IECSTD - Version 3.2
52 XXX ( CEI:1997
-
ISA-ds77.44.01-2006
Draft Standard
Fossil Fuel Power Plant -
Steam Temperature ControlsDraft 5
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Preface
This preface, as well as all footnotes and annexes, is included
for information purposes and is not part of
ANSI/ISA-77.44.01-2007.
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ISA(the Instrumentation, Systems, and Automation Society(toward a
goal of uniformity in the field of instrumentation. To be of real
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The following people served as members of ISA Subcommittee
SP77.44:
NAMECOMPANY
D. Lee, ChairmanABB Automation Inc.
W. Holland, Managing DirectorSouthern Company
L. AltchehIsrael Electric Corporation
D. ChristopherReliant Energy
D. Crow*TXU
D. FitzgeraldFoster Wheeler Energy Corporation
J. GleggCentral & South West
R. HubbyConsultant
G. KumarFichtner Consulting Engineers
J. LeeKorea Electric Power Company
G. McFarlandWestinghouse Process Control Inc.
R. McSpaddenVision Controls Company
R. PapillaSouthern California Edison Company
L. RawlingsPalm Beach Resource Recover Company
D. RoneyRaytheon Engineers & Constructors
M. SkonceyDuquesne Light Company
C. TaftElectric Power Research Institute
J. VavrekSargent & Lundy Inc.
D. Wade*TXU Electric
The following served as members of the ISA SP77 Committee:
NAMECOMPANY
W. Holland, Managing DirectorSouthern Company
E. Adamson*Foxboro Company
L. AltchehIsrael Electric Corporation
S. AlvarezCompania Inspeccion Mexicana
J. BatugPennsylvania Power & Light Company
L. BroekerConsultant
Q. ChouConsultant
D. ChristopherReliant Energy
D. CrowTXU
F. CunninghamSwagelok Company
G. DavisDuke Power Company
D. ForemanBrown & Root Energy Services
W. FrymanIllinois Power Company
K. GabelCenterior Energy
A. GilePotomac Electric Power Company
R. Hicks*Black & Veatch
R. HubbyConsultant
R. JohnsonSargent & Lundy Engineers
J. KennardOntario Hydro
J. Kling*Black & Veatch
G. KumarFichtner Consulting Engineers
D. LeeABB Automation Inc.
W. Matz*Foxboro Company
G. McFarlandWestinghouse Process Control Inc.
R. McSpaddenVision Controls Company
G. MookerjeeU.S. Department of Energy
N. Obleton*Honeywell Inc.
R. PapillaSouthern California Edison Company
G. RamachandranCytec Industries Inc.
L. RawlingsPalm Beach Resource Recover Company
D. RoneyRaytheon Engineers & Constructors
R. RoopHoosier Energy Inc.
A. SchagerVitec Inc.
T. StevensonBaltimore Gas & Electric Company
C. Taft*Electric Power Research Institute
D. TennantInternational Applied Engineering
B. TraylorGE Instrument Control Service
J. Weiss*Electric Power Research Institute
D. Younie*Woodward Global Services
F. ZikasParker Hannifin Corporation
T. Zuvlis*Woodward Global Services
This standard was approved for publication by the ISA Standards
and Practices Board on _________________________.
NAMECOMPANY
M. ZielinskiFisher-Rosemount Systems, Inc.
D. BishopConsultant
P. BrettHoneywell, Inc.
M. CohenSenior Flexonics, Inc.
M. CopplerAmetek, Inc.
B. DumortierSchneider Electric SA
W. HollandSouthern Company
A. IversonIvy Optiks
R. JonesDow Chemical Company
V. MaggioliFeltronics Corporation
T. McAvinewInstrumentation & Control Engineering LLC
A. McCauley, Jr.Chagrin Valley Controls, Inc.
G. McFarlandHoneywell, Inc.
R. ReimerRockwell Automation
J. RennieFactory Mutual Research Corporation
H. SasajimaAdvanced Architecture and Technologies
R. WebbAltran Corporation
W. WeidmanParsons Energy & Chemicals Group
J. WeissEPRI
J. WhetstoneNational Institute of Standards & Technology
M. WidmeyerEG&G
R. WiegleCANUS Corporation
C. WilliamsEastman Kodak Company
G. WoodGraeme Wood Consulting
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Table of Contents
101Purpose
102Scope
103Definitions
124Process measurement requirements
124.1Instrument installations for superheat and reheat steam
temperature control
134.2Design of thermocouples and temperature sensors
134.3Isolation valves and impulse lines
134.4Process measurements for superheat and reheat steam
temperature control
145Attemperation Methods Control and logic requirements for an
attemperator control system for control of steam temperatures
155.1Single-stage attemperation
165.2Two-stage attemperation
175.3Multiple-stage attemperation
175.4Attemperator spray and block valve logic
186Control and logic requirements for a reheat steam temperature
control by means of heat distribution
186.1Fuel nozzle tilts
196.2Flue gas pass dampers
196.3Flue gas recirculation
206.4Compartmented windbox
206.5Single-stage spray water attemperation
207Superheat control and logic requirements for once through
type boilers
217.1Firing rate-feedwater flow ratio control
227.2Attemperator control
228Common design requirements
228.1Automatic tracking
228.2Integral windup prevention
228.3Final control element requirements
228.4System reliability and availability
238.5Minimum alarm requirements
238.6Operator interface
25A.1References
27B.1Purpose
27B.2Introduction
28B.3Requirements
30B.4Principles and methods of steam temperature control
31B.5Saturation protection/water induction
32B.6Two-stage attemperation
32B.7Use of cascade spray valve control
32B.8NOx control
33B.9Redundancy
33B.10Reset windup prevention
34B.11Advanced steam temperature control
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Forward
A variety of steam temperature control systems have been
developed over the years to fit the needs of particular
applications. Operating philosophy, plant layout, and type of
firing must be considered before the ultimate selection of a system
is made. Therefore, this standard is not intended to limit the
complexity or scope of the steam temperature control system design
that one might wish to implement, but rather to establish a minimum
of control needed.
This standard is part of a series resulting from the efforts of
the SP77 Committee on Fossil Power Plant Standards, especially
subcommittee SP77.40 on Boiler Controls. It should be used in
conjunction with the other SP77 series of standards for safe,
reliable, and efficient design, construction, operation, and
maintenance of the power plant. It is not the intent of this
standard to establish any procedures or practices that are contrary
to any other standard in this series.1 Purpose
The purpose of this standard is to establish the minimum
requirements for the functional design specification of steam
temperature control systems for drum type and once-through type
fossil fuel power plant boilers.
2 Scope
The scope of this standard addresses the major steam temperature
control subsystems in boilers with steaming capacities of
200,000lb/hr (25kg/s) or greater. These subsystems include, but are
not limited to, superheat temperature control and reheat
temperature control. Specifically excluded from consideration are
controls associated with fluidized-bed, stoker-fired furnace
combustion units and mud drum desuperheaters.
3 Definitions
The following definitions are provided to clarify their use in
this standard and may not be relevant to the use of the words in
other texts. For other definitions, please refer to
ANSI/ISAS51.11979 (R1993) Process Instrumentation Terminology.
3.1attemperator:
a device used for maintaining and controlling the temperature of
superheated steam.
3.2attemperator (direct contact type):
a device in which the steam and the cooling medium (water) are
mixed.
3.3boiler:
the entire vessel in which steam or other vapor is generated for
use external to the vessel. This includes the furnace, consisting
of waterwall tubes; the firebox area, including burners and
dampers; the convection area, consisting of any superheater,
reheater, economizer sections or any combination thereof, as well
as drums and headers.
3.4cascade control system:
a control system in which the output of one controller (the
outer loop) is the setpoint for another controller (the inner
loop). The outer loop is normally a slow responding process than
the inner loop.
3.5control loop:
a combination of field devices and control functions arranged so
that a control variable is compared to a setpoint and its output
returns to the process in the form of a manipulated variable.
3.6controller:
any manual or automatic device or system of devices used to
regulate a process within defined parameters. If automatic, the
device or system responds to variations in a process variable.
3.7desuperheater (direct contact type):
a device in which the steam and the cooling medium (water) are
mixed.3.8deviation:
the difference between the loop setpoint and the process
variable (also called error).
3.9error:
see 3.9 deviation.
3.10feedback:
a concept in which a process measurement in used to determine
whether the control variable is at the desired value. A signal
produced by a measuring device that is proportional to the
magnitude of a controlled variable or position of a control
element.
3.11final control element:
component of a control system (such as a control valve) that
directly regulates the flow of energy or material to or from the
process.
3.12gas pass:
an arrangement in which the convection banks of a boiler are
separated by gas-tight baffles into two or more parallel gas paths
isolating portions of the superheater and reheater surfaces. The
proportion of total gas flow through each gas pass may be varied by
regulating dampers.
3.13gas recirculation:
a method by which flue gas from the boiler, economizer, or air
heater outlet is reintroduced to the lower furnace to reduce
furnace heat absorption while increasing convection pass heat
absorption or to reduce NOx emission.
3.14integral control action:
an action in which the controller's output is proportional to
the time integral of the error input. It is also called reset
action.
3.15integral windup:
the saturation of the integral controller output in the presence
of a continuous error, which may cause unacceptable response in
returning the process to its setpoint within acceptable limits of
time and overshoot.
3.16interlock:
a device or group of devices (hardware or software) arranged to
sense a limit or off-limit condition, or improper sequence of
events, and to shut down the offending or related piece of
equipment, or to prevent proceeding in an improper sequence in
order to avoid an undesirable condition.
3.17linearity:
the nearness with which the plot of a signal or other variable
plotted against a prescribed linear scale approximates a straight
line.
3.18master fuel trip:
An event resulting in the rapid shutoff of all fuel including
igniters.
3.19primary air:
combustion air that enters the fuel-burning zone and directly
supports initial combustion. On pulverized coal-fired units, the
primary air is used to transport the coal from the pulverizers to
the burners.
3.20reheater:
a heating surface receiving steam returning to the boiler from
the high-pressure turbine exhaust.
3.21secondary air:
combustion air introduced on the edge of the burning zone to
supplement the primary air for support of the combustion
process.
3.22setpoint:
the desired operating value of the process variable.
3.23superheater:
boiler heating surface that is not part of the boiler enclosure
which receives only steam already at or above its saturation
temperature. (See Figure 3.26.a and Figure 3.26.b for typical steam
and gas flow paths.)3.23.1 Intermediate Superheater - Section or
sections of superheating surface located between primary and
secondary superheaters.
3.23.2 Platen Superheater - Intermediate superheater surface
which is also a radiant superheater.
3.23.3 Primary Superheater - First boiler heating surface to
receive steam at or slightly above saturation temperature.
3.23.4 Secondary Superheater - Final stage of boiler
superheating surface.
3.23.5 Radiant Superheater - Steam superheating surface where
the primary means of heat transfer to the steam is by radiation
rather than convection. Typically, an intermediate superheater
section.
Figure 3.23.a - Typical Superheater Steam Flow Path
Figure 3.26.b - Typical Superheater Gas Flow Path3.24trip:
the automatic removal from operation of specific equipment or
the automatic discontinuance of a process action or condition as
the result of an interlock or operator action.
3.25transient correction:
a control action specifically applied to minimize any process
error resulting from a temporary process change; e.g., temperature
control action applied to counter the effects of over- or
under-firing during load changes.
4 Process measurement requirements
4.1 Instrument installations for superheat and reheat steam
temperature control
Instruments should be installed as close as is practical to the
source of the measurement, with consideration being given to
excessive vibration, ambient temperature, and accessibility for
periodic maintenance. Temperature measurement should be located at
least 20 pipe diameters downstream of any attemperator.
4.2 Design of thermocouples and temperature sensors
Design of thermocouples and temperature sensors shall meet the
requirements of ASME Power Test Code PTC19.3 Temperature
Measurements.
Design of the attachment of the thermowell to the pipe shall
meet the requirements of either ASME Boiler Pressure Vessel Code
Section I Power Boilers for Boilers or ASME B31.1 Power Piping Code
depending on the code jurisdiction for the pipe.
Thermowell installations shall consider location, mounting, and
velocity criteria in making a proper interface with the
process.
4.3 Isolation valves and impulse lines
Separate isolation valves and impulse lines shall be provided
for head-type instrumentation.
4.4 Process measurements for superheat and reheat steam
temperature controlProcess measurements for superheat temperature
control are listed below. For location of these measurements see
figures C.1a, C.1b, C.1c, and C.1d.
4.4.1 Secondary (final) superheater outlet steam temperature
measurementA temperature measurement, taken at the outlet of the
secondary (final) superheater, is required for superheat steam
temperature control strategies.
4.4.2 Secondary superheater inlet temperature measurementA
temperature measurement, taken at the attemperator outlet(s) for
single-stage or multiple-stage attemperation and followed by a
superheater section, is required as the secondary variable in a
cascade loop with feedforward control strategy.
4.4.3 Primary (initial, platen) inlet temperature
measurement
A temperature measurement, taken at the primary superheater
inlet (or outlet of the first stage attemperator of multiple-stage
attemperation), is required as the secondary variable in a cascade
loop with feedforward control strategy.
4.4.4 Primary (initial, platen) outlet temperature
measurement
A temperature measurement, taken at the outlet of the primary
superheater section before the first stage attemperator, is
required in a single or multiple-stage attemperator control
strategy.
4.4.5 Primary (initial, platen, intermediate) inlet pressure
measurementA pressure measurement is required in a multiple-stage
attemperator control strategy to prevent saturation following
first-stage spray attemperation. Typically, this pressure is
measured at the inlet of the primary superheater. A pressure
measurement is required in a two-stage attemperator control
strategy to prevent saturation following first-stage spray
attemperation. Typically, this pressure is measured at the inlet of
the intermediate superheater; however, drum pressure may be used if
primary superheaters pressure loss is considered.4.4.6 Intermediate
inlet temperature measurementA temperature measurement, taken at
the intermediate superheater inlet (or outlet of the first stage
attemperator of two-stage attemperation), is required as the
secondary variable in a three- element control strategy.
4.4.7 Intermediate outlet temperature measurement
A temperature measurement, taken at the outlet of the
intermediate superheater section before the second stage
attemperator, is required in a two-stage attemperator control
strategy.
4.4.8 Reheat steam temperature measurement
A temperature measurement, taken at the outlet of the final
reheater, is required for single loop and single loop with
feedforward reheat steam temperature control strategies for
modulation of the reheat steam temperature control mechanisms
provided by the boiler manufacturer.
4.4.9 Attemperator spray water-flow measurement
An attemperator spray water mass flow signal provides an
alternative to the use of the attemperator outlet steam temperature
as the secondary variable in a cascade loop with feedforward
control strategy.
4.4.10 Waterwall (convection pass) outlet temperature
measurement
A temperature measurement, taken at the outlet of the furnace
walls (convection pass) section and followed by a superheater
section, is required in a multiple-stage attemperator control
strategy.
5 Attemperation Methods Control and logic requirements for an
attemperator control system for control of steam temperatures
The function of the superheat temperature control system is to
maintain superheat steam temperature within the boiler
manufacturer's specified limits. Generally, the goal is to obtain a
specified final superheat steam temperature over the specified
boiler-load range. Control strategy must be based on the particular
control mechanisms used and the boiler manufacturer's philosophy
for controlling steam temperature. Although the strategies in this
standard use conventional PID control techniques, it is not the
intention to preclude the use of advanced control strategies. Refer
to Table B.1 for summary of typical control systems.For the control
of superheat steam temperature, this standard addresses
single-stage attemperation and two-stage attemperation. For typical
boiler superheater attemperation arrangements, see FiguresC.1a and
C.1b.
Single loop steam temperature control is the minimum control
strategy for reheat steam temperature leaving the boiler and shall
be used only for applications where reheat spray is the secondary
means of reheat temperature control.
Referring to FigureC.9, reheat steam temperature is measured and
compared to a setpoint. The setpoint bias in Figures C.5C.8, which
is used to slightly increase the setpoint above the setpoint of the
primary controlling mechanism, is summed with the reheat
temperature error to develop the final error signal. Proportional
and integral control action, along with a automatic/manual station
function, completes the control scheme to regulate the valve.
Single loop with feedforward and cascade loop with feedforward
steam temperature control strategy should be used in applications
where reheat spray is the primary method of reheat temperature
control; with variable steam pressures; and with variable spray
water pressure supplies.
5.1 Single-stage attemperation
Single-stage attemperation refers to the boiler design that
provides a single location for the introduction of spray water for
the regulation of steam temperature. This application is typical of
boilers with a single reheater section or a single superheat
section with the attemperation at the inlet. If a boiler has two
superheater sections in series, (i.e., the primary and secondary
superheaters) then it is normal to have the spray attemperation
located between the two superheater sections. Note that a single
attemperation location does not necessarily refer to a single set
of spray equipment because there may be more than one parallel path
for the steam leaving the drum.5.1.1 Single loop steam temperature
controlSingle loop steam temperature control is the minimum control
strategy required to regulate the steam temperature leaving the
boiler and should be used only in applications with slow load
changes (e.g., approximately 0.2%/min as in building heating system
or where constant steam temperature is not critical).
Referring to FigureC.2, final steam temperature is measured and
compared to a setpoint with the result used to regulate the spray
valve(s).
5.1.2 Single loop with feedforward steam temperature control
Single loop with feedforward steam temperature control strategy
shall be used only in applications with slow to moderate load
changes (e.g., < 1.0 %/min) and with steady spray water pressure
supply and fixed steam pressure applications.
Referring to FigureC.3, Single loop with feedforward steam
temperature control adds a feedforward signal and a transient
correction signal to the single loop control described in 5.1.1. As
a minimum, the feedforward signal is derived from a load index (or
indices). This feedforward signal should recognize all major
influences on steam temperature, including adjustments to heat
distribution within the boiler.
5.1.3 Cascade loop with feedforward steam temperature
control
Cascade loop with feedforward steam temperature control strategy
shall be used in applications with rapidly changing loads (e.g.,
> 1 %/min), with variable steam pressures or with variable spray
water pressure supplies.
The cascade loop with feedforward control strategy is applicable
only when attemperation takes place between two superheater
sections.
Referring to Figure C.4a and Figure 4b, cascade loop with
feedforward steam temperature control adds a cascade control
arrangement to the single loop with feedforward control strategy
described in 5.1.2 for the control of the spray valve. The single
loop with feedforward control strategy acts as the setpoint
development for the inner control loop of the cascade control
arrangement. The process variable for the inner control loop is a
monitor of the spray action. Although steam temperature immediately
after the attemperation is the preferred process variable, spray
water flow also may be used. As a minimum, the feedforward signal
is derived from a load index (or indices). This feedforward signal
should recognize all major influences on steam temperature,
including adjustments to heat distribution within the boiler.
For variable pressure operation, a suitable feedforward shall be
provided to reflect the influence of changes in the thermodynamic
properties of steam on the final steam temperature.
5.2 Two-stage attemperationTwo-stage attemperation refers to the
boiler design when spray attemperation is applied at two different
locations along the same steam path, typically between the primary
and intermediate superheaters and also between the intermediate and
secondary superheaters. There are two common approaches to
controlling a two-stage attemperation systemindependent systems or
coupled systems. Consideration should be given to the boiler
manufacturer's recommendations when selecting a control
strategy.
5.2.1 Independent two-stage controlIn the independent system,
the first-stage attemperator is used to control the outlet
temperature of the intermediate superheater. The second-stage
attemperator is used to control the final outlet temperature.
Referring to Figure C.2, the setpoint for the first-stage control
loop usually is a fixed value dependent on the metal temperature
limits of the intermediate superheater. A single loop control is
the minimum system required for the first stage. Referring to
Figure C.4, the setpoint for the second-stage control loop is
operator set. A cascade control scheme using final outlet
temperature as the primary process variable and either the
second-stage attemperator outlet temperature or spray water flow as
the secondary process variable is the minimum system required for
controlling the final outlet temperature.
Feed-forward signals usually are required to obtain satisfactory
transient control performance from a steam temperature control
loop. In the independent strategy, the feed-forward signals are
used only on the final outlet temperature control loop, where they
are added to the outlet of the primary controller. The exact
arrangement of the feedforward signals must be determined on a
case-by-case basis. As a minimum, the feedforward signal is derived
from a load index (or indices). This feedforward signal should
recognize all major influences on steam temperature, including
adjustments to heat distribution within the boiler. Some common
feedforward signals include load index, heat distribution signals
(fuel nozzle tilt positions), fuel flow, and air flow.
5.2.2 Coupled two-stage control
In the coupled two-stage control strategy, the total spray
attemperator demand is distributed between both stages of
attemperation. Referring to Figure C.5, cascade loop with
feedforward XE "three-element control" control is the minimum
system required for the coupled two-stage attemperation to maintain
the superheat steam temperature setpoint. The load index (or
indices) feedforward signal is summed with a transient signal(s)
and a final steam temperature feedback controller signal to develop
a total spray attemperator demand. This feedforward signal should
recognize all major influences on steam temperature, including
adjustments to heat distribution within the boiler.
The individual spray attemperator demand is distributed between
both stages of attemperation. The individual spray demands are
developed from the spray distribution and coordination control
strategy as determined from the boiler manufacturer's
recommendations and specifications or as process constraints
dictate. Both valves shall participate during transient boiler
operation to minimize temperature excursions.
The intermediate (platen) spray demand shall protect the
intermediate (platen) superheater from going into saturation at the
inlet and from high temperature at the outlet. The control system
must coordinate the intermediate (platen) spray demand and the
secondary spray demand to minimize correction from the final steam
temperature controller.
5.3 Multiple-stage attemperation
Multiple-stage attemperation refers to the boiler design when
spray attemperation is applied at two or more different locations,
typically between the furnace and primary superheaters and also
between the primary and secondary superheaters. This sub clause
also applies to parallel multiple-stage attemperation.
5.3.1 Multiple-stage control
The first-stage attemperator is used to control the outlet
temperature of the primary superheater. The second-stage
attemperator is used to control the final outlet temperature.
Referring to Figure C.5, the setpoint for the second-stage control
loop is operator set. A cascade control scheme using final outlet
temperature as the primary process variable and either the
second-stage attemperator outlet temperature or spray water flow,
as the secondary process variable is the minimum system required
for controlling the final outlet temperature.
Feed-forward signals usually are required to obtain satisfactory
transient control performance from a steam temperature control
loop. The feed-forward signals are used only on the final outlet
temperature control loop, where they are added to the outlet of the
primary controller. The exact arrangement of the feedforward
signals must be determined on a case-by-case basis. As a minimum,
the feedforward signal is derived from a load index(es). This
feedforward signal should recognize all major influences on steam
temperature, including adjustments to heat distribution within the
boiler. Some common feedforward signals include load index, heat
distribution signals (fuel nozzle tilt positions), fuel flow, and
airflow.
The individual spray attemperator demand is distributed between
both stages of attemperation. The individual spray demands are
developed from the spray distribution and coordination controls
strategy as determined from the boiler manufacturer's
recommendations and specifications or as process constraints
dictate. Both valves shall participate during transient boiler
operation to minimize temperature excursions.
The first spray demand shall protect the primary superheater
from going into saturation at the inlet and from high temperature
at the outlet. The control system must coordinate the first spray
demand and the second spray demand to minimize correction from the
final steam temperature controller.
5.4 Attemperator spray and block valve logic
A spray water block valve(s) shall be furnished to provide tight
shutoff to prevent water leakage past the spray control valve and
to provide backup in the event that the spray control valve fails
to close when required. Each spray valve shall have its own
dedicated block valve, or several valves may share a common block
valve.
Control logic shall be provided for block valve operation to
preserve its tight shutoff ability. The following permissive shall
be satisfied before spray and block valves are opened:
Reset the turbine trip logic
Load greater than the preset amount
Spray demand greater than the preset amount (e.g., 2 to 3 % to
minimize valve wear)
The attemperator spray water block valve logic shall open the
block valve to its full open position prior to the initial opening
of its associated modulating attemperator spray control valve(s).
The block valve logic shall close the block valve after its
associated modulating attemperator spray control valve(s) is fully
closed. The block valve logic shall be designed to minimize
repeated opening and closing of the block valve when operating near
minimum spray conditions. Provisions shall be made to override the
sequence logic and close both the block and spray valves in the
event of a turbine trip (or master fuel trip when the master fuel
trip does not initiate a turbine trip) to minimize the possibility
of water carryover as the unit is shut down.
The block valve logic design shall be fully compliant with
ANSI/ASME TDP-1, "Recommended Practices for the Prevention of Water
Damage to Steam Turbines Used in Electric Power Generation".
5.5 Saturation ProtectionTo prevent the steam temperature
control system from spraying into saturation, logic shall be
provided which calculates the saturation temperature as a function
of the steam pressure in the superheater. When the desuperheater
outlet temperature approaches the saturation temperature, usually
within 5.5-11.1OC (10-20 OF), an interlock shall be activated which
prevents the spray valve from injecting any additional water. The
upstream controller shall take appropriate action to prevent windup
while the saturation interlock is active in the inner controller.
For two-stage attemperator arrangements, each loop should have
independent saturation protection6 Control and logic requirements
for a reheat steam temperature control by means of heat
distribution
The function of the reheat steam temperature control system is
to maintain reheat steam temperature, leaving the boiler within
manufacturer's specified limits. The strategy must be based on the
particular mechanism(s) used and the boiler manufacturer's
philosophies for controlling reheat steam temperature. The control
mechanism(s) that are operated by the reheat steam temperature
control equipment may involve the fire-side or the water-side of
the boiler, or a combination of both. Although the strategies
describe the use of conventional PID control techniques, it is not
the intention to preclude the use of advanced control
strategies.
This standard addresses the following means or mechanisms
employed for the control of reheat steam temperature:
a) Fuel nozzle tilts
b) Flue gas pass dampers
c) Flue gas recirculation
d) Single-stage spray water attemperation
6.1 Fuel nozzle tilts
Fuel nozzle tilts are a means of altering the distribution of
heat in a furnace to effect changes in reheater and superheater
outlet steam temperatures. Generally, the fuel nozzle tilts are
mounted in the furnace corners and can be tilted up or down from
horizontal. Lowering the fuel nozzle tilts increases furnace heat
absorption, which in turn lowers the flue gas temperature as it
enters the reheater and the superheater. Raising the fuel nozzle
tilts has the opposite effect. Fuel nozzle tilts usually are
operated in parallel, although biasing of individual corners may be
included and incorporated in the control strategy employed.
Referring to Figure C.6, single loop with feedforward control
(reheat temperature control with feedforward) is the minimum system
requirement for the fuel nozzle tilt arrangement to maintain the
reheat steam temperature setpoint. The load index feedforward
signal is summed with transient correction signals and a reheat
temperature controller output to develop a fuel nozzle tilt
demand.
Fuel nozzle tilts may also be used to control superheater steam
temperature in accordance with the boiler manufacturer's
recommendation.
Single-stage spray water attemperation is provided to supplement
the normal controls of reheat steam temperature (see 6.4 and
5.1).
6.2 Flue gas pass dampers
Flue gas pass dampers are a means to distribute the flue gas
between the superheater and the reheater to control reheat
temperature. The pass damper demand shall be indexed to position
the two pass dampers in opposite directions. During start-up and at
low loads, the reheat pass damper will normally be wide open, and
the superheat pass damper will be at a minimum position, and will
approach full open while the reheat pass damper closes to its
minimum position as load is increased. The relationship of the
damper positions is such that the combined flow restriction of both
devices remains relatively constant.
Referring to figure C.7, single loop with feedforward control
(reheat temperature control with feedforward) is the minimum system
requirement for the flue gas pass damper arrangement to maintain
the reheat steam temperature setpoint. The load index feedforward
signal is summed with transient correction signals and a reheat
temperature controller output to develop a flue gas pass damper
demand.
Single-stage spray water attemperation is provided to supplement
the normal controls of reheat steam temperature (see 6.4 and
5.1).
6.3 Flue gas recirculation
Flue gas recirculation is a means of altering the distribution
of heat within a furnace to affect changes in reheater outlet steam
temperature. Typically, at low loads, gas recirculation is high to
assist in achieving reheat temperature. At high loads, gas
recirculation is reduced to its minimum value. Generally, the
recirculation of flue gas is introduced into the furnace hoppers
for temperature control. For some boiler designs, flue gas
recirculation is introduced in the furnace airfoil and a
combination of airfoil and hoppers for control of temperature and
NO( (see B7).
Referring to figure C.8, single loop with feedforward control
(reheat temperature control with feedforward) is the minimum system
requirement for the gas recirculation to maintain reheat
temperature at the setpoint. The load index feedforward signal is
summed with transient correction signals and a reheat temperature
controller output to develop a flue gas damper demand. Gas
recirculation control damper demand shall be constrained by a
current limiting program to keep fan current within acceptable
limits. Safety interlocks, such as furnace purge, needs to be
considered but, are not addressed by this standard.
An alternate arrangement for the application of gas
recirculation is as a supplement to the normal temperature control.
When used in conjunction with fuel nozzle tilt control (see 6.1),
gas recirculation may be applied to maintain the fuel nozzles in
their horizontal position. When used in conjunction with flue gas
pass damper control (see 6.2), the gas recirculation is used to
maintain the pass dampers in a regulating range at low loads.
Single-stage water attemperation is provided to supplement the
normal controls of reheat steam temperature (see 6.4 and 5.1).
6.4 Single-stage spray water attemperation
The use of spray water attemperators is a method of controlling
reheater outlet steam temperature. Water is sprayed into the
superheated steam to lower its temperature. Temperature control is
achieved by varying the water flow.
Since water injection into the reheater will lower the overall
unit thermal efficiency, spray-water attemperation normally is
employed as a secondary means of reheat steam temperature control
in combination with other control mechanisms.
Single-stage spray water attemperation is often combined with
one of the other aforementioned means of controlling reheat steam
temperature. When combined with fuel nozzle tilts, flue gas pass
dampers, flue gas recirculation, and excess air, single-stage spray
water attemperation reduces cycle efficiency and is effective only
in reducing temperature. In such cases, other means shall be
employed in the control strategy to limit the use of spray-water
attemperation and to maximize the use of these other means of final
reheater outer steam temperature control. One method of
accomplishing this control strategy is to introduce a positive
offset (e.g., +10o F), into the temperature setpoint for the reheat
spray control. The boiler manufacturer's recommendations should be
followed in the implementation of combined control strategies.
7 Superheat control and logic requirements for once through type
boilers
For once-through type fossil fuel power plant boilers, the
transition between water and steam occurs without boiling. Water
becomes steam as it flows through the waterwall tubing. With
continuous heating, fluid temperatures increase throughout the
process. For subcritical boiler, the phase change point between
water and steam can move further down the piping within the
waterwalls as load (intermediate steam pressure) increases. For
supercritical boilers (critical point pressure [3206.2 psia]) there
is no change in phase between water and steam.
The ratio of firing rate to feedwater flow determines the final
value for the superheat steam leaving the boiler. To improve the
transient temperature response, boiler design may include single or
multiple stages of spray attemperation.
Since all feedwater entering the waterwalls becomes steam
(once-through), the throttle pressure is directly related to
feedwater flow. Low pressure requires an increase in feedwater
flow; high pressure requires a reduction in feedwater flow. Since
all the feedwater entering the boiler must be heated into
superheated steam, the firing rate controls (fuel and air) are
modulated to provide the required heating. The ratio of feedwater
to firing rate determines the final value for the main superheat
steam leaving the boiler.
Since superheater spray flow is extracted from feedwater flow, a
change of superheat spray flow will not result in a permanent
change in final steam temperature leaving the boiler since it does
not change the ratio of firing rate to feedwater flow. Eventually,
final steam temperature will return to its previous value, as the
intermediate steam temperature will rise due to less feedwater
flow.
This standard addresses the following means or mechanisms for
the control of final steam temperature:
a) Firing rate-feedwater ratio control
b) Attemperation control
7.1 Firing rate-feedwater flow ratio control All once-through
boilers include a firing ratefeedwater ratio control strategy as a
means to control steam temperatures. For boilers without spray
attemperation, the firing ratefeedwater flow ratio regulates the
final superheater outlet temperature. For boilers with single or
multiple spray attemperation, the firing rate-feedwater flow ratio
regulates the specified superheater outlet temperature or
attemperator differential temperature in accordance with the boiler
manufacturers recommendation.
Referring to figure C.10, single loop with feedforward firing
rate-feedwater flow control is the minimum control strategy to
regulate the steam temperature. Final steam temperature is measured
and compared to a setpoint with the results used to regulate the
firing ratefeedwater flow ratio. As a minimum, the temperature
setpoint is derived from a load index and modified by an operator
bias. In accordance with the boiler manufacturers recommendation,
the feedback controller is constrained by a waterwall outlet or
primary superheater outlet temperature controller to protect
against high temperature in the water walls or primary superheater
outlet tubes respectively.
A feedforward signal(s) and transient correction signal(s) is
added to the final steam temperature controller. As a minimum, the
feedforward signal is derived from a load index(es). This
feedforward signal should recognize all major influences on steam
temperature, including adjustments to heat distribution within the
boiler. As a minimum transient correction, waterwall outlet
temperature should be an anticipating signal. This signal
compensates for upsets due to sudden changes in slag formation,
feedwater temperature, mill starts, etc.
For once-through boilers with single or multiple-stage
attemperators, the firing rate-feedwater flow ratio control
strategy shall return final steam temperature to setpoint and spray
attemperation to its nominal value. As a minimum, the average
temperature difference across the attemperator is compared to a
setpoint. Any deviation from a differential temperature setpoint is
included in the control strategy to return the spray attemperator
to its nominal value.
The firing rate-feedwater flow ratio control loop provides a
signal both to the feedwater control sub-loop and to the fuel
control sub-loop. To raise steam temperature, the firing
rate-feedwater flow ratio must either increase firing rate or
decrease feedwater flow or both (see B2.2 Steam temperature control
by ratio adjustment). To lower steam temperature, the firing
rate-feedwater flow ratio must either decrease firing rate or
increase feedwater flow or both.
The firing rate-feedwater flow ratio control shall be
interlocked to manual until the subloops being modified (i.e.,
feedwater flow and/or firing rate) are in automatic mode.
7.2 Attemperator control
For once-through boilers, spray attemperator(s) are not used for
steady state correction but serve to stabilize steam temperature
during transient disturbance. To allow the transient temperature
control to operate in both directions (increase/decrease of main
steam temperature), the superheat spray valves should be maintained
at a normal regulating range. See Clause 5.1 for single stage
attemperation control and logic requirements and Clause 5.2 for
two-stage attemperation control and logic requirements.8 Common
design requirementsThe control system shall meet all operational
requirements and properly interface with the process. To accomplish
these objectives, the following minimum system design requirements
are defined.8.1 Automatic trackingAutomatic tracking shall be
provided such that any control mode transfer is accomplished
without a sudden process upset.
8.2 Integral windup preventionMeans shall be provided with the
superheater outlet steam temperature control strategy to prevent
integral windup of steam temperature controller(s) when the boiler
load is below that of the superheat steam temperature control range
or when the final control element is at a limit (full open or full
closed).
8.3 Final control element requirements
All final temperature control elements shall be designed to fail
safe on loss of demand signal or control power (i.e., close, or
lock in place). The fail-safe position shall be determined by the
user, based on the specific application and the recommendations
from the boiler/turbine supplier. The final control element should
have the capability to be characterized to linearize the
process.
8.4 System reliability and availability
As minimum criteria, the design basis of the steam temperature's
control system shall include the capability for
a)Maximum unit load/temperature control;
b)Normal operating load range;
c)Anticipated load changes (transients); and
d)Unit design characteristics, including spray water pressure
and capacity for attemperation.
8.5 Minimum alarm requirements
As a minimum, alarm requirements shall include the following
information:
a)High final superheater outlet steam temperature
b)Low final superheater outlet steam temperature
c)High differential header temperature between parallel paths of
the final superheater (if applicable)
d)Low primary superheater inlet steam temperature
(multiple-stage attemperation and saturation protection)
e)High primary superheater outlet steam temperature
(multiple-stage attemperation and tube metal protection)
f)High final reheater outlet steam temperature
g)Loss of control power
h)Loss of final drive power
i)Control loop trip-to-manual
In addition to the above, the following alarms should be made
available to the operator. a) Block valve failed to open
b)Block valve failed to close
8.6 Operator interface
8.6.1 Operation information
The following information used in the steam temperature control
system shall be made available to the operator:
a)Final superheater outlet steam temperature (per outlet)
b)Final superheater outlet steam temperature setpoint
c)Primary superheater inlet temperature(s) (multiple-stage
attemperation)
d)Primary superheater outlet temperature (multiple-stage
attemperation)
e) Secondary superheater inlet steam temperature(s) or
attemperator spray flow measurement
f) Inner loop process variable for cascade loop with feedforward
steam temperature control (temperature or flow)
g) Intermediate superheater outlet temperature (two-stage
attemperation)
h)Final reheater outlet steam temperature (per outlet)
i)Final reheater outlet steam temperature setpoint
j)All alarms (see 8.5)k)Automatic/manual control loop status
In addition to the above, the following information should be
made available to the operator:
a)Final control element(s) positionb)Attemperator spray flow
measurement (if not used for control)
8.6.2 Operator control functions
The control system shall include capabilities for the
automatic/manual mode transfer and manual control of firing rate
feedwater flow ratio for once through boiler and each individual
final control element except the fuel nozzle tilt final control
element which may be operated in parallel. The operator shall not
have manual control of the block valves.
The control system shall include capabilities for the operator
to adjust the final superheater outlet steam temperature setpoint
and the final reheater outlet steam temperature setpoint.
Consideration should be given to setpoint limits, which should not
be accessible to the operator.
Annex A ReferenceAMERICAN SOCIETY OF MECHANICAL ENGINEERS
(ASME)
ASME B31.1
Power Piping for Boilers
PTC19.3
Power Test Code Temperature Measurement
BPVC Section 1-2004
Boiler and Pressure Vessel Code, Power Boiler
ANSI/ASME TDP-1-1998Recommended Practices for the Prevention of
Water Damage to Steam Turbines Used for Electric Power
Generation
Available from:ASME
Tel: (212) 591-8500
Three Park Avenue
New York, NY 10016-5990
INSTITUTE OF ELECTRICAL AND ELECTRONICS ENGINEERS (IEEE)
IEEE/ASTM SI 10-97 Standard of Use of International System of
Units (SI): The Modern Metric System
Available from:IEEE
Tel. (800) 678-4333
345 East 47th Street
New York, NY 10017
ASTM
Tel. (610)-832-9585
100 Barr Harbor Dr.
Fax: (610)-832-9555
West Conshohocken, PA 19428-2959
Instrumentation, Systems and Automation (ISA)
ANSI/ISA-S5.1-1984
Instrumentation Symbols and Identification (R1992)
ANSI/ISA-S5.4-1976
Instrument Loop Diagrams (R-1981)
ANSI/ISA-S51.1-1979
Process Instrumentation Terminology
Control of Boilers, 2nd ed.Dukelow, S.G.; ISA Press-1986 (ISBN:
1-55617-330-x)
Available from:ISA
Tel. (919) 549-8411
67 Alexander Drive
P.O. Box 12277
Research Triangle Park, NC 27709
International ElectroTechnical Commission (IEC)
IEC TR62140-3:2002
Fossil-fired power station- Part 3, Steam Temperature
Control
Available from:IEC
Tel. +41 22 919 02 11
www.iec.ch
MEASUREMENT, CONTROL AND AUTOMATION ASSOCIATION (MCAA)
Functional Diagramming of Instrument and Control Systems
(Previously PMC 22.1-1981)
Process Measurement and Control Terminology (Previously PMC
20.1-1973)
Available from: MCAA
2093 Harper's Mill Rd.
P.O. Box 3698
Williamsburg, VA 23187-3698
www.measure.orgMISCELLANEOUS
Babcock & Wilcox, Steam It's Generation and Use, 41st ed.,
The Babcock & Wilcox Company, 20 S Van Buren Ave., P.O. Box
351, Barberton, OH. 44203-0351.
Design, Operation, Control and Modeling of Pulverized Coal-fired
Boilers; Control of Boilers, 2nd. ed.; Dukelow, S. G.; ISA
Press-1986 (ISBN: 1-55617-330-X)
Durrant, O. W.; Boiler-Turbine Modeling and Control Seminar,
University of New South Wales, February 14-18, 1977
Standard Handbook of Power Plant Engineering, McGraw-Hill
Publishing Co.; 1989 (ISBN: 0-07-01906-9)
Singer, Joseph G., Combustion: Fossil Power Systems, 4th ed.,
Combustion Engineering Inc., 1000 Prospect Hill Rd. Windsor, CT.
06095, 1991.
Control Valve Sourcebook, Power and Severe Services, 2nd ed.,
Fisher Controls International, Inc., 1990.
AnnexB Steam Temperature Control
B.1 Purpose
The purpose of this annex is to provide tutorial information on
the philosophy underlying this standard and to assist the user of
this standard in specifying and applying steam temperature control
schemes. This annex is included for information purposes only and
is not part of ISA-dS77.44.01.
B.2 Introduction
B.2.1 Subcritical vs. supercritical in once through boiler
design
A boiler is either subcritical or supercritical depending on
whether it is designed to be operated below or above the critical
pressure, respectively (critical pressure is 3206.2 psia). At
critical pressure and above, boiling, as it is known within the
saturation region, does not take place. The transition from water
to steam is abrupt, and the temperature steadily increases rather
than flattening completely. At critical pressure, the density
differential between water and steam becomes zero, thus making
natural circulation impossible.
Operation at subcritical pressures creates certain problems for
the boiler designer. Probably the most important problem is the
handling of water-steam mixtures. At subcritical pressures, the
water-steam mixtures can separate into all water in one tube and
all steam in an adjacent tube. Thus, the boiler design must achieve
good mixing of the water-steam mixture and limit the amount of heat
absorbed by a furnace panel to a value that will not cause damaging
thermal stresses in the membrane walls. As examples, variable
orifices are installed in each furnace panel to balance the flows
and furnace-mixing headers are used at particular locations to
limit the heat absorption.
Operation at supercritical pressures eliminates concern over the
separation of water-steam mixtures because this phenomenon does not
occur. However, furnace-mixing headers redistribute the fluid where
adjacent tubes are in different fluid passes. In supercritical
operation, it is important to avoid subcritical pressures because
of the possibility of steam to water separation where the boiler
design does not consider this.
There are many similarities between subcritical and
supercritical boilers. The gas side arrangement is practically
identical, although some furnace panel surfaces may be located
differently. The fluid side is also quite similar, particularly in
the furnace circuitry. The boiler responses are quite similar, with
supercritical boiler being slightly faster.
B.2.2 Steam temperature control by ratio adjustment
In a once-through boiler, final steam temperature is affected by
the ratio of firing rate to feedwater flow. Therefore, changing
firing rate, feedwater flow, or both, can affect control of steam
temperature. The boiler master demand signal is typically sent in
parallel to the firing rate demand and the feedwater demand. The
temperature controller output is then configured as a ratio setting
and applied to the firing rate, feedwater flow, or both.
The boiler master is tuned for pressure and load response, that
is orders of magnitude faster than the temperature loop. Therefore,
changes to ratio setting have been applied with success in either
or both subsystems. Generally, though, it is simplified to modify
the firing rate demand.
Recognizing that megawatts output is proportional, the input
firing rate and feedwater flow must equal the flow leaving the
boiler to maintain constant storage of fluid; it is logical to send
boiler demand to the firing rate and feedwater together. Adjusting
firing rate for final steam temperature results in a compromise
between controlling temperature and controlling load. Adjusting
feedwater flow for final steam temperature results in a compromise
between controlling temperature and controlling pressure.
Furthermore, firing rate and feedwater flow are conditioned upon
the specific boiler design, boiler/process constraints, and process
variable responses.
Once-through boiler designs require a minimum feedwater rate to
protect the furnace tubes from overheating. This boiler constraint
requires that the firing rate be adjusted to control steam
temperature until load exceeds the minimum feedwater flow. At which
time, feedwater flow can participate in controlling final steam
temperature.
When feedwater flow or firing rate changes, a temperature delay
exists before final steam temperature changes. The temperature
delay time for firing rate is shorter than feedwater flow due to
shorter transport delay and provides better transient correction
for steam temperature. Boilers with spray attemperation have means
to shorten feedwater flow transport delays by introducing spray
water before the superheater(s). While spray attemperation may
initially control temperature excursions, steady state temperature
is achieved when total feedwater flow (boiler inlet water flow and
spray attemperation flow) is in correct ratio with firing rate.
The controls will over-fire or under-fire the firing rate to
respond to load changes. This transient condition creates an
incorrect steady state fuel demand that causes temperature and
pressure errors. Using temperature controls to modify firing rate
demand and feedwater demand in opposite direction helps the overall
system stability because one process effect counter acts the
other.
B.3 Requirements
B.3.1 Design specification requirement
To adequately specify a steam temperature control strategy, the
following three fundamental questions must be addressed:
a) What are the anticipated process operational
requirementse.g., steady-state or cyclic operations, variable or
fixed pressure operation, rates-of-change, etc.?
b) What equipment and operating parameters are required to
properly interface the control system?
c) What characteristics must the control system possess to
maintain the desired performance?
d) What are the boiler-design characteristics in the heat
absorption pattern of the economizer, steam generation
(water-wall), and the steam superheating (superheater and
reheater)?
The extent to which these questions are answered will directly
determine how well the control system is fitted to the design and
operating requirements. A misapplication, at the least, could
result in poor operating performance and, at the worst, could
result in extensive boiler damage. The following is intended to
supplement good engineering judgment with a consistent means of
communicating design requirements to suppliers, designers, and
constructors.
B.3.2 Summary of process performance requirements
A significant factor to consider in boiler control system
selection is the heat absorption pattern in each steam generation
(water wall and economizer) and steam superheater. Different boiler
designs are used to properly balance the list absorption between
the steam generation and steam super listing as well as the heat
distribution requirements between the superheater and reheater
sections.
When the superheater and reheater surfaces are designed to
provide full load temperature at control load, resulting in
excessive steam temperatures at full load, the following control
means are provided for achieving the desired balance between steam
generation and steam superheating over the load range:
a) Spray attemperation
b) Gas by-pass and damper control
c) Burner manipulation
d) A combination of the above is often needed to control
superheat and reheat temperature independently.
When the superheat and reheat surfaces are designed to provide
full load temperature only near full load, the following means are
provided to increase the balance toward superheating and/or
reheating as the load is reduced:
a) Increase excess air at reduced load
b) Burner manipulation
c) Gas recirculation
d) Gas by-pass and damper control (for distribution between
superheat and reheat absorption)
e) A combination of the above is often needed to control
superheat and reheat temperature independently
A second significant factor in steam temperature control system
selection is the intended boiler usage. Since the operating
requirements of the boiler define the required control system
capabilities, design specifications must address the following unit
characteristics:
a) Unit load/steaming capacity
b) Normal operating load range
c) Anticipated load changes (transients)
d) Start-up and shutdown frequency
A complete description of the anticipated load characteristics
will allow the engineer/supplier to properly evaluate the system
and to propose a control strategy. When the control strategy is
preselected, these characteristics still should be defined as part
of the design basis.
Table B.1 provides a general comparison of typical control
systems for specification development and evaluation. This table is
not intended to be all-inclusive; rather, it is a summary of
commonly used control strategies. The important conclusion to be
drawn from the table is that all control systems are not the same,
and, therefore, selection of a specific system requires careful
consideration of design parameters.
Table B.1 Summary of typical control systems
ProcessPrerequisitesSingle LoopSingle Loop with
FeedforwardCascade Loop with Feedforward
Slow load changes or constant final steam temperature not
criticalSlow to moderate load changes or steady spray water
pressure supply or fixed final steam temperatureRapidly changing
loads, variable spray water supply or variable final steam
temperature
Steady-state operabilityGoodGoodGood
Transient operabilityPoorGoodGood
Response to load changeSlowFastFast
Control system typeFeedbackFeedback and FeedforwardFeedback,
Feedforward, and Cascade
Process measurement requirementsFinal steam temperatureFinal
steam temperature and feedforward signalSecondary Superheater (SSH)
inlet temperature or attempt flow, feedforward signal, and final
steam temperature
Potential for excessive temperature deviation during load
changeProbableDependent on final drive linearity and repeatable
through the load rangeMinimal
B.3.3 System description and interface requirements
To achieve the desired performance objectives, the control
system interface with the process must be considered carefully. At
a minimum, a detailed process description should be provided that
includes
a) a specification for all process design parameters such as
temperature, pressures, and normal flows;
b) final drive descriptions of sufficient detail that a control
strategy can be selected to provide appropriate control action;
c) existing process measurement interfaces, dimension sketches
or diagrams. All measurements should be taken where vibrations,
pulsations, and other flow disturbances are at a minimum;
d) a description of available electrical power and pneumatic
supplies;
e) control interlocks, setpoints, and alarm points; and
f) instrument loop diagrams as defined by ISAS5.41976
(R1981).
B.4 Principles and methods of steam temperature control
B.4.1 Steam temperature feedback control
A typical boiler arrangement is one where the spray
attemperation takes place between the primary and secondary
superheaters. With this arrangement, a large process time lag
exists between the introduction of spray water and the detection
and stabilization of exit steam temperature. A final steam
temperature is used as the feedback measurement for control.
B.4.2 Load index development
The load index feedforward may be steam flow, air flow, or other
measures of boiler load. Air flow offers the advantage of including
excess combustion air requirements as a part of the load index
signal. The load index feedforward signal is summed with the output
signal from the steam temperature controller.
B.4.3 Transient correction signal development
A steam temperature transient correction is a signal that is
applied to the normal steam temperature control strategy to counter
the impact of a transient process change. An example of a transient
process change, and the most typical, would be overfiring or
underfiring. Overfiring and underfiring are considered transients
because they are not required to maintain a steady-state condition.
A steam temperature transient correction recognizes the impact of a
transient on the final steam temperature and attempts to minimize
this impact.
Probably the best way to describe this action is to consider an
example. Assuming that a load increase is occurring, the firing
rate will increase to meet the new load setting and will increase
even more to assist in achieving the new energy storage level in
the unit. This additional firing is referred to as overfiring, and
once the unit's energy level is satisfied, it will be removed.
Since the overfiring is only temporary, it is considered a
transient condition. Assuming that no transient correction is made,
the new load setting will require an adjustment to the steam
temperature control, which normally is satisfied through
feedforward action. The overfiring would cause the steam
temperature to increase, and the steam temperature controller would
react to counter the temperature excursion by increasing the
spray.
When the overfiring is removed, the steam temperature would drop
because excess spray exists. The excess spray would then cause the
steam temperature controller to reduce the spray flow. The end
results are a longer time period to reach steady-state conditions
and a greater deviation versus time. A transient correction would
recognize when overfiring is occurring and bias the controls to
increase the spray to help minimize the temperature excursion and
to prevent the temperature controller from integrating a
temperature error over time. Ideally, no temperature transient
would occur; thus steady state is achieved more quickly, and the
temperature deviation versus time will be reduced.
The actual transient correction for overfiring or underfiring is
a function of the overall control strategy. One approach is to use
the throttle pressure error as the source for the transient
correction. Throttle pressure error is scaled and summed with other
feedforward signals.
B.5 Saturation protection/water induction protectionSteam
temperature control maintains final steam temperature by injecting
water into the steam flow upstream of the final superheater
section. There are two potential problems with this process. The
first can lead to water induction into the steam turbine and the
second can cause a loss of control function along with severe
downstream temperature transients.
If spray water is allowed to enter the desuperheater while the
turbine is not operating, either by a leaking valve or a control
malfunction, it may collect in the superheater tubes without being
fully vaporized. Later when the turbine is started or the steam
flow is increased, the water can be carried into the turbine where
it can cause thermal or mechanical damage. The relatively cold
water will tend to collect in the bottom of the turbine shell and
shrink the hot metal which distorts the shape of the turbine shell
causing rubbing and vibration.
The second problem is that during boiler upsets that cause the
steam temperature to increase significantly, the steam temperature
control system may call for more spray flow than can be completely
vaporized by the steam flow. If the water is not completely
vaporized, the steam leaving the desuperheater will be saturated.
As long as the steam remains saturated, its temperature will not
depend on the amount of spray flow but will only depend on the
steam pressure. The saturation causes two problems. First, the
desuperheater outlet temperature will stop changing. If the
temperature is used as the feedback for the inner loop in a cascade
control strategy, the inner loop will begin to "windup." This
windup will not be prevented by normal anti-windup logic because
the controller output will not be at a limit. Since the inner loop
is normally tuned with significant integral action, the windup will
occur fairly quickly. When the desuperheater outlet temperature
eventually emerges from saturation, the controller will have to
unwind before it begins to control properly. This condition can be
detected very easily by watching for a clipped wave in the
desuperheater outlet temperature response.
Secondly, when the desuperheater outlet steam is saturated, the
small water droplets in the steam can affect downstream piping and
superheater tubing. It also can cause severe thermal transients
downstream as the steam emerges from the saturation condition.
B.6 Two-stage attemperation
Two-stage attemperation is provided in a boiler for one or both
of the following reasons: first, the quantity of spray flow
required is so great that a single attemperator would have
saturated steam at its outlet; second, the metal temperature in one
of the intermediate superheater sections would be above the
allowable design temperature unless the inlet temperature of that
section is controlled by spray.
Control of two-stage attemperators is more complex than a single
attemperator because the action of the first spray stage affects
the second stage. The coupling of the two stages makes tuning any
control strategy more difficult.
One consideration in developing an appropriate strategy is the
difference in the time responses of the first-stage spray and the
second-stage spray. Since the second-stage spray is closer to the
outlet of the boiler, its effect on the outlet temperature is
faster than the first-stage spray. Better dynamic response of the
final outlet temperature is possible if the second-stage spray is
the main control parameter for the final temperature. The primary
objective for steady state operation is providing maximum
attemperation to the first stage to achieve maximum cooling of the
platen or radiant superheater while controlling outlet steam
temperature.B.7 Use of cascade spray valve control
In a cascade control strategy, when the output of one controller
is used to manipulate the setpoint of another, the two controllers
are said to be cascaded. Although each controller will have its own
measurement input, only the primary controller (outer loop) can
have an independent setpoint, and only the secondary controller
(inner loop) has an output to the process.
Steam temperature control strategies assume a predictable
relationship between the spray water control valve position and the
spray water flow. If this is not the case, a cascade spray water
flow control strategy should be considered. With the cascade
control strategy, the output of the temperature controller
establishes the required spray flow setpoint for the spray water
flow controller. In the cascade control arrangement, the
temperature controller is the primary controller, and the spray
flow controller is the secondary controller.
B.8 NOx control
The nitrogen and oxygen in the combustion air and fuel form
oxides of nitrogen (NO() during the combustion process. The rate of
NOx formation is dependent on high temperature, stoichiometric
conditions, resident combustion time, and the amount of nitrogen in
the fuel. To suppress the formation of NO(, the combustion
conditions and control strategy must be altered to decrease 02
level at the flame zone, stage combustion or both and to decrease
combustion gas temperature in the furnace and, hence, the time of
exposure of the products of combustion to high temperature.
Air that bypasses the burner combustion can suppress the
formation of NO( by reducing the 02 level and temperature at the
primary combustion zone. This option is possible if the boiler
design allows the use of burner out-of-service or overfire air
ports, or both to achieve the second stage of combustion. The
out-of-service burners and overfire air ports provide means of
introducing staged combustion air downstream of the furnace
combustion zone. Excess air used for steam temperature control also
must bypass the burner combustion zone.
Flue gas recirculation can suppress the formation of NO( by
reducing the combustion temperature if the boiler design allows
introduction of flue gas recirculation into the secondary air
stream.
Flue gas recirculation can be used for suppressing the formation
of NOx and controlling reheat steam temperatures if the boiler
design allows the introduction of flue gas recirculation into both
the secondary air stream and the furnace hopper. These boilers have
a gas recirculation distribution damper for regulating the gas
recirculation flow path.
B.9 Redundancy
Redundancy is employed when system reliability will be seriously
affected by a component failure. Redundancy also permits on-line
maintenance of components. For maximum availability, redundancy
should always be considered. Deviation alarms and automatic failure
detection/transfer should be considered, in order to maximize the
usefulness of the application of redundancy.
B.10 Reset windup prevention
Any control loop in which the controller has integral action and
the final control element is likely to be fully open or fully
closed during routine plant operation should have a provision to
prevent reset windup. Steam temperature controls frequently fall
into this category because boiler designers usually try to minimize
the amount of spray flow required throughout the load range. This
frequently leads to times when the spray valve is fully closed
during normal operation and, therefore, to the need to reset windup
prevention.
For conventional single loop controls, reset windup prevention
is relatively simple to implement. As soon as the final control
element reaches one of its endpoints of travel (0% closed or 100%
open), the integral (reset) action or the entire controller is
disabled. For a simple control loop, the integral limits on the
final control element correspond to the high and low limits on the
controller output. Most controllers have automatic reset windup
prevention when the controller output reaches a limit. Provided
everything is calibrated correctly, the reset windup prevention
will begin when the final control element reaches a travel
limit.
For a cascade loop or cascade loop with feedforward controls,
reset windup prevention becomes slightly more complicated. Now two
controllers must both stop integrating to prevent reset windup. The
inner or secondary controller operates the same as a single loop
controller described above. The primary controller must also have
its integral or reset action disabled when the final control
element reaches a limit. The output of the primary controller is
not always at the same value when the final control element reaches
a limit, so a different mechanism must be used to implement the
windup prevention. On pneumatic and analog electronic controllers,
it may not be practical to implement a reset windup prevention
scheme such as is required in this situation. On a digital system,
however, there are several ways to do this. The integral gain of
the controller may be adaptively tuned to zero when the limit is
reached or the high or low limit of the controller may be adjusted
to the controller output value when the limit is reached. This
prevents the primary controller from winding up the setpoint for
the secondary controller when the final control element is at a
limit.
B.11 Advanced steam temperature control
Steam temperature control is one of the most difficult control
loops in the boiler control system. There are several factors that
make the control difficult.
The time response of the final steam temperatures is generally
very slow and has a considerable deadtime response. This is due to
the large mass of metal in the superheater sections of the boiler,
which are slow to change temperature. Slow response and deadtime
responses are both tough to handle well with conventional control
strategies.
Steam temperature can be upset by almost any disturbance in the
boiler. These upsets continually challenge the control system and
when combined with the slow temperature response make good control
tough. Some of the more common upsets are load changes, fuel
variations, boiler slag, pressure changes, pulverizer upsets, and
sootblowing.
Spray valves that are usually the primary control means for
final steam temperature control sometimes go closed during certain
load ranges or transients. Any time a final control element goes
into saturation such as fully closed or fully open, it introduces a
large nonlinearity into the control loop. Conventional control
strategies do not cope with such nonlinear responses well.
There are usually two methods of controlling reheat temperature.
One is a spray valve and the other is some method of controlling
heat distribution such as burner tilts, pass dampers, or gas
recirculation. The action of these two control variables must be
coordinated, and this adds some complexity to the control
strategy.
With all of these factors making steam temperature control
difficult, it is easy to understand why it is a frequent target of
advanced control techniques. There are a variety of advanced
control techniques, which can be used. They range from relatively
simple modifications such as better feedforward signals or deadtime
compensation to full-blown multivariable optimal control systems.
Many of the advanced control techniques can improve steam
temperature control, but they generally involve added complexity in
the control system. The added complexity in the control system can
require a higher level of support by the plant staff.
Although this standard describes the minimum requirements for
steam temperature control, the reader should be aware that more
advanced control techniques are available and can frequently
provide better control performance.
Annex C Figures
Figure C.1a Typical superheater single-stage attemperator
arrangement
Figure C.1b Typical superheater two-stage attemperator
arrangement
Figure C.1c Typical universal pressure once-through boiler
Figure C.1d Typical once-through boiler
Figure C.1e Typical combined circulation once-through boiler
Figure C.1f Typical two stage attemperator once-through
boiler
Figure C.2 Typical single loop superheat steam temperature
control
Figure C.3 - Typical single loop with feedforward superheat
steam temperature control
Figure C.4a Typical cascade loop with feedforward superheat
steam temperature control with temperature inner loopFigure C.4b
Typical cascade loop with feedforward superheat steam temperature
control with flow inner loop
Figure C.5 Typical two-stage attemperation superheat steam
temperature control
Figure C.6 Typical single loop with feedforward fuel nozzle tilt
control
Figure C.7 Typical single loop with feedforward flue gas pass
damper control
Figure C.8 Typical single loop with feedforward flue gas
recirculation control
Figure C.9 Typical single loop reheat steam temperature
control
Figure C.10 Typical firing rate feedwater ratio control
Developing and promulgating sound consensus standards,
recommended practices, and technical reports is one of ISAs primary
goals. To achieve this goal the Standards and Practices Department
relies on the technical expertise and efforts of volunteer
committee members, chairmen and reviewers.
ISA is an American National Standards Institute (ANSI)
accredited organization. ISA administers United States Technical
Advisory Groups (USTAGs) and provides secretariat support for
International Electrotechnical Commission (IEC) and International
Organization for Standardization (ISO) committees that develop
process measurement and control standards. To obtain additional
information on the Societys standards program, please write:
ISA
Attn: Standards Department
67 Alexander Drive
P.O. Box 12277
Research Triangle Park, NC 27709
ISBN:
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