas Turbine) Cycle • The Rankine (Steam Plant) Cycle
The Brayton Cycle
The Brayton Cycle In the Brayton Cycle (a.k.a. Constant Pressure Cycle), combustion and exhaust take place at a constant pressure.
The Brayton Cycle Can You Explain This Diagram?
The Brayton Cycle
Brayton Cycle Efficiency • Brayton Cycle thermal efficiency is measured using compressor ratio. • Compressor ratio is the ratio that exists between the maximum and minimum pressures in the cycle – pressure of the air entering the compressor vs. the hot gas leaving the turbine.
• It is best expressed as; ηth = 1 - rp (1-k)/k Where; rp = compressor ratio and k = the value of the ratio of the specific heats of the working fluid. The average simple cycle gas turbine cycle is 38% - 45% efficient Brayton Cycle Efficiency
The Rankine Cycle
P3 P1 Turbine FP HRSG Condenser Temperature Entropy (S) 1 2 3 P2 4 5 6 7 8 Can you explain the shape of this cycle? The Rankine Cycle
P3 P1 Turbine FP HRSG Condenser Temperature Entropy (S) 1 2 3 P2 4 5 6 7 8 The Rankine Cycle
Rankine Cycle Efficiency • The Rankine Cycle stated simply, is ∆E = Q - W. • The total change in energy entering or leaving the system equals the heat added to the system less the work performed by the system.
• It is best expressed as; ηth = (wout - win ) / qin Where; wout = work done by the system, win = work done on the system; and qin = specific heat added Rankine Cycle Efficiency • The average normal Rankine Cycle is about 27% - 35% efficient.
The Combined Cycle
Combined Cycle Efficiency • When two power cycles, each with their own thermal efficiencies, are employed in a single power unit, the resulting efficiency is dependant upon each of the two cycles. • In our particular application the Brayton Cycle and Rankine Cycle operate in series. • Because of this any problems with the efficiency of the Brayton Cycle will have a direct effect on the efficiency of the Rankine Cycle and thereby affect the overall plant efficiency.
• Thermal efficiency can be calculated as; ηth = ηA + ηB - ηA ηB . • With Cycle A representing the Brayton Cycle and Cycle B representing the Rankine Cycle. Combined Cycle Efficiency • It is a result of this gain in efficiency that the combined cycle power plant is now being widely implemented over more traditional power generating stations.
So, What are the advantages? • Short Project Schedules ~ 24 Months • High Thermal Efficiency ~ 50% • Low Environmental Emmissions • High Operating Flexibility • High Availability ~ 90%
HRSG Steam Cycles & Flow Diagrams
Functional Description The HRSG uses waste heat contained in the exhaust of a gas turbine to convert water to steam. The steam is then used to power a steam turbine and/or supply auxiliary plant processes.
HRSG Recover Thermal Energy From Turbine Exhaust Gas. Transfer Heat Into Feed Water Generate LP, IP and HP Steam Gas Turbine Exhaust Auxiliary Burners (Optional) Boiler Feedwater Utility Steam (Optional) LP, IP and HP Steam Exhaust Gas
The most common HRSG is a horizontal, three pressure, natural circulation system with reheat and superheat. SCR units are commonly added for emissions reduction. 3 Steam Cycles, one HRSG SCR BOX
SCR BOX The complete HRSG system is made up of three separate subsystems (LP, IP, and HP); each with its own steam drum and all required support equipment. 3 Steam Cycles, one HRSG HPIPLP
The three pressure system has the advantage of providing each stage of the steam turbine with the steam pressure and flow most efficient for the turbine blade speed. 3 Steam Cycles, one HRSG SCR BOX
LP System Overview LP Steam Drum & De-aerator LPEcon1&2 LPEvap LPSuperhtr The LP System consists of a LP Steam Drum and De-aerator, two LP economizers mounted in series, an LP evaporator, an LP superheater, and all required piping and valves. LP Superhtr Feedwater Pump Recirc Feedwater Condensate LP SteamFrom LP Steam Drum
IP System Overview IPSuperhtr The IP system comprises the IP Steam Drum, the IP economizer, the IP evaporator, the IP superheater and all required piping and valves. IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum IP Steam Drum IPEcon IPEvap
IPEcon IP System Overview IPSuperhtr Steam from the IP superheater ties into the Cold Reheat line and then passes through two reheaters before leaving as Hot Reheat steam. IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum IP Steam DrumIPEvap Reheat2 Cold Reheat Hot Reheat IP Feedwater A Reheat1
IP System Overview Hot reheat steam temperature is controlled by an attemperator located between the two reheaters. IP feedwater supplies the cooling spray used in the attemperator. Reheat2 Cold Reheat Hot Reheat IP Feedwater A Reheat1
HP Steam Drum HP Feedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 The HP system includes the HP Steam Drum, 4 HP economizers mounted in series, 2 HP evaporators mounted in series, 5 HP superheaters also mounted in series, and all required piping and valves. HP System Overview
HP Steam Drum HP Feedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 HP steam temperature is controlled by an attemperator mounted between the HP superheaters. The attemperator uses HP feedwater as the cooling medium. HP System Overview A HP Feedwater
Component Locations All economizers, evaporators, superheaters, and reheaters are mounted within the HRSG while the steam drums are mounted above the HRSG. The relative locations of the heat exchangers are shown on the next slide.
Complete HRSG IP Steam Drum HP Steam Drum LP Steam Drum & De-aerator Condensate IP Feedwater Feedwater Pump Recirc Feedwater LP Superhtr Pegging Steam LP Steam From LP Steam Drum HP Feedwater Cold Reheat IP Feedwater A A HP Feedwater HP Steam Hot Reheat Fuel Gas Heater LPEcon1&2 LPEvap HPEcon1&2 IPEcon IPEvap HPEcon3 HPEcon4 LPSuperhtr IPSuperhtr HPEvap1&2 HPSuperhtr1-3 Reheat1 Reheat2 HPSuperhtr4&5
HRSG Details SCR BOX
SCR BOX Hot Exhaust Gases from Gas Turbine Cold Gases to Stack The exhaust gases cool as they move through the HRSG and give up their heat to the contained heat exchangers.
LP System Details LP Economizer Condensate Pump Thru the tubes of the economizer which preheats the feed water to within 20° of saturation temperature for the LP Steam Drum The first component to be discussed in detail is the LP Economizer Water from the economizer is sprayed into the drum where non-condensible gases are stripped and vented to atmosphere. It’s located in the coolest part of the HRSG, near the exhaust. This minimizes the temperature induced stress across the tube walls of the economizer. Flow is from the discharge of the Condensate Pumps.
Water from the economizer enters the de-aerator dome where it impinges on spray dishes. The spray dishes atomize the incoming water and direct it towards the inner walls of the dome. This liberates any gases dissolved in the water. The gases then leave the dome via the de-aerator vent. The de-aerated water moves downwards into the main body of the steam drum where it is further directed into the downcomers of the evaporator or into the supply line for the boiler feed pumps. LP Steam Drum and De-aerator
LP Steam Drum and De-aerator
LP System Details LP Economizer Condensate Pump LP Evaporator Downcomer Risers (12) Vent The steam-water mixture moves upward in the risers, increasing in quality as it goes. The density difference between the water in the downcomer and the steam/water mixture in the risers provides the driving force for moving the mixture back into the drum. The water picks up heat as it moves thru the evaporator until it reaches saturation temperature. It flashes to steam in the riser sections. The de-aerated water pools in the drum where it gravity drains via the downcomer to a distribution header located at the bottom of the Evaporator. The LP drum serves as a surge volume for the evaporator located below it.
Density Driving Head
LP Economizer Condensate Pump LT Vent Water level in the LP drum is regulated by a feedwater flow control valve During startup or low power operations, the Startup Feedwater Flow Control valve is used. Regardless of which valve is in service, valve position is controlled automatically by a level control system LP System Details
LP Economizer LP Evaporator Condensate Pump Condenser FT Cycling of the feeedwater control valves reduces flow from the Condensate Pumps. Too low of a flow could damage the pumps so protection is provided in the form of a condensate return line. Condensate return flow is automatically regulated by throttling of the return valve in response to flow changes. LP System Details
LP Drum TT Condensate Pump Economizer Inlet Temperature Control Valve Pegging Steam from IP Drum LP Economizer Recirculation Flow Control Valve Under gas fired conditions when economizer operation is required, inlet temperature may be maintained by recirculating some of the economizer outlet flow back to the inlet. LP System Details Economizer Recirculation Pump Regardless of which means is used, the required valve operation is accomplished by an automatic temperature control system which monitors and controls economizer inlet temperature. When the inlet temperature is low, such as during startup, some or all of the feed flow is bypassed around the LP economizer using the Economizer Inlet Temperature Control Valve. When oil is used as the fuel and the economizer is bypassed, drum temperature can be maintained by admitting pegging steam from the IP steam drum. To prevent condensation of acids on the outside of the LP economizer tubes, the economizer inlet temperature must be maintained above the dew point for the exhaust gases. (approx 146 °F)
Condensate Pump LP Economizer LP Superheater Steam is drawn from the LP steam drum and sent to the LP superheater where is is further Heated and then sent on to the LP turbine. LP Steam LP System Details
LP System Parameters LP Steam Drum & De-aerator LPEcon1&2 LPEvap LPSuperhtr LP Superhtr Feedwater Pump Recirc Feedwater Condensate LP Steam From LP Steam Drum The cited parameters are the guaranteed values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 85.5 °F. Values are per HRSG. 85.5 °F >140 °F Flow – 64,648 lbm/hr Pressure – 58.5 psia Temp – 593.1 °F
LP Steam Drum & De-aerator LPEcon1&2 LPEvap LPSuperhtr LP Superhtr Feedwater Pump Recirc Feedwater Condensate LP Steam From LP Steam Drum The cited parameters are typical 100% values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 80.7 °F. Values are per HRSG. 80.7 °F >140 °F Flow – 73,507 lbm/hr Pressure – 59.2 psia Temp – 591.7 °F LP System Parameters
LP Steam Drum & De-aerator LPEcon1&2 LPEvap LPSuperhtr LP Superhtr Feedwater Pump Recirc Feedwater Condensate LP Steam From LP Steam Drum The cited parameters are typical 100% values assuming 1 Gas Turbines operating at maximum load and a feedwater inlet temperature of 82.0 °F. Values are per HRSG. 82.0 °F >140 °F Flow – 53,977 lbm/hr Pressure – 57.3 psia Temp – 546.9 °F LP System Parameters
IP System Details IP Economizer IP Feedwater Pump Flow is from the IP Feedwater Pumps Through the tubes of the IP economizer where heat is added And then into the IP Steam Drum
Feedwater enters the IP Steam Drum through a distribution manifold and then moves through the downcomers into the evaporator section. Steam returning to the drum from the evaporator is separated from the feedwater by the primary separator. The separator forces the steam to move upwards following the curve of the inside wall of the drum. After the steam is above the water level, It is free to move out into the body proper of the drum and finally into the steam outlet. IP Steam Drum
IP System Details IP Economizer IP Feedwater Pump Feed flow to the IP drum is regulated by a Feedwater Flow Control Valve which is controlled by the Steam Drum Level Control System The IP evaporator functions similarly to the LP evaporator.
IP Economizer Flow from the superheater passes through a motor operated isolation valve, a pneumatic operated control valve and then ties into the Cold Reheat line. Steam flows from the IP drum and through the IP superheater. IP Superheater Cold Reheat IP System Details
IP Economizer IP Superheater Cold Reheat Under low load conditions, a portion of the IP feedwater may be recirculated back to the LP evaporator. A significant amount of the IP Feedwater is diverted to the Fuel Gas Heater. Fuel Gas LP Evap Flow – 49,707 lbm/hr Pressure – 688.4 psia Temp – 432.7 °F IP System Details
Reheat System Details Reheater #1 Cold Reheat Reheater #2 IP Superheater Flow from the first reheater is sent to Reheater #2 The combined flow from Cold Reheat and the LP Superheater leaves the second reheater and is sent to the IP Turbine. The steam flow is called Hot Reheat at this point. IP Turbine The steam exhaust from the HP turbine, known as Cold Reheat, is directed to Reheater #1. Steam flow from the IP superheater ties into the Cold Reheat line before it reaches the first reheater. To ensure that the turbine is not exposed to excessive steam temperatures, the steam temperature is regulated by a component called an attemperator. IP Feedwater is sprayed into the steam flow between the first and second reheaters. All of the water is evaporated and its only effect is to control the steam temperature at the desired setpoint. IP Feedwater A
IP System Parameters Cold Reheat Hot Reheat Reheat1 Reheat2 IP Feedwater A IP Steam Drum IPEcon IPEvap IPSuperhtr IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum The cited parameters are the guaranteed values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 85.5 °F. Values are per HRSG. Flow – 452,421 lbm/hr Pressure – 373.5 psia Temp – 634.7 °F 85.5 °F Flow – 66,598 lbm/hr Pressure – 390.1 psia Temp – 599.6 °F Flow – 452,735 lbm/hr Pressure – 337.7 psia Temp – 1,052.0 °F Flow – 310 lbm/hr
IP System Parameters Cold Reheat Hot Reheat Reheat1 Reheat2 IP Feedwater A IP Steam Drum IPEcon IPEvap IPSuperhtr IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum The cited parameters are typical 100% values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 80.7 °F. Values are per HRSG. Flow – 456,732 lbm/hr Pressure – 361.8 psia Temp – 613.1 °F 80.7 °F Flow – 75,208 lbm/hr Pressure – 383.7 psia Temp – 623.3 °F Flow – 456,732 lbm/hr Pressure – 335.4 psia Temp – 1,010.2 °F Flow – 310 lbm/hr
IP System Parameters Cold Reheat Hot Reheat Reheat1 Reheat2 IP Feedwater A IP Steam Drum IPEcon IPEvap IPSuperhtr IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum The cited parameters are typical 100% values assuming 1 Gas Turbines operating at maximum load and a feedwater inlet temperature of 82.0 °F. Values are per HRSG. Flow – 472,313 lbm/hr Pressure – 221.2 psia Temp – 642.6 °F 82.0 °F Flow – 67,560 lbm/hr Pressure – 248.3 psia Temp – 571.0 °F Flow – 472,313 lbm/hr Pressure – 173.6 psia Temp – 1,013.1 °F Flow – 310 lbm/hr
HP System Details HP Feedwater Pump HP Economizers 1 - 4 Feed flow enters a series of 4 HP economizers for pre-heating of the feedwater before it enters the HP Steam Drum. Note that the Feedwater Control Valve is located upstream of the economizers in the HP systems.
The HP Steam Drum is very similar to the IP drum. It differs mainly in that steam leaving the Primary Separator is forced through a set of cyclone moisture separators before it goes on to the Secondary Separator and leaves the drum. HP Steam Drum
HP System Details HP Feedwater Pump HP Economizers 1 - 4 HP Superheater 1,2, & 3 HP Superheater 4 & 5 HP Steam Steam from the HP drum is sent to a series of 5 HP superheaters and then on to the HP turbine. An attemperator is mounted between HP superheaters 3 and 4 to control the HP steam temperature. A HP Feedwater
HP System Parameters HP Steam Drum A HP Feedwater HP Feedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 The cited parameters are the guaranteed values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 85.5 °F. Values are per HRSG. 85.5 °F Flow – 389,821 lbm/hr Pressure – 1838.0 psia Temp – 1,052.3 °F Flow – 4,799 lbm/hr
HP Steam Drum A HP Feedwater HP Feedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 The cited parameters are typical 100% values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 80.7 °F. Values are per HRSG. 80.7 °F Flow – 394,379 lbm/hr Pressure – 1794.0 psia Temp – 1,016.9 °F Flow – 0 lbm/hr HP System Parameters
HP Steam Drum A HP Feedwater HP Feedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 The cited parameters are typical 100% values assuming 1 Gas Turbines operating at maximum load and a feedwater inlet temperature of 82.0 °F. Values are per HRSG. 82.0 °F Flow – 418,393 lbm/hr Pressure – 952.6 psia Temp – 1,019.7 °F Flow – 0 lbm/hr HP System Parameters
Complete HRSG IP Steam Drum HP Steam Drum LP Steam Drum & De-aerator Condensate IP Feedwater Feedwater Pump Recirc Feedwater LP Superhtr Pegging Steam LP Steam From LP Steam Drum HP Feedwater Cold Reheat IP Feedwater A A HP Feedwater HP Steam Hot Reheat Fuel Gas Heater LPEcon1&2 LPEvap HPEcon1&2 IPEcon IPEvap HPEcon3 HPEcon4 LPSuperhtr IPSuperhtr HPEvap1&2 HPSuperhtr1-3 Reheat1 Reheat2 HPSuperhtr4&5
Common Features Although not shown on the previous slides, all three of the subsystems have several common features. All of the steam drums have provisions for blowdown, pressure relief valves, drain and vent lines, Level indication, nitrogen dosing for dry layup, chemical dosing for wet layup and corrosion control during operation, and sampling. All of the heat exchangers have provisions for vents and drains. There are numerous sample points along the piping runs.
HRSG Construction
SCR BOX LP Econ. 1&2 LP Evap. Reheat 2 Reheat 1 IP Evap IP Econ. IP SuperhtrLP Superhtr HP Econ. 1&2 HP Econ. 3 HP Econ. 4 HP Superhtr 4&5 HP Superhtr 1,2&3 HP Evap 1&2
The heat exchangers are actually mounted in assemblies called “harps” or racks. A module harp consists of a top and bottom header with up to three rows of tubes between them. Harps are placed against each other to minimize bypass flow of exhaust gases. Harps mounted in groups without an access lane between them are called tube banks. A tube bank may consist of harps with different function and even different pressure systems.
This snug fit between the harp headers and the bumpers creates a seal against gas flow so that the the area below the bottom headers and above the top headers is essentially a dead air space with little or no gas flow. The dead space acts as additional insulation between the hot gases and the box walls. Bumpers Lateral motion of the harps is prevented by bumpers which fit snugly against the harp.
HRSG Operational Considerations
Operating Tips Large combustion turbine combined cycle plants in cyclic service present extreme operational transient conditions. These conditions or limits must be considered in the "Balance of Plant" component selection particularly the HRSG. The evaluation of low cycle fatigue and creep are now beginning to gain the required design attention relative to life cycle analysis.
Operating Tips These transient conditions are the result of a number of factors, which may include:  The fast starting and shutdown characteristics of combustion turbines,  Associated heating and cooling ramp rates of critical components in the heat recovery steam generator (HRSG),  Introduction of cold condensate into hot economizer headers of the HRSG upon a system restart after planned shutdowns such as overnight, and, the required warm-up time of steam cycle equipment.
Potential problems include: Operating Tips • Gas turbine exhaust dew point corrosion (cold end corrosion). • Corrosion and fatigue – cumulative effects • Consequences for not maintaining proper steam cycle chemistry (i.e., on-line, off-line storage and return to service).
To Reduce the Stress Corrosion Fatigue  Minimize thermal shock to the different components.  Minimize the introduction of O2 into the feed/condensate water.  Open the furnace doors to break the natural draft rate through the gas turbine/HRSG/stack.
Approach Temperature The approach temperature is defined as the difference in the temperature of the boiler feedwater leaving the economizer section compared to the water in the steam drum. Calculating the "actual" approach temperature, and comparing it to the "as-designed" approach temperature is an effective tool in assessing performance in the "back end" of the HRSG, and indicates how well the economizer is operating.
Approach Temperature To calculate approach temp, simply find the saturation temperature at the steam-drum operating pressure, and subtract the temperature of the water leaving the economizer. Typical values for approach temperature range from 10F to 40F, depending on the operating status of the HRSG. In many plants, the approach temperature can be determined directly from panel data in the control room.
Approach Temperature Variables Ambient temperature can significantly affect the approach temperature, as a direct function. As the ambient temperature decreases, the approach temperature will also decrease, indicating that the economizer outlet temperature is getting closer to saturation and the risk of steaming within the economizer is growing. Conversely, as ambient temperature increases, so does the approach temperature, indicating that economizer effectiveness is decreasing.
Low Approach Temp If the calculated approach temperature is low--less than 10F--it may indicate economizer steaming or poor evaporator performance. Since most HRSG economizers are either panels or serpentine style, unintended steaming can create major problems. It may cause water hammer and can vapor-lock some economizer circuits, causing high local velocities in some tubes and performance degradation of the entire economizer section
High Approach Temp If the calculated approach temperature is high-more than 10F above the "as-designed" approach temperature-it may indicate economizer under- performance.
Economizer under-performance is one of the most common HRSG performance problems, and has many possible causes, including: • Gas bypass. Some of the exhaust gas takes an alternative path around the finned tube surface; this is usually due to poor baffling. Economizer Under-Performance • Tube outer-surface problems. Fins are damaged; tubes and fins are fouled by debris or precipitate from an upstream source; or tubes and fins are corroded.
Economizer under-performance is one of the most common HRSG performance problems, and has many possible causes, including: • Tube inner-surface problems. Deposits on the inner surface of the tubes lowers the heat transferred to the water. Economizer Under-Performance • Air/vapor pockets. Vapor left over from steam during startup or at other operating points can cause tube circuits to be blocked. Similarly, trapped air left in upper return bends after filling the HRSG with water can cause tube circuits to be blocked.
 Low water velocity. When tube velocities within the economizer are low, stagnation or areas of recirculation can develop, which effectively reduce the economizer heat-transfer area. (Power, November/December 2000, p 64) Economizer Under-Performance Economizer under-performance is one of the most common HRSG performance problems, and has many possible causes, including:  Improper use of full or partial economizer bypass.
Pinch Temperature Pinch temperature is defined as the difference between the exhaust-gas temperature leaving the evaporator and the saturation temperature within the evaporator tubes. The pinch temperature indicates whether the evaporator section is absorbing as much heat as predicted. Typical pinch temperatures range from 15 to 30F. Note: The pinch temperature can not always be measured with installed instrumentation. If the pinch is not being measured at your site, a temporary gas-side thermocouple can be installed while the HRSG is on-line to enable you to make the calculation.
Pinch Temperature Variables If the inlet-air conditions to the gas turbine are not controlled, the ambient temperature will change the calculated pinch temperature. In general, the Pinch will react inversely with ambient temperature: As the ambient temperature increases, the pinch temperature will go down; as the ambient temp decreases, the pinch temp will go up. Note: As the pinch temperature increases, the exhaust-gas temperature leaving the evaporator section is increasing, sending more energy to the heat-transfer surfaces located downstream.
Low Pinch Temp If the pinch temperature is slightly low, the evaporator is probably working better than designed. It is unlikely that the calculated pinch temperature will be significantly lower than the design, especially if the duct burners are not firing (or don't exist). At a low pinch temp, approximately 15F, there is not enough temperature differential between the hot exhaust gas and the water being boiled to drive much more heat transfer.
High Pinch Temp If the pinch temperature is high, it may indicate an under- performing evaporator section.
Some Common Causes of a High Pinch Temp:  Gas bypass. Some of the exhaust gas takes an alternative path around the finned tube surface; this is usually because of poor baffling.  Tube outer-surface problems. Fins are damaged; tubes and fins are fouled by debris or precipitate from an upstream source; or tubes and fins are corroded.  Tube inner surface fouling.
Stack Temperature  The stack temperature, defined as the temperature of the exhaust gas as it exits the HRSG, is an indicator of the overall performance of the HRSG.  The stack temperature is dependent on many factors, including the ambient temperature, rate of supplementary duct firing, and feedwater temperature.
Counter-Intuitive ?  If the gas-turbine inlet-air conditions are not controlled, the stack temperature will decrease as the ambient temperature rises. This is counter-intuitive; especially since steam flow from the HRSG will decrease as the ambient temperature rises.
Counter-Intuitive?  Finally, it is somewhat common for an economizer or pre-heater to be the last section of heat-transfer surface before the exhaust gas exits the HRSG. For this reason, the incoming feedwater temperature can have a major impact on the stack temperature. Of course, the higher the feedwater temperature, the higher the stack temperature.
High Stack Temp  High stack temperatures indicate overall under- performance by the HRSG. Be sure to verify the reference conditions when comparing an actual stack temperature to the predicted value. If you find that your stack temperature is too high, immediately check the approach and pinch temperatures. The most common causes of high stack temperatures are gas bypass and external fouling of the finned tube surface.
Low Stack Temp  A low stack temperature typically indicates that the energy absorbed by the HRSG exceeds predictions
Stack Temp Consistently Low? Check the Following:  Is the feedwater source temperature lower than expected?  Calculate the water dew point of the exhaust gas to determine if condensation is a threat.  Check the exhaust gas acid dew point, especially if using a fuel other than natural gas.
Stack Temp Consistently Low? Check the Following:  Verify proper operation of the economizer, or pre-heater bypass if one exists.  Verify that operating pressures of the deaerator and low-pressure evaporater are not too low. Operating at pressures lower than design can cause flow- accelerated corrosion and deaerator performance problems
Principal Threats to HRSG Reliability are:  Low-cycle thermal fatigue, particularly in high- pressure (h-p) superheaters, HP steam drums and evaporator circuits, and low-temperature economizers.  Corrosion-related problems, which include flow- accelerated corrosion, cold-end gas-side corrosion, and pitting from oxygenated feedwater.  Other thermal-mechanical problems--such as failures of casings and expansion joints. These components typically receive less attention than pressure parts, but can cause persistent operation and maintenance (O&M) challenges.  Other issues--most notably stratification of flue gas during prestart purge of the HRSG.
Quenching damage  In addition to severe heating ramps, superheaters are vulnerable to quench cooling by condensate  Condensation occurs in superheater tubes during every purge of the HRSG prior to gas-turbine ignition.  Quantities of condensate are substantial during hot and warm starts.  A repeat purge can actually fill the front panel tubes of the superheater.
1. Extensive temperature monitoring confirmed that a substantial quantity of condensate formed in superheater tubes during gas-turbine purging, even in large-bore headers. Quenching Damage 2. Condensate began to clear from superheater tubes once steam flow commenced.
4. Condensate clears first from the tubes closest to the end-pipe connections, creating temperature differences between individual tubes along the headers. 3. A single, small-bore drain, opened during purging, reduces the quantity of condensate, but does not completely eliminate it. Quenching Damage
Two Problems Caused By Quench  First: Condensate which is possibly still subcooled is ejected in large quantities into the outlet header and pipe manifold where it quench cools hotter material. (On hot restarts after trips, the outlet header and manifold can be more than 360F above saturation temperature.)
• Second: Individual tubes experience different average temperatures--because they do not clear of condensate simultaneously. Two Problems Caused By Quench Designs that have stiff tube arrangements connected to headers at each end develop significant tensile and compressive loads when at different temperature relative to other tubes.
Selective Catalytic Reduction
Why NOx Reduction?  N02 can irritate the lungs, cause bronchitis and pneumonia, and lower resistance to respiratory infections.  Nitrogen Oxides are a precursor to ozone(03)which is the major component of smog.
The Clean Air Act of 1967, amended in 1970, 1977 and again in 1990, authorizes the EPA to establish standards for atmospheric pollutants, including sulfur dioxide (SO2) and nitrous oxides (NOX). When NOX and volatile organic compounds enter the atmosphere, they react in the presence of sunlight to form ground-level ozone, a major constituent of smog. The current National Ambient Air Quality Standard (NAAQS) for ozone is 0.12 ppm. Areas where the ambient air ozone concentration (averaged over a three year period) is above 0.12 ppm are considered nonattainment areas. Why NOx Reduction?
Power plants located in nonattainment areas are required to implement measures to minimize pollutant emission. Pollution controls for Pilloti consists of a Carbon Monoxide (CO) Catalyst and a Specific Catalytic Reduction (SCR) system. Why NOx Reduction?
Selective Catalytic Reduction • There are two major chemical reactions that take place in NOx reduction: • 4NO + 4NH3 + O2 = 4N2 + 6H2O • The first reaction is most dominant. It shows a one to one relationship between NO and NH3 and also NO2 is harder to break down. • 2NO2 + 4NH3 + O2 = 3N2 + 6H2O
F l u e G a s C l e a n G a s N O x N O x N O x N O x N H 3 N H 3 C a t a l y s t B e d N H 3 N H 3 N H 3 N 2 H 2 O N 2 H 2 O Selective Catalytic Reduction
Selective Catalytic Reduction • Aqueous ammonia is pumped into a vaporization tank where it is mixed with a heated air supply and sent into the spray manifold inside the HRSG. • The ammonia spray is absorbed in the active sites on the catalyst bed. The flue gas passes over those same sites where the NOx reacts and forms N2 and H2O. • The active catalyst is a combination of different transition metal oxides formed into either a honeycomb or flat plate shape. This construction material lowers the activation energy required to initiate the chemical reaction.
Selective Catalytic Reduction • When fossil fuels are burned at high temperatures nitric oxide (NO) is formed. When left untreated it oxidizes in the atmosphere forming NO2, that irritates the lungs and can cause respiratory problems. • SCR is a post combustion process that reduces the NOx found in exhaust gasses to molecular N2 and H2O. • Generally located downstream of the HP evaporator section, the system can potentially remove 90% of the NOx from the flue gas.
SCR Operational Overview
Stack SCR Box HP Steam Drum LP Steam Drum and De-aerator IP Steam Drum LPEcon#1 LPEcon#2 IPEcon LPEcon#2 LPEcon#2 LPEvap#1 IPEvap#1 LPEvap#3 LPEvap#2 HPEvap#2 HPEcon#2 HPEcon#1 IPEvap#1 HPEcon#3 HPEcon#4 HPEcon#4 HPEcon#3 HPSuperheater#5 IPSuperheater HPEvap#1 HPEvap#1 HPEvap#1 HPSuperheater#4 HPSuperheater#3 HPSuperheater#2 HPSuperheater#1 Reheater#1 Reheater#2 GT Exhaust Gas Flow NOX emissions are reduced by introducing Ammonia (NH3) into the flue gas stream.
Stack SCR Box HP Steam Drum LP Steam Drum and De-aerator IP Steam Drum LPEcon#1 LPEcon#2 IPEcon LPEcon#2 LPEcon#2 LPEvap#1 IPEvap#1 LPEvap#3 LPEvap#2 HPEvap#2 HPEcon#2 HPEcon#1 IPEvap#1 HPEcon#3 HPEcon#4 HPEcon#4 HPEcon#3 HPSuperheater#5 IPSuperheater HPEvap#1 HPEvap#1 HPEvap#1 HPSuperheater#4 HPSuperheater#3 HPSuperheater#2 HPSuperheater#1 Reheater#1 Reheater#2 GT Exhaust Gas Flow AIG (Ammonia Injection Grid) NH3 Injection Hot Flue Gas to SCR Skid SCR Skid The hot flue gases are taken from the SCR Box and fed to the SCR Skid Ammonia (NH3) is mixed with hot flue gases to ensure complete evaporation and then fed into an Ammonia Injection Grid. The SCR Skid provides the components to mix the flue gases with the Ammonia. The hot flue gases and gaseous ammonia are returned to the gas stream through the Ammonia Injection Grid. The AIG is little more than a grid of pipes with injection holes. There are butterfly valves and orifices for adjusting the ammonia injection rate over different zones of the gas path cross-section.
Aqueous Ammonia Vaporizer Return to AIG VSD Panel VSD Panel Aqueous Ammonia FCV XCV Instrument Air PRV Hot Flue Gas Fans Hot Flue Gas From SCR Box The hot flue gases mix with Aqueous Ammonia in the Aqueous Ammonia Vaporizer . To ensure complete vaporization of the ammonia, it is atomized by forcing it through a mixing nozzle with Instrument Air. The mixture of flue gases and ammonia is then returned to the AIG.
VSD Panel VSD Panel Hot Flue Gas Fans Hot Flue Gas From SCR Box Two 100% capacity Variable Speed Fans are provided to draw the hot flue gases from the SCR Box and inject them into the Aqueous Vaporizer. One fan is selected for service while the other remains in standby.
The rate of ammonia injection must be closely controlled for two reasons. The first is to ensure that NOX emissions are less than limits. In this case we limit our Stack NOX concentrations to less than 2 ppm. The second is to limit ammonia leakage to less than 10 ppm at the stack exit. Unreacted NH3 in the flue gas downstream of the SCR is called Ammonia Slip. It is necessary to limit the amount of ammonia slip to minimize the formation of (NH4)SO4 and NH4HSO4 which can cause plugging and corrosion of downstream equipment. This is not a problem when the Gas Turbines are using gas as the fuel. However, we must use low sulfur oil or minimize ammonia slip when oil is the fuel.
3. Regulation of ammonia flow rate to meet the calculated necessary flow rate. Control of the ammonia injection rate has four major considerations: 1. Determination of how much ammonia should be injected to achieve the desired NOX emission limits. 2. Determination of how much gas flow is required through the vaporizer to achieve the required dilution. 4. Regulation of the gas flow rate through the vaporizer to meet the calculated required dilution flow.
Inlet NOX Set Value Σ _ + Determination of how much ammonia should be injected to achieve the desired NOX emission limits is fairly complex. It starts by comparing the actual NOX concentration at the inlet to the HRSG to a set value controlled by the operator.
Inlet NOX Set Value Σ _ + Mol. Rate ƒ The difference between the Set Value and the measured concentration at the HRSG inlet is fed to a function generator which calculates a molar ammonia flow rate.
However this function generator assumes that the O2 concentration is 15%. If the actual O2 concentration is anything else, the calculated value for ammonia flow rate will be incorrect. We therefore introduce a correction factor to compensate for O2 concentrations other than 15%. Inlet NOX Set Value Σ _ + Mol. Rate ƒƒ Stack O2 GT Flue Gas Flow Rate X Actual NOX Flow Rate X Feed Forward
The actual NOX flow rate is calculated by multiplying the compensated Inlet NOX concentration by the GT flue gas flow rate. The actual NOX flow rate is then multiplied by the Mol. Rate to obtain the Feed Forward Signal
 The Feed Forward signal is essentially a desired ammonia flow rate and it can be fed to the air  pressure regulator for the NH3 Flow Control Valve. However, systems never work perfectly so we must have an ammonia flow rate feedback signal to ensure that the FCV opens to the correct position. The feedback signal is derived by measuring the actual ammonia flow rate downstream of the FCV and the difference between actual and desired flow rates is used to control the FCV. The Feed Forward signal can tell the FCV to open to a specified percentage and if all design assumptions are actually met, we should obtain the correct flow rate.
Inlet NOX Set Value Σ _ + Mol. Rate ƒƒ Stack O2 GT Flue Gas Flow Rate X Actual NOX Flow Rate X Feed Forward Aqueous Ammonia FCV Σ + _ FT
Inlet NOX Set Value Σ _ + ƒƒ Stack O2 GT Flue Gas Flow Rate X Actual NOX Flow Rate X Aqueous Ammonia FCV Σ + _ FT To ensure that the desired reduction is obtained and that NOX emissions remain within limits, we use another feedback signal; this one looking at actual stack NOX levels. Gain Σ Set Value Stack NOX + _
The entire control scheme discussed so far provides rapid response to changes in the GT flue gas NOX concentration. However it assumes that if we inject the correct ammonia flow based on the NOX at the HRSG inlet we will obtain the desired reduction in NOX at the stack. That assumption may not always be valid. This feedback signal adjusts the gain of the Feed Forward signal to compensate for any difference between the operator determined Set Value and the measured Stack NOX concentration.
The Variable Speed fans have two operating modes, VSD control and Gas Temperature control. VSD control is initiated by the DCS when the Gas Turbine starts firing and the SCR temperature starts to increase. Flue Gas Temperature Fan Speed Standby Fan @ 700 RPM Main Fan @ 2540 RPM Main Fan @ 2000 RPM 293 °F 122 °F VSD Control
When the flow rate of the Hot Flue Gas is sufficient, the isolation valve for the ammonia injection opens and ammonia flow control switches to Auto. Fan speed control switches to Gas Temperature mode. From this point, fan speed is regulated by SCR inlet temperature. Flue Gas Temperature Fan Speed Standby Fan @ 700 RPM Main Fan @ 2540 RPM Main Fan @ 2000 RPM 293 °F 122 °F VSD Control
At 293 °F, the Main Fan reaches its maximum VSD operating speed of 2540 RPM. The fan speed will remain at this value regardless of further increase in SCR temperature as long as the fans remain in VSD control mode. VSD Control is used to start and accelerate the fans to obtain a controlled heat-up of the fan bearings and to ensure that the fan motors do not overload.
HRSG/SCR Failure – Cause & Prevention
Problems Common for SCR Systems  Increase in NOx Emission Rate  Reduction of NOx Conversion  Efficiency/Catalyst Degradation  Increase in Catalyst Pressure Drop  Increase in Ammonia Slip  Plugging of Ammonia Supply System  Plugging of Downstream Equipment
Causes of High NOx Emissions  Sources of NOx Emission Increase  Decrease in Catalyst Activity  Catalyst Degradation Higher than expected NOx emissions from combustion turbine  Imbalance Between Ammonia Injection and NOx Distribution  Flue Gas Leakage Around Catalyst
Solutions to NOx Emission Increases  Clean catalyst (if catalyst OP has also increased)  Reduce NOx emissions from combustion turbine or duct burner.  Clean / Adjust the AIG to match the NOx distribution  Reduce gas leakage around catalyst by inspecting and maintaining support frame sealing system and catalyst packing.  Sample / Replace Catalyst
Sources of Catalyst Degradation  Operation Above Design Temperature  Decreases available surface area by thermal sintering of reaction sites.  Operation Below Design Temperature  Decreases available surface area by plugging reaction sites with ammonia-sulfur compounds.  Particulate Matter- Decreases available surface area by plugging reaction sites.  Poisoning- Some Chemicals such as Sodium, Potassium, Halogen, Calcium, Magnesium, Arsenic, Silica, etc. will reduce conversion efficiency.
Solutions to Catalyst Degradation  Try not to exceed maximum operational temperature of catalyst.  Inject ammonia only after the catalyst has reached the minimum operating temperature - preventing ammonium-sulfur compound deposits on the catalyst face.  Use a vacuum, compressed air, or steam to remove particulate from the catalyst.  Contact manufacturer if catalyst surface comes in contact with water.  Sample catalyst annually.
Sources of Catalyst Pressure Drop  Insulation Particulate  Ammonia-Sulfur Compounds  And yes... Even Liner Plates
Solutions to Catalyst Pressure Drop  Use a vacuum, compressed air, or steam to remove particulate and insulation from the catalyst. Use care not to damage catalyst.  Operate the catalyst above the ammonium- sulfur compound recovery temperature to evaporate the salts.
Pressure Drop Correction Vacuuming Catalyst
Ammonia Slip  Flue Gas Leakage Around Catalyst  Decrease in Catalyst Activity  Imbalance Between Ammonia Injection and NOx Distribution
Ammonia Slip - Solutions  Clean Catalyst  Clean / Adjust the AIG to match the NOx distribution  Reduce gas leakage around catalyst by inspecting and maintaining support frame sealing system and catalyst packing.  Sample / Replace Catalyst
Causes for Ammonia Supply Plugging  Particulate Mill Scale  Ammonia-Sulfur Compounds
Solutions to Ammonia Supply Plugging  Install filters to remove particulate and mill scale.  Utilize aqueous ammonia that is free of suspended solids.  Clean piping utilizing compressed air or steam to remove mill scale.  Time, combined with the ammonia flow will also eventually remove mill scale.  Operate the system above the salt formation temperatures to prevent ammonia-sulfur compounds from forming.
Anhydrous Ammonia  Advantages: Low auxiliary heat input, small dilution air fans, no NH3 salts.  Disadvantages: Hazardous substance - special operational / handling requirements.
Aqueous Ammonia - Hot Gas Recirculation  Advantages: "No" auxiliary heat input, minimal handling requirements.  Disadvantages: Large "hot" dilution air fans , NH3 salt concerns.
Source of Downstream Tube Plugging  The ammonia slip combines with sulfur and condenses as ammonium bisulfate on the "cold" tubes. This salt buildup will eventually interfere with the HRSG heat transfer and increase the combustion turbine back pressure.
Solution to Downstream Tube Plugging  Reduce Sulfur Content of Fuel  Reduce Ammonia Slip  Periodic Cleaning (Water Washing, Compressed Air)
Stack HP Steam Drum LP Steam Drum and De-aerator IP Steam Drum LPEcon#1 LPEcon#2 IPEcon LPEcon#2 LPEcon#2 LPEvap#1 IPEvap#1 LPEvap#3 LPEvap#2 HPEvap#2 HPEcon#2 HPEcon#1 IPEvap#1 HPEcon#3 HPEcon#4 HPEcon#4 HPEcon#3 HPSuperheater#5 IPSuperheater HPEvap#1 HPEvap#1 HPEvap#1 HPSuperheater#4 HPSuperheater#3 HPSuperheater#2 HPSuperheater#1 Reheater#1 Reheater#2 IPSuperheater CO Catalyst Grid GT Exhaust Gas Flow The CO Catalyst Grid consists of several 2ft by 2ft converter modules. Each module contains a honeycomb core made of stainless steel foil and covered with the active catalyst materials Al2O3 and Pt. These materials participate in intermediate stages of the reaction but are not consumed. The CO Catalyst Grid is mounted in the HRSG between #1 and #2 HP evaporators. The chemical reaction which occurs is 2CO + O2 → 2 CO2 There are no controls required for the CO Catalyst Grid. The only requirement for the reaction to occur is a temperature above 500 °F and an excess of oxygen.
The EPA has placed limits on the emission of various airborne pollutants which result from the use of fossil fuels. The two contaminants of most concern are the different compounds of nitrogen and oxygen, and carbon monoxide. Carbon monoxide is easily controlled by passing it over a catalyst bed of Al2O3 and Pt. This control method requires no electronics or support equipment. The reaction will proceed as long as CO is present at the catalyst surface, the ambient temperature is greater than 500 °F and there is an excess of O2. The CO catalyst is mounted in the HRSG between #1 and #2 HP evaporators. SummarySummary
SummarySummary This control method requires precise regulation of the ammonia injection rate. The components used to regulate the ammonia injection rate are mounted on the SCR skid, located near the HRSG inlet. The major components involved are the Hot Flue Gas Fans, the Aqueous Ammonia Vaporizer, the instrument air pressure supply to the Vaporizer, and the Ammonia flow controller. NOX is controlled by injecting ammonia into the gas steam upstream of the SCR. In the SCR, the NH3 reacts with the NOX to form N2 and harmless water vapor. These reactions will proceed at normal HRSG operating temperature if a catalysts are present. The catalysts are oxide forms of titanium, vanadium, and tungsten.
SummarySummary These components will work together to supply the correct ammonia flow to the Ammonia Injection Grid. The AIG is a network of pipes and injection holes located in the HRSG just upstream of #2 HP evaporator.

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Basic ccpp overview Power plant

  • 1.
    Ras Laffan CCCPIntroduction Manual
  • 2.
  • 3.
    Course Outline • CombinedCycle Theory Review • HRSG Steam Cycles & Flow Diagrams • HRSG Construction • HRSG Operational Considerations • SCR Introduction • SCR Operational Overview • HRSG/SCR Failure – Cause & Prevention
  • 4.
  • 5.
    What is a“Combined Cycle” Power Plant? A combined cycle system uses the same heat energy to generate power from two different thermodynamic cycles. The advantage of this arrangement is the overall efficiency of the plant unit – electrical energy out compared with heat energy in – is greatly improved over either the simple gas turbine cycle or simple steam turbine cycle.
  • 6.
    This plant usestwo distinctly different thermodynamic cycles to perform useful work (generate electricity). • The Brayton (Gas Turbine) Cycle • The Rankine (Steam Plant) Cycle
  • 7.
  • 8.
    The Brayton Cycle Inthe Brayton Cycle (a.k.a. Constant Pressure Cycle), combustion and exhaust take place at a constant pressure.
  • 9.
    The Brayton Cycle CanYou Explain This Diagram?
  • 10.
  • 11.
    Brayton Cycle Efficiency •Brayton Cycle thermal efficiency is measured using compressor ratio. • Compressor ratio is the ratio that exists between the maximum and minimum pressures in the cycle – pressure of the air entering the compressor vs. the hot gas leaving the turbine.
  • 12.
    • It isbest expressed as; ηth = 1 - rp (1-k)/k Where; rp = compressor ratio and k = the value of the ratio of the specific heats of the working fluid. The average simple cycle gas turbine cycle is 38% - 45% efficient Brayton Cycle Efficiency
  • 13.
  • 14.
    P3 P1 Turbine FP HRSG Condenser Temperature Entropy (S) 1 2 3 P2 4 5 6 7 8 Canyou explain the shape of this cycle? The Rankine Cycle
  • 15.
  • 16.
    Rankine Cycle Efficiency •The Rankine Cycle stated simply, is ∆E = Q - W. • The total change in energy entering or leaving the system equals the heat added to the system less the work performed by the system.
  • 17.
    • It isbest expressed as; ηth = (wout - win ) / qin Where; wout = work done by the system, win = work done on the system; and qin = specific heat added Rankine Cycle Efficiency • The average normal Rankine Cycle is about 27% - 35% efficient.
  • 18.
  • 19.
    Combined Cycle Efficiency •When two power cycles, each with their own thermal efficiencies, are employed in a single power unit, the resulting efficiency is dependant upon each of the two cycles. • In our particular application the Brayton Cycle and Rankine Cycle operate in series. • Because of this any problems with the efficiency of the Brayton Cycle will have a direct effect on the efficiency of the Rankine Cycle and thereby affect the overall plant efficiency.
  • 20.
    • Thermal efficiencycan be calculated as; ηth = ηA + ηB - ηA ηB . • With Cycle A representing the Brayton Cycle and Cycle B representing the Rankine Cycle. Combined Cycle Efficiency • It is a result of this gain in efficiency that the combined cycle power plant is now being widely implemented over more traditional power generating stations.
  • 22.
    So, What arethe advantages? • Short Project Schedules ~ 24 Months • High Thermal Efficiency ~ 50% • Low Environmental Emmissions • High Operating Flexibility • High Availability ~ 90%
  • 23.
    HRSG Steam Cycles& Flow Diagrams
  • 24.
    Functional Description The HRSGuses waste heat contained in the exhaust of a gas turbine to convert water to steam. The steam is then used to power a steam turbine and/or supply auxiliary plant processes.
  • 25.
    HRSG Recover Thermal EnergyFrom Turbine Exhaust Gas. Transfer Heat Into Feed Water Generate LP, IP and HP Steam Gas Turbine Exhaust Auxiliary Burners (Optional) Boiler Feedwater Utility Steam (Optional) LP, IP and HP Steam Exhaust Gas
  • 26.
    The most commonHRSG is a horizontal, three pressure, natural circulation system with reheat and superheat. SCR units are commonly added for emissions reduction. 3 Steam Cycles, one HRSG SCR BOX
  • 27.
    SCR BOX The complete HRSGsystem is made up of three separate subsystems (LP, IP, and HP); each with its own steam drum and all required support equipment. 3 Steam Cycles, one HRSG HPIPLP
  • 28.
    The three pressuresystem has the advantage of providing each stage of the steam turbine with the steam pressure and flow most efficient for the turbine blade speed. 3 Steam Cycles, one HRSG SCR BOX
  • 29.
    LP System Overview LPSteam Drum & De-aerator LPEcon1&2 LPEvap LPSuperhtr The LP System consists of a LP Steam Drum and De-aerator, two LP economizers mounted in series, an LP evaporator, an LP superheater, and all required piping and valves. LP Superhtr Feedwater Pump Recirc Feedwater Condensate LP SteamFrom LP Steam Drum
  • 30.
    IP System Overview IPSuperhtr TheIP system comprises the IP Steam Drum, the IP economizer, the IP evaporator, the IP superheater and all required piping and valves. IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum IP Steam Drum IPEcon IPEvap
  • 31.
    IPEcon IP System Overview IPSuperhtr Steamfrom the IP superheater ties into the Cold Reheat line and then passes through two reheaters before leaving as Hot Reheat steam. IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum IP Steam DrumIPEvap Reheat2 Cold Reheat Hot Reheat IP Feedwater A Reheat1
  • 32.
    IP System Overview Hotreheat steam temperature is controlled by an attemperator located between the two reheaters. IP feedwater supplies the cooling spray used in the attemperator. Reheat2 Cold Reheat Hot Reheat IP Feedwater A Reheat1
  • 33.
    HP Steam Drum HPFeedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 The HP system includes the HP Steam Drum, 4 HP economizers mounted in series, 2 HP evaporators mounted in series, 5 HP superheaters also mounted in series, and all required piping and valves. HP System Overview
  • 34.
    HP Steam Drum HPFeedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 HP steam temperature is controlled by an attemperator mounted between the HP superheaters. The attemperator uses HP feedwater as the cooling medium. HP System Overview A HP Feedwater
  • 35.
    Component Locations All economizers,evaporators, superheaters, and reheaters are mounted within the HRSG while the steam drums are mounted above the HRSG. The relative locations of the heat exchangers are shown on the next slide.
  • 36.
    Complete HRSG IP SteamDrum HP Steam Drum LP Steam Drum & De-aerator Condensate IP Feedwater Feedwater Pump Recirc Feedwater LP Superhtr Pegging Steam LP Steam From LP Steam Drum HP Feedwater Cold Reheat IP Feedwater A A HP Feedwater HP Steam Hot Reheat Fuel Gas Heater LPEcon1&2 LPEvap HPEcon1&2 IPEcon IPEvap HPEcon3 HPEcon4 LPSuperhtr IPSuperhtr HPEvap1&2 HPSuperhtr1-3 Reheat1 Reheat2 HPSuperhtr4&5
  • 37.
  • 38.
    SCR BOX Hot Exhaust Gases fromGas Turbine Cold Gases to Stack The exhaust gases cool as they move through the HRSG and give up their heat to the contained heat exchangers.
  • 39.
    LP System Details LPEconomizer Condensate Pump Thru the tubes of the economizer which preheats the feed water to within 20° of saturation temperature for the LP Steam Drum The first component to be discussed in detail is the LP Economizer Water from the economizer is sprayed into the drum where non-condensible gases are stripped and vented to atmosphere. It’s located in the coolest part of the HRSG, near the exhaust. This minimizes the temperature induced stress across the tube walls of the economizer. Flow is from the discharge of the Condensate Pumps.
  • 40.
    Water from theeconomizer enters the de-aerator dome where it impinges on spray dishes. The spray dishes atomize the incoming water and direct it towards the inner walls of the dome. This liberates any gases dissolved in the water. The gases then leave the dome via the de-aerator vent. The de-aerated water moves downwards into the main body of the steam drum where it is further directed into the downcomers of the evaporator or into the supply line for the boiler feed pumps. LP Steam Drum and De-aerator
  • 41.
    LP Steam Drumand De-aerator
  • 42.
    LP System Details LPEconomizer Condensate Pump LP Evaporator Downcomer Risers (12) Vent The steam-water mixture moves upward in the risers, increasing in quality as it goes. The density difference between the water in the downcomer and the steam/water mixture in the risers provides the driving force for moving the mixture back into the drum. The water picks up heat as it moves thru the evaporator until it reaches saturation temperature. It flashes to steam in the riser sections. The de-aerated water pools in the drum where it gravity drains via the downcomer to a distribution header located at the bottom of the Evaporator. The LP drum serves as a surge volume for the evaporator located below it.
  • 43.
  • 44.
    LP Economizer Condensate Pump LT Vent Waterlevel in the LP drum is regulated by a feedwater flow control valve During startup or low power operations, the Startup Feedwater Flow Control valve is used. Regardless of which valve is in service, valve position is controlled automatically by a level control system LP System Details
  • 45.
    LP Economizer LP Evaporator CondensatePump Condenser FT Cycling of the feeedwater control valves reduces flow from the Condensate Pumps. Too low of a flow could damage the pumps so protection is provided in the form of a condensate return line. Condensate return flow is automatically regulated by throttling of the return valve in response to flow changes. LP System Details
  • 46.
    LP Drum TT Condensate Pump EconomizerInlet Temperature Control Valve Pegging Steam from IP Drum LP Economizer Recirculation Flow Control Valve Under gas fired conditions when economizer operation is required, inlet temperature may be maintained by recirculating some of the economizer outlet flow back to the inlet. LP System Details Economizer Recirculation Pump Regardless of which means is used, the required valve operation is accomplished by an automatic temperature control system which monitors and controls economizer inlet temperature. When the inlet temperature is low, such as during startup, some or all of the feed flow is bypassed around the LP economizer using the Economizer Inlet Temperature Control Valve. When oil is used as the fuel and the economizer is bypassed, drum temperature can be maintained by admitting pegging steam from the IP steam drum. To prevent condensation of acids on the outside of the LP economizer tubes, the economizer inlet temperature must be maintained above the dew point for the exhaust gases. (approx 146 °F)
  • 47.
    Condensate Pump LP Economizer LPSuperheater Steam is drawn from the LP steam drum and sent to the LP superheater where is is further Heated and then sent on to the LP turbine. LP Steam LP System Details
  • 48.
    LP System Parameters LPSteam Drum & De-aerator LPEcon1&2 LPEvap LPSuperhtr LP Superhtr Feedwater Pump Recirc Feedwater Condensate LP Steam From LP Steam Drum The cited parameters are the guaranteed values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 85.5 °F. Values are per HRSG. 85.5 °F >140 °F Flow – 64,648 lbm/hr Pressure – 58.5 psia Temp – 593.1 °F
  • 49.
    LP Steam Drum& De-aerator LPEcon1&2 LPEvap LPSuperhtr LP Superhtr Feedwater Pump Recirc Feedwater Condensate LP Steam From LP Steam Drum The cited parameters are typical 100% values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 80.7 °F. Values are per HRSG. 80.7 °F >140 °F Flow – 73,507 lbm/hr Pressure – 59.2 psia Temp – 591.7 °F LP System Parameters
  • 50.
    LP Steam Drum& De-aerator LPEcon1&2 LPEvap LPSuperhtr LP Superhtr Feedwater Pump Recirc Feedwater Condensate LP Steam From LP Steam Drum The cited parameters are typical 100% values assuming 1 Gas Turbines operating at maximum load and a feedwater inlet temperature of 82.0 °F. Values are per HRSG. 82.0 °F >140 °F Flow – 53,977 lbm/hr Pressure – 57.3 psia Temp – 546.9 °F LP System Parameters
  • 51.
    IP System Details IPEconomizer IP Feedwater Pump Flow is from the IP Feedwater Pumps Through the tubes of the IP economizer where heat is added And then into the IP Steam Drum
  • 52.
    Feedwater enters theIP Steam Drum through a distribution manifold and then moves through the downcomers into the evaporator section. Steam returning to the drum from the evaporator is separated from the feedwater by the primary separator. The separator forces the steam to move upwards following the curve of the inside wall of the drum. After the steam is above the water level, It is free to move out into the body proper of the drum and finally into the steam outlet. IP Steam Drum
  • 53.
    IP System Details IPEconomizer IP Feedwater Pump Feed flow to the IP drum is regulated by a Feedwater Flow Control Valve which is controlled by the Steam Drum Level Control System The IP evaporator functions similarly to the LP evaporator.
  • 54.
    IP Economizer Flow fromthe superheater passes through a motor operated isolation valve, a pneumatic operated control valve and then ties into the Cold Reheat line. Steam flows from the IP drum and through the IP superheater. IP Superheater Cold Reheat IP System Details
  • 55.
    IP Economizer IP Superheater Cold Reheat Underlow load conditions, a portion of the IP feedwater may be recirculated back to the LP evaporator. A significant amount of the IP Feedwater is diverted to the Fuel Gas Heater. Fuel Gas LP Evap Flow – 49,707 lbm/hr Pressure – 688.4 psia Temp – 432.7 °F IP System Details
  • 56.
    Reheat System Details Reheater#1 Cold Reheat Reheater #2 IP Superheater Flow from the first reheater is sent to Reheater #2 The combined flow from Cold Reheat and the LP Superheater leaves the second reheater and is sent to the IP Turbine. The steam flow is called Hot Reheat at this point. IP Turbine The steam exhaust from the HP turbine, known as Cold Reheat, is directed to Reheater #1. Steam flow from the IP superheater ties into the Cold Reheat line before it reaches the first reheater. To ensure that the turbine is not exposed to excessive steam temperatures, the steam temperature is regulated by a component called an attemperator. IP Feedwater is sprayed into the steam flow between the first and second reheaters. All of the water is evaporated and its only effect is to control the steam temperature at the desired setpoint. IP Feedwater A
  • 57.
    IP System Parameters ColdReheat Hot Reheat Reheat1 Reheat2 IP Feedwater A IP Steam Drum IPEcon IPEvap IPSuperhtr IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum The cited parameters are the guaranteed values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 85.5 °F. Values are per HRSG. Flow – 452,421 lbm/hr Pressure – 373.5 psia Temp – 634.7 °F 85.5 °F Flow – 66,598 lbm/hr Pressure – 390.1 psia Temp – 599.6 °F Flow – 452,735 lbm/hr Pressure – 337.7 psia Temp – 1,052.0 °F Flow – 310 lbm/hr
  • 58.
    IP System Parameters ColdReheat Hot Reheat Reheat1 Reheat2 IP Feedwater A IP Steam Drum IPEcon IPEvap IPSuperhtr IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum The cited parameters are typical 100% values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 80.7 °F. Values are per HRSG. Flow – 456,732 lbm/hr Pressure – 361.8 psia Temp – 613.1 °F 80.7 °F Flow – 75,208 lbm/hr Pressure – 383.7 psia Temp – 623.3 °F Flow – 456,732 lbm/hr Pressure – 335.4 psia Temp – 1,010.2 °F Flow – 310 lbm/hr
  • 59.
    IP System Parameters ColdReheat Hot Reheat Reheat1 Reheat2 IP Feedwater A IP Steam Drum IPEcon IPEvap IPSuperhtr IP Feedwater Pegging Steam Fuel Gas Heater LP Steam Drum The cited parameters are typical 100% values assuming 1 Gas Turbines operating at maximum load and a feedwater inlet temperature of 82.0 °F. Values are per HRSG. Flow – 472,313 lbm/hr Pressure – 221.2 psia Temp – 642.6 °F 82.0 °F Flow – 67,560 lbm/hr Pressure – 248.3 psia Temp – 571.0 °F Flow – 472,313 lbm/hr Pressure – 173.6 psia Temp – 1,013.1 °F Flow – 310 lbm/hr
  • 60.
    HP System Details HPFeedwater Pump HP Economizers 1 - 4 Feed flow enters a series of 4 HP economizers for pre-heating of the feedwater before it enters the HP Steam Drum. Note that the Feedwater Control Valve is located upstream of the economizers in the HP systems.
  • 61.
    The HP SteamDrum is very similar to the IP drum. It differs mainly in that steam leaving the Primary Separator is forced through a set of cyclone moisture separators before it goes on to the Secondary Separator and leaves the drum. HP Steam Drum
  • 62.
    HP System Details HPFeedwater Pump HP Economizers 1 - 4 HP Superheater 1,2, & 3 HP Superheater 4 & 5 HP Steam Steam from the HP drum is sent to a series of 5 HP superheaters and then on to the HP turbine. An attemperator is mounted between HP superheaters 3 and 4 to control the HP steam temperature. A HP Feedwater
  • 63.
    HP System ParametersHP Steam Drum A HP Feedwater HP Feedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 The cited parameters are the guaranteed values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 85.5 °F. Values are per HRSG. 85.5 °F Flow – 389,821 lbm/hr Pressure – 1838.0 psia Temp – 1,052.3 °F Flow – 4,799 lbm/hr
  • 64.
    HP Steam Drum A HPFeedwater HP Feedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 The cited parameters are typical 100% values assuming 2 Gas Turbines operating at maximum load and a feedwater inlet temperature of 80.7 °F. Values are per HRSG. 80.7 °F Flow – 394,379 lbm/hr Pressure – 1794.0 psia Temp – 1,016.9 °F Flow – 0 lbm/hr HP System Parameters
  • 65.
    HP Steam Drum A HPFeedwater HP Feedwater HP Steam HPEvap1&2 HPEcon1&2 HPEcon3 HPEcon4 HPSuperhtr1-3 HPSuperhtr4&5 The cited parameters are typical 100% values assuming 1 Gas Turbines operating at maximum load and a feedwater inlet temperature of 82.0 °F. Values are per HRSG. 82.0 °F Flow – 418,393 lbm/hr Pressure – 952.6 psia Temp – 1,019.7 °F Flow – 0 lbm/hr HP System Parameters
  • 66.
    Complete HRSG IP SteamDrum HP Steam Drum LP Steam Drum & De-aerator Condensate IP Feedwater Feedwater Pump Recirc Feedwater LP Superhtr Pegging Steam LP Steam From LP Steam Drum HP Feedwater Cold Reheat IP Feedwater A A HP Feedwater HP Steam Hot Reheat Fuel Gas Heater LPEcon1&2 LPEvap HPEcon1&2 IPEcon IPEvap HPEcon3 HPEcon4 LPSuperhtr IPSuperhtr HPEvap1&2 HPSuperhtr1-3 Reheat1 Reheat2 HPSuperhtr4&5
  • 67.
    Common Features Although notshown on the previous slides, all three of the subsystems have several common features. All of the steam drums have provisions for blowdown, pressure relief valves, drain and vent lines, Level indication, nitrogen dosing for dry layup, chemical dosing for wet layup and corrosion control during operation, and sampling. All of the heat exchangers have provisions for vents and drains. There are numerous sample points along the piping runs.
  • 68.
  • 69.
    SCR BOX LP Econ. 1&2 LPEvap. Reheat 2 Reheat 1 IP Evap IP Econ. IP SuperhtrLP Superhtr HP Econ. 1&2 HP Econ. 3 HP Econ. 4 HP Superhtr 4&5 HP Superhtr 1,2&3 HP Evap 1&2
  • 70.
    The heat exchangersare actually mounted in assemblies called “harps” or racks. A module harp consists of a top and bottom header with up to three rows of tubes between them. Harps are placed against each other to minimize bypass flow of exhaust gases. Harps mounted in groups without an access lane between them are called tube banks. A tube bank may consist of harps with different function and even different pressure systems.
  • 71.
    This snug fitbetween the harp headers and the bumpers creates a seal against gas flow so that the the area below the bottom headers and above the top headers is essentially a dead air space with little or no gas flow. The dead space acts as additional insulation between the hot gases and the box walls. Bumpers Lateral motion of the harps is prevented by bumpers which fit snugly against the harp.
  • 73.
  • 74.
    Operating Tips Large combustionturbine combined cycle plants in cyclic service present extreme operational transient conditions. These conditions or limits must be considered in the "Balance of Plant" component selection particularly the HRSG. The evaluation of low cycle fatigue and creep are now beginning to gain the required design attention relative to life cycle analysis.
  • 75.
    Operating Tips These transientconditions are the result of a number of factors, which may include:  The fast starting and shutdown characteristics of combustion turbines,  Associated heating and cooling ramp rates of critical components in the heat recovery steam generator (HRSG),  Introduction of cold condensate into hot economizer headers of the HRSG upon a system restart after planned shutdowns such as overnight, and, the required warm-up time of steam cycle equipment.
  • 76.
    Potential problems include: OperatingTips • Gas turbine exhaust dew point corrosion (cold end corrosion). • Corrosion and fatigue – cumulative effects • Consequences for not maintaining proper steam cycle chemistry (i.e., on-line, off-line storage and return to service).
  • 77.
    To Reduce theStress Corrosion Fatigue  Minimize thermal shock to the different components.  Minimize the introduction of O2 into the feed/condensate water.  Open the furnace doors to break the natural draft rate through the gas turbine/HRSG/stack.
  • 78.
    Approach Temperature The approachtemperature is defined as the difference in the temperature of the boiler feedwater leaving the economizer section compared to the water in the steam drum. Calculating the "actual" approach temperature, and comparing it to the "as-designed" approach temperature is an effective tool in assessing performance in the "back end" of the HRSG, and indicates how well the economizer is operating.
  • 79.
    Approach Temperature To calculateapproach temp, simply find the saturation temperature at the steam-drum operating pressure, and subtract the temperature of the water leaving the economizer. Typical values for approach temperature range from 10F to 40F, depending on the operating status of the HRSG. In many plants, the approach temperature can be determined directly from panel data in the control room.
  • 80.
    Approach Temperature Variables Ambienttemperature can significantly affect the approach temperature, as a direct function. As the ambient temperature decreases, the approach temperature will also decrease, indicating that the economizer outlet temperature is getting closer to saturation and the risk of steaming within the economizer is growing. Conversely, as ambient temperature increases, so does the approach temperature, indicating that economizer effectiveness is decreasing.
  • 81.
    Low Approach Temp Ifthe calculated approach temperature is low--less than 10F--it may indicate economizer steaming or poor evaporator performance. Since most HRSG economizers are either panels or serpentine style, unintended steaming can create major problems. It may cause water hammer and can vapor-lock some economizer circuits, causing high local velocities in some tubes and performance degradation of the entire economizer section
  • 82.
    High Approach Temp Ifthe calculated approach temperature is high-more than 10F above the "as-designed" approach temperature-it may indicate economizer under- performance.
  • 83.
    Economizer under-performance isone of the most common HRSG performance problems, and has many possible causes, including: • Gas bypass. Some of the exhaust gas takes an alternative path around the finned tube surface; this is usually due to poor baffling. Economizer Under-Performance • Tube outer-surface problems. Fins are damaged; tubes and fins are fouled by debris or precipitate from an upstream source; or tubes and fins are corroded.
  • 84.
    Economizer under-performance isone of the most common HRSG performance problems, and has many possible causes, including: • Tube inner-surface problems. Deposits on the inner surface of the tubes lowers the heat transferred to the water. Economizer Under-Performance • Air/vapor pockets. Vapor left over from steam during startup or at other operating points can cause tube circuits to be blocked. Similarly, trapped air left in upper return bends after filling the HRSG with water can cause tube circuits to be blocked.
  • 85.
     Low watervelocity. When tube velocities within the economizer are low, stagnation or areas of recirculation can develop, which effectively reduce the economizer heat-transfer area. (Power, November/December 2000, p 64) Economizer Under-Performance Economizer under-performance is one of the most common HRSG performance problems, and has many possible causes, including:  Improper use of full or partial economizer bypass.
  • 86.
    Pinch Temperature Pinch temperatureis defined as the difference between the exhaust-gas temperature leaving the evaporator and the saturation temperature within the evaporator tubes. The pinch temperature indicates whether the evaporator section is absorbing as much heat as predicted. Typical pinch temperatures range from 15 to 30F. Note: The pinch temperature can not always be measured with installed instrumentation. If the pinch is not being measured at your site, a temporary gas-side thermocouple can be installed while the HRSG is on-line to enable you to make the calculation.
  • 87.
    Pinch Temperature Variables Ifthe inlet-air conditions to the gas turbine are not controlled, the ambient temperature will change the calculated pinch temperature. In general, the Pinch will react inversely with ambient temperature: As the ambient temperature increases, the pinch temperature will go down; as the ambient temp decreases, the pinch temp will go up. Note: As the pinch temperature increases, the exhaust-gas temperature leaving the evaporator section is increasing, sending more energy to the heat-transfer surfaces located downstream.
  • 88.
    Low Pinch Temp Ifthe pinch temperature is slightly low, the evaporator is probably working better than designed. It is unlikely that the calculated pinch temperature will be significantly lower than the design, especially if the duct burners are not firing (or don't exist). At a low pinch temp, approximately 15F, there is not enough temperature differential between the hot exhaust gas and the water being boiled to drive much more heat transfer.
  • 89.
    High Pinch Temp Ifthe pinch temperature is high, it may indicate an under- performing evaporator section.
  • 90.
    Some Common Causesof a High Pinch Temp:  Gas bypass. Some of the exhaust gas takes an alternative path around the finned tube surface; this is usually because of poor baffling.  Tube outer-surface problems. Fins are damaged; tubes and fins are fouled by debris or precipitate from an upstream source; or tubes and fins are corroded.  Tube inner surface fouling.
  • 91.
    Stack Temperature  Thestack temperature, defined as the temperature of the exhaust gas as it exits the HRSG, is an indicator of the overall performance of the HRSG.  The stack temperature is dependent on many factors, including the ambient temperature, rate of supplementary duct firing, and feedwater temperature.
  • 92.
    Counter-Intuitive ?  Ifthe gas-turbine inlet-air conditions are not controlled, the stack temperature will decrease as the ambient temperature rises. This is counter-intuitive; especially since steam flow from the HRSG will decrease as the ambient temperature rises.
  • 93.
    Counter-Intuitive?  Finally, itis somewhat common for an economizer or pre-heater to be the last section of heat-transfer surface before the exhaust gas exits the HRSG. For this reason, the incoming feedwater temperature can have a major impact on the stack temperature. Of course, the higher the feedwater temperature, the higher the stack temperature.
  • 94.
    High Stack Temp High stack temperatures indicate overall under- performance by the HRSG. Be sure to verify the reference conditions when comparing an actual stack temperature to the predicted value. If you find that your stack temperature is too high, immediately check the approach and pinch temperatures. The most common causes of high stack temperatures are gas bypass and external fouling of the finned tube surface.
  • 95.
    Low Stack Temp A low stack temperature typically indicates that the energy absorbed by the HRSG exceeds predictions
  • 96.
    Stack Temp ConsistentlyLow? Check the Following:  Is the feedwater source temperature lower than expected?  Calculate the water dew point of the exhaust gas to determine if condensation is a threat.  Check the exhaust gas acid dew point, especially if using a fuel other than natural gas.
  • 97.
    Stack Temp ConsistentlyLow? Check the Following:  Verify proper operation of the economizer, or pre-heater bypass if one exists.  Verify that operating pressures of the deaerator and low-pressure evaporater are not too low. Operating at pressures lower than design can cause flow- accelerated corrosion and deaerator performance problems
  • 98.
    Principal Threats toHRSG Reliability are:  Low-cycle thermal fatigue, particularly in high- pressure (h-p) superheaters, HP steam drums and evaporator circuits, and low-temperature economizers.  Corrosion-related problems, which include flow- accelerated corrosion, cold-end gas-side corrosion, and pitting from oxygenated feedwater.  Other thermal-mechanical problems--such as failures of casings and expansion joints. These components typically receive less attention than pressure parts, but can cause persistent operation and maintenance (O&M) challenges.  Other issues--most notably stratification of flue gas during prestart purge of the HRSG.
  • 99.
    Quenching damage  Inaddition to severe heating ramps, superheaters are vulnerable to quench cooling by condensate  Condensation occurs in superheater tubes during every purge of the HRSG prior to gas-turbine ignition.  Quantities of condensate are substantial during hot and warm starts.  A repeat purge can actually fill the front panel tubes of the superheater.
  • 100.
    1. Extensive temperature monitoringconfirmed that a substantial quantity of condensate formed in superheater tubes during gas-turbine purging, even in large-bore headers. Quenching Damage 2. Condensate began to clear from superheater tubes once steam flow commenced.
  • 101.
    4. Condensate clearsfirst from the tubes closest to the end-pipe connections, creating temperature differences between individual tubes along the headers. 3. A single, small-bore drain, opened during purging, reduces the quantity of condensate, but does not completely eliminate it. Quenching Damage
  • 102.
    Two Problems CausedBy Quench  First: Condensate which is possibly still subcooled is ejected in large quantities into the outlet header and pipe manifold where it quench cools hotter material. (On hot restarts after trips, the outlet header and manifold can be more than 360F above saturation temperature.)
  • 103.
    • Second: Individualtubes experience different average temperatures--because they do not clear of condensate simultaneously. Two Problems Caused By Quench Designs that have stiff tube arrangements connected to headers at each end develop significant tensile and compressive loads when at different temperature relative to other tubes.
  • 104.
  • 105.
    Why NOx Reduction? N02 can irritate the lungs, cause bronchitis and pneumonia, and lower resistance to respiratory infections.  Nitrogen Oxides are a precursor to ozone(03)which is the major component of smog.
  • 106.
    The Clean AirAct of 1967, amended in 1970, 1977 and again in 1990, authorizes the EPA to establish standards for atmospheric pollutants, including sulfur dioxide (SO2) and nitrous oxides (NOX). When NOX and volatile organic compounds enter the atmosphere, they react in the presence of sunlight to form ground-level ozone, a major constituent of smog. The current National Ambient Air Quality Standard (NAAQS) for ozone is 0.12 ppm. Areas where the ambient air ozone concentration (averaged over a three year period) is above 0.12 ppm are considered nonattainment areas. Why NOx Reduction?
  • 107.
    Power plants locatedin nonattainment areas are required to implement measures to minimize pollutant emission. Pollution controls for Pilloti consists of a Carbon Monoxide (CO) Catalyst and a Specific Catalytic Reduction (SCR) system. Why NOx Reduction?
  • 108.
    Selective Catalytic Reduction •There are two major chemical reactions that take place in NOx reduction: • 4NO + 4NH3 + O2 = 4N2 + 6H2O • The first reaction is most dominant. It shows a one to one relationship between NO and NH3 and also NO2 is harder to break down. • 2NO2 + 4NH3 + O2 = 3N2 + 6H2O
  • 109.
    F l ue G a s C l e a n G a s N O x N O x N O x N O x N H 3 N H 3 C a t a l y s t B e d N H 3 N H 3 N H 3 N 2 H 2 O N 2 H 2 O Selective Catalytic Reduction
  • 110.
    Selective Catalytic Reduction •Aqueous ammonia is pumped into a vaporization tank where it is mixed with a heated air supply and sent into the spray manifold inside the HRSG. • The ammonia spray is absorbed in the active sites on the catalyst bed. The flue gas passes over those same sites where the NOx reacts and forms N2 and H2O. • The active catalyst is a combination of different transition metal oxides formed into either a honeycomb or flat plate shape. This construction material lowers the activation energy required to initiate the chemical reaction.
  • 111.
    Selective Catalytic Reduction •When fossil fuels are burned at high temperatures nitric oxide (NO) is formed. When left untreated it oxidizes in the atmosphere forming NO2, that irritates the lungs and can cause respiratory problems. • SCR is a post combustion process that reduces the NOx found in exhaust gasses to molecular N2 and H2O. • Generally located downstream of the HP evaporator section, the system can potentially remove 90% of the NOx from the flue gas.
  • 112.
  • 113.
  • 114.
    Stack SCR Box HP Steam Drum LP Steam Drum and De-aerator IP Steam Drum LPEcon#1 LPEcon#2 IPEcon LPEcon#2 LPEcon#2 LPEvap#1 IPEvap#1 LPEvap#3 LPEvap#2 HPEvap#2 HPEcon#2 HPEcon#1 IPEvap#1 HPEcon#3 HPEcon#4 HPEcon#4 HPEcon#3 HPSuperheater#5 IPSuperheater HPEvap#1 HPEvap#1 HPEvap#1 HPSuperheater#4 HPSuperheater#3 HPSuperheater#2 HPSuperheater#1 Reheater#1 Reheater#2 GTExhaust Gas Flow AIG (Ammonia Injection Grid) NH3 Injection Hot Flue Gas to SCR Skid SCR Skid The hot flue gases are taken from the SCR Box and fed to the SCR Skid Ammonia (NH3) is mixed with hot flue gases to ensure complete evaporation and then fed into an Ammonia Injection Grid. The SCR Skid provides the components to mix the flue gases with the Ammonia. The hot flue gases and gaseous ammonia are returned to the gas stream through the Ammonia Injection Grid. The AIG is little more than a grid of pipes with injection holes. There are butterfly valves and orifices for adjusting the ammonia injection rate over different zones of the gas path cross-section.
  • 115.
    Aqueous Ammonia Vaporizer Return to AIG VSD Panel VSD Panel Aqueous Ammonia FCV XCV Instrument Air PRV HotFlue Gas Fans Hot Flue Gas From SCR Box The hot flue gases mix with Aqueous Ammonia in the Aqueous Ammonia Vaporizer . To ensure complete vaporization of the ammonia, it is atomized by forcing it through a mixing nozzle with Instrument Air. The mixture of flue gases and ammonia is then returned to the AIG.
  • 116.
    VSD Panel VSD Panel Hot Flue Gas Fans HotFlue Gas From SCR Box Two 100% capacity Variable Speed Fans are provided to draw the hot flue gases from the SCR Box and inject them into the Aqueous Vaporizer. One fan is selected for service while the other remains in standby.
  • 117.
    The rate ofammonia injection must be closely controlled for two reasons. The first is to ensure that NOX emissions are less than limits. In this case we limit our Stack NOX concentrations to less than 2 ppm. The second is to limit ammonia leakage to less than 10 ppm at the stack exit. Unreacted NH3 in the flue gas downstream of the SCR is called Ammonia Slip. It is necessary to limit the amount of ammonia slip to minimize the formation of (NH4)SO4 and NH4HSO4 which can cause plugging and corrosion of downstream equipment. This is not a problem when the Gas Turbines are using gas as the fuel. However, we must use low sulfur oil or minimize ammonia slip when oil is the fuel.
  • 118.
    3. Regulation ofammonia flow rate to meet the calculated necessary flow rate. Control of the ammonia injection rate has four major considerations: 1. Determination of how much ammonia should be injected to achieve the desired NOX emission limits. 2. Determination of how much gas flow is required through the vaporizer to achieve the required dilution. 4. Regulation of the gas flow rate through the vaporizer to meet the calculated required dilution flow.
  • 119.
    Inlet NOX Set Value Σ _ + Determination ofhow much ammonia should be injected to achieve the desired NOX emission limits is fairly complex. It starts by comparing the actual NOX concentration at the inlet to the HRSG to a set value controlled by the operator.
  • 120.
    Inlet NOX Set Value Σ _ + Mol. Rate ƒ The differencebetween the Set Value and the measured concentration at the HRSG inlet is fed to a function generator which calculates a molar ammonia flow rate.
  • 121.
    However this functiongenerator assumes that the O2 concentration is 15%. If the actual O2 concentration is anything else, the calculated value for ammonia flow rate will be incorrect. We therefore introduce a correction factor to compensate for O2 concentrations other than 15%. Inlet NOX Set Value Σ _ + Mol. Rate ƒƒ Stack O2 GT Flue Gas Flow Rate X Actual NOX Flow Rate X Feed Forward
  • 122.
    The actual NOXflow rate is calculated by multiplying the compensated Inlet NOX concentration by the GT flue gas flow rate. The actual NOX flow rate is then multiplied by the Mol. Rate to obtain the Feed Forward Signal
  • 123.
     The FeedForward signal is essentially a desired ammonia flow rate and it can be fed to the air  pressure regulator for the NH3 Flow Control Valve. However, systems never work perfectly so we must have an ammonia flow rate feedback signal to ensure that the FCV opens to the correct position. The feedback signal is derived by measuring the actual ammonia flow rate downstream of the FCV and the difference between actual and desired flow rates is used to control the FCV. The Feed Forward signal can tell the FCV to open to a specified percentage and if all design assumptions are actually met, we should obtain the correct flow rate.
  • 124.
    Inlet NOX Set Value Σ _ + Mol. Rate ƒƒ Stack O2 GTFlue Gas Flow Rate X Actual NOX Flow Rate X Feed Forward Aqueous Ammonia FCV Σ + _ FT
  • 125.
    Inlet NOX Set Value Σ _ + ƒƒ Stack O2 GTFlue Gas Flow Rate X Actual NOX Flow Rate X Aqueous Ammonia FCV Σ + _ FT To ensure that the desired reduction is obtained and that NOX emissions remain within limits, we use another feedback signal; this one looking at actual stack NOX levels. Gain Σ Set Value Stack NOX + _
  • 126.
    The entire controlscheme discussed so far provides rapid response to changes in the GT flue gas NOX concentration. However it assumes that if we inject the correct ammonia flow based on the NOX at the HRSG inlet we will obtain the desired reduction in NOX at the stack. That assumption may not always be valid. This feedback signal adjusts the gain of the Feed Forward signal to compensate for any difference between the operator determined Set Value and the measured Stack NOX concentration.
  • 127.
    The Variable Speedfans have two operating modes, VSD control and Gas Temperature control. VSD control is initiated by the DCS when the Gas Turbine starts firing and the SCR temperature starts to increase. Flue Gas Temperature Fan Speed Standby Fan @ 700 RPM Main Fan @ 2540 RPM Main Fan @ 2000 RPM 293 °F 122 °F VSD Control
  • 128.
    When the flowrate of the Hot Flue Gas is sufficient, the isolation valve for the ammonia injection opens and ammonia flow control switches to Auto. Fan speed control switches to Gas Temperature mode. From this point, fan speed is regulated by SCR inlet temperature. Flue Gas Temperature Fan Speed Standby Fan @ 700 RPM Main Fan @ 2540 RPM Main Fan @ 2000 RPM 293 °F 122 °F VSD Control
  • 129.
    At 293 °F,the Main Fan reaches its maximum VSD operating speed of 2540 RPM. The fan speed will remain at this value regardless of further increase in SCR temperature as long as the fans remain in VSD control mode. VSD Control is used to start and accelerate the fans to obtain a controlled heat-up of the fan bearings and to ensure that the fan motors do not overload.
  • 130.
    HRSG/SCR Failure –Cause & Prevention
  • 131.
    Problems Common forSCR Systems  Increase in NOx Emission Rate  Reduction of NOx Conversion  Efficiency/Catalyst Degradation  Increase in Catalyst Pressure Drop  Increase in Ammonia Slip  Plugging of Ammonia Supply System  Plugging of Downstream Equipment
  • 132.
    Causes of HighNOx Emissions  Sources of NOx Emission Increase  Decrease in Catalyst Activity  Catalyst Degradation Higher than expected NOx emissions from combustion turbine  Imbalance Between Ammonia Injection and NOx Distribution  Flue Gas Leakage Around Catalyst
  • 133.
    Solutions to NOxEmission Increases  Clean catalyst (if catalyst OP has also increased)  Reduce NOx emissions from combustion turbine or duct burner.  Clean / Adjust the AIG to match the NOx distribution  Reduce gas leakage around catalyst by inspecting and maintaining support frame sealing system and catalyst packing.  Sample / Replace Catalyst
  • 134.
    Sources of CatalystDegradation  Operation Above Design Temperature  Decreases available surface area by thermal sintering of reaction sites.  Operation Below Design Temperature  Decreases available surface area by plugging reaction sites with ammonia-sulfur compounds.  Particulate Matter- Decreases available surface area by plugging reaction sites.  Poisoning- Some Chemicals such as Sodium, Potassium, Halogen, Calcium, Magnesium, Arsenic, Silica, etc. will reduce conversion efficiency.
  • 135.
    Solutions to CatalystDegradation  Try not to exceed maximum operational temperature of catalyst.  Inject ammonia only after the catalyst has reached the minimum operating temperature - preventing ammonium-sulfur compound deposits on the catalyst face.  Use a vacuum, compressed air, or steam to remove particulate from the catalyst.  Contact manufacturer if catalyst surface comes in contact with water.  Sample catalyst annually.
  • 136.
    Sources of CatalystPressure Drop  Insulation Particulate  Ammonia-Sulfur Compounds  And yes... Even Liner Plates
  • 137.
    Solutions to CatalystPressure Drop  Use a vacuum, compressed air, or steam to remove particulate and insulation from the catalyst. Use care not to damage catalyst.  Operate the catalyst above the ammonium- sulfur compound recovery temperature to evaporate the salts.
  • 138.
  • 139.
    Ammonia Slip  FlueGas Leakage Around Catalyst  Decrease in Catalyst Activity  Imbalance Between Ammonia Injection and NOx Distribution
  • 140.
    Ammonia Slip -Solutions  Clean Catalyst  Clean / Adjust the AIG to match the NOx distribution  Reduce gas leakage around catalyst by inspecting and maintaining support frame sealing system and catalyst packing.  Sample / Replace Catalyst
  • 141.
    Causes for AmmoniaSupply Plugging  Particulate Mill Scale  Ammonia-Sulfur Compounds
  • 142.
    Solutions to AmmoniaSupply Plugging  Install filters to remove particulate and mill scale.  Utilize aqueous ammonia that is free of suspended solids.  Clean piping utilizing compressed air or steam to remove mill scale.  Time, combined with the ammonia flow will also eventually remove mill scale.  Operate the system above the salt formation temperatures to prevent ammonia-sulfur compounds from forming.
  • 143.
    Anhydrous Ammonia  Advantages:Low auxiliary heat input, small dilution air fans, no NH3 salts.  Disadvantages: Hazardous substance - special operational / handling requirements.
  • 144.
    Aqueous Ammonia -Hot Gas Recirculation  Advantages: "No" auxiliary heat input, minimal handling requirements.  Disadvantages: Large "hot" dilution air fans , NH3 salt concerns.
  • 145.
    Source of DownstreamTube Plugging  The ammonia slip combines with sulfur and condenses as ammonium bisulfate on the "cold" tubes. This salt buildup will eventually interfere with the HRSG heat transfer and increase the combustion turbine back pressure.
  • 146.
    Solution to DownstreamTube Plugging  Reduce Sulfur Content of Fuel  Reduce Ammonia Slip  Periodic Cleaning (Water Washing, Compressed Air)
  • 147.
    Stack HP Steam Drum LP Steam Drum and De-aerator IP Steam Drum LPEcon#1 LPEcon#2 IPEcon LPEcon#2 LPEcon#2 LPEvap#1 IPEvap#1 LPEvap#3 LPEvap#2 HPEvap#2 HPEcon#2 HPEcon#1 IPEvap#1 HPEcon#3 HPEcon#4 HPEcon#4 HPEcon#3 HPSuperheater#5 IPSuperheater HPEvap#1 HPEvap#1 HPEvap#1 HPSuperheater#4 HPSuperheater#3 HPSuperheater#2 HPSuperheater#1 Reheater#1 Reheater#2 IPSuperheater COCatalyst Grid GT Exhaust Gas Flow The CO Catalyst Grid consists of several 2ft by 2ft converter modules. Each module contains a honeycomb core made of stainless steel foil and covered with the active catalyst materials Al2O3 and Pt. These materials participate in intermediate stages of the reaction but are not consumed. The CO Catalyst Grid is mounted in the HRSG between #1 and #2 HP evaporators. The chemical reaction which occurs is 2CO + O2 → 2 CO2 There are no controls required for the CO Catalyst Grid. The only requirement for the reaction to occur is a temperature above 500 °F and an excess of oxygen.
  • 148.
    The EPA hasplaced limits on the emission of various airborne pollutants which result from the use of fossil fuels. The two contaminants of most concern are the different compounds of nitrogen and oxygen, and carbon monoxide. Carbon monoxide is easily controlled by passing it over a catalyst bed of Al2O3 and Pt. This control method requires no electronics or support equipment. The reaction will proceed as long as CO is present at the catalyst surface, the ambient temperature is greater than 500 °F and there is an excess of O2. The CO catalyst is mounted in the HRSG between #1 and #2 HP evaporators. SummarySummary
  • 149.
    SummarySummary This control methodrequires precise regulation of the ammonia injection rate. The components used to regulate the ammonia injection rate are mounted on the SCR skid, located near the HRSG inlet. The major components involved are the Hot Flue Gas Fans, the Aqueous Ammonia Vaporizer, the instrument air pressure supply to the Vaporizer, and the Ammonia flow controller. NOX is controlled by injecting ammonia into the gas steam upstream of the SCR. In the SCR, the NH3 reacts with the NOX to form N2 and harmless water vapor. These reactions will proceed at normal HRSG operating temperature if a catalysts are present. The catalysts are oxide forms of titanium, vanadium, and tungsten.
  • 150.
    SummarySummary These components willwork together to supply the correct ammonia flow to the Ammonia Injection Grid. The AIG is a network of pipes and injection holes located in the HRSG just upstream of #2 HP evaporator.