Basic ccpp overview Power plant

Ras Laffan CCCP Introduction
Manual

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

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
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?

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

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.

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.
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.
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

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 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.

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
Temp – 591.7 °F

LP Steam Drum &
De-aerator
LPEcon1&2
LPEvap
LPSuperhtr
LP Superhtr
Feedwater
Pump
Recirc
Feedwater
Condensate
LP Steam
From LP
Steam Drum
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
Temp – 546.9 °F

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
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.
Temp – 634.7 °F
85.5 °F
Temp – 599.6 °F
Temp – 1,052.0 °F
Flow – 310
lbm/hr

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
typical 100% values
operating at maximum load
and a feedwater inlet
Temp – 613.1 °F
80.7 °F
Temp – 623.3 °F
Temp – 1,010.2 °F
Flow – 310
lbm/hr

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
typical 100% values
operating at maximum load
and a feedwater inlet
Temp – 642.6 °F
82.0 °F
Temp – 571.0 °F
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
85.5 °F
Temp – 1,052.3 °F

HP Steam Drum
A
HP Feedwater
HP Feedwater
HP
Steam
HPEvap1&2
HPEcon1&2
HPEcon3
HPEcon4
HPSuperhtr1-3
HPSuperhtr4&5
100% values assuming 2 Gas
Turbines operating at maximum
load and a feedwater
80.7 °F
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.
82.0 °F
Temp – 1,019.7 °F
Flow – 0 lbm/hr
HP System Parameters

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.

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.

including:
• Tube inner-surface problems. Deposits on the inner
surface of the tubes lowers the heat transferred to the
water.
• 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)
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.

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

• 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.

• 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.

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.

Basic ccpp overview Power plant

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