Effective boiler operations fundamentals

The Babcock & Wilcox Company

Chapter 43
Boiler Operations

Effective operation of steam generating equipment
has always been critical to maintaining system efficiency, reliability and availability. With advances in
sensor technology, control software, and steam generator hardware, efficient operation today means balancing equipment performance with safety requirements and emissions mandates. The procedures used
to run steam generating equipment vary widely depending upon the type of system, fuel and application. Systems can range from simple and fully automated requiring a minimum of attention, such as
small gas-fired package boilers, to the very complex
requiring constant operator attention and interaction,
such as a large utility plant. There are, however, a
set of relatively common fundamental operating
guidelines that safeguard personnel and optimize
equipment performance and reliability. When combined with equipment-specific procedures, these
guidelines promote the best possible operations. The
first half of this chapter focuses on general practices
applicable to large multi-burner fossil-fuel fired natural circulation and once-through boilers, though these
practices are also generally applicable to most other
boiler designs. Starting with Operation of Cyclone
furnaces, the remaining sections focus on the unique
practices for several important special cases.
Because of the intimate relationship between equipment design and operation, additional operating guidelines may be found in other chapters of Steam. Selected
areas of particular interest are listed in Table 1.

General boiler operations
Fundamental principles
Although boiler design and power production have
become sophisticated, basic operating principles still
apply. Combustion safety and proper steam/water
cooling of boiler pressure parts are essential.
Combustion safety and steam/water cooling requirements Before firing a furnace, there must be no lin-

gering combustible material inside the unit. Purging,
or removal of this material, assures that the furnace
is ready for firing. A standard operating rule for multiple burner boilers is to purge the unit at no less than
25% of the maximum continuous rating (MCR) mass
air flow for the greater of at least five minutes or five
volume changes.
Steam 41 / Boiler Operations

Once combustion is established, the correct air/fuel
ratio must be maintained. Insufficient air flow may
permit the formation of combustible gas pockets and
provide an explosion potential. Sufficient air flow to
match the combustion requirements of the fuel should
be maintained and a small amount of excess air
should be admitted to cover imperfect mixing and to
promote air and fuel distribution. For emissions reduction, many newer firing systems are staged with
overfire air (OFA) ports installed in the upper combustion zones of the furnace. The controlled introduction of combustion air does not eliminate the need to
provide adequate operating excess air for safety.
In addition to these combustion precautions, it is
important to verify boiler water levels. Combustion
should never be established until adequate cooling
water is in the tubes and steam drum for natural circulation boilers and minimum flow rates are established for once-through boilers.
General safety considerations Pressure part failure
remains a major concern in the boiler industry. The

Table 1
Index to Additional Operating Guidelines
Found in Steam
System or Component
Air heaters
Ash handling equipment
Auxiliary equipment
Burners, coal
Burners, oil and gas
Bypass systems
Chemical cleaning
Chemical recovery units
Cyclone furnaces
Fluidized-bed boilers
Particulate removal equipment
Pulverizers
Scrubbers (flue gas desulfurization)
Selective catalytic reduction systems
Sootblowers
Startup systems
Stokers
Waste-to-energy systems
Water chemistry
Water treatment

Chapter
20
24
25
14
11
19
42
28
15
17
33
13
35
34
24
19
16
29
42
42

43-1

American Society of Mechanical Engineers (ASME),
National Board of Boiler and Pressure Vessel Inspectors, and other organizations have issued extensive
codes directed at minimizing these failures. The codes
are continuously updated to support quality pressure
part design. (See Appendix 2.)
Combustion products have also received considerable safety attention. Carbon dioxide (CO2), carbon
monoxide (CO), sulfur oxides and chlorine compounds
must be considered. While CO2 is not poisonous, it reduces oxygen availability in the flue gas. Sulfur oxides
can form acids when breathed into the lungs. Chlorine
compounds can form hydrochloric acids or carcinogens
such as dioxin.
Safety of fuel ash must also be considered. While
few ashes contain hazardous materials, heavy metals and arsenic can be present in dangerous levels. In
addition, residual combustion may continue in ash
collected in hoppers. This is especially true when new
emissions reduction combustion systems are being
installed. Carbon-in-ash characteristics may be altered under the new low nitrogen oxides (NOx) firing
configurations.
Finally, safeguards apply when performing maintenance and other work on out-of-service boilers. A
confined space may have insufficient oxygen for personnel. Good lighting is important for a safe working
environment. In addition, ash accumulations in outof-service boiler areas may still be too hot for maintenance activities.

Initial commissioning operations
Operator requirements
Good operation begins before equipment installation is complete. It includes training of the operators
as well as preparation of the equipment.
Every operator must be trained to understand and
fulfill the responsibility assumed for the successful
performance of the equipment and for the safety of
all personnel involved. To be prepared for all situations that may arise, the operator must have a complete knowledge of all components: their designs, purposes, limitations and relationships to other components. This includes thoroughly inspecting the equipment and studying the drawings and instructions. The
ideal time to become familiar with new equipment is
during the pre-operational phase when the equipment
is being installed.
A distributed control system (DCS) integrates the
individual process controllers of a steam generation
process into a coordinated, interactive system. It enables the operator to manage the process as a complete
system, with control over the interrelationship of various subsystems.
Modern distributed control systems are extendable
to provide operating personnel with advanced simulations of equipment behavior. Simulator training is
typically in real-time, ensuring not only a working
understanding of the various steam generator systems,
but also the reaction time and rate of the equipment.
Combined with simulated equipment failures and
43-2

what-if events, the operating personnel can gain valuable experience prior to initial operation.
Preliminary operation should not be entrusted to
inexperienced personnel who are not familiar with the
equipment and the correct operating procedures. Considerable equipment damage and potential safety
events can result from improper preparation of equipment or its misuse during preliminary checkout.
Operator training takes on special significance during the initial operating period required to prepare the
unit for commercial operation. Knowledgeable and
experienced operators are valuable during this period
when the controls and interlocks are being adjusted,
fuel burning equipment is being regulated, operating
procedures are being perfected and preliminary tests
are being conducted to demonstrate the performance
and capabilities of the unit.

Preparations for startup
A systematic approach is required when a new
boiler is being installed or when any boiler has undergone major repairs or alterations. The procedure
varies with boiler design; however, certain steps are
required for all boilers. The steps may be classified as
inspection, cleaning, hydrostatic testing, pre-calibration of instruments and controls, auxiliary equipment
preparation, refractory conditioning, chemical cleaning, steam line cleaning (blowing), safety valve testing and settings, and initial operations for adjustments and testing.
Inspection An inspection of the boiler and auxiliary
equipment serves two purposes: 1) it familiarizes the
operator with the equipment, and 2) it verifies the
condition of the equipment. The inspection should
begin some time during the construction phase and
continue until all items are completed.
One item frequently overlooked during the inspection is the provision or lack of provision for expansion.
The boiler expands as the temperature and pressure
are increased, as do steam lines, flues and ducts, sootblower piping and drain piping. Before pressure is
raised in the boiler, temporary braces, hangers or ties
used during construction must be removed.
Cleaning Debris and foreign material that accumulate during shipment, storage, erection or repairs must
be removed. Debris on the water side can restrict circulation or plug drain lines. Debris on the gas side can
alter gas or air flows. Combustible material on the gas
side can ignite and burn at uncontrollable rates and
cause considerable damage. Glowing embers can be the
source of ignition at times when ignition is not desired.
Fuel lines, especially oil and gas lines, should be
cleaned to prevent subsequent damage to valves and
the plugging of burner parts. Steam cleaning is recommended for all oil and gas lines. Atomizing steam
and atomizing air lines should be cleaned.
Hydrostatic test After the pressure parts are assembled, but before the refractory and casing are installed, a hydrostatic test at 1.5 times the boiler design
pressure is applied to all new boilers and maintained for
a sufficient time to detect any leaks. Testing is equally
important following pressure part replacements at pressures specified in local code requirements.

The hydrostatic test is normally the first time the
new boiler is filled with water; therefore, this is the
time to begin using high quality water for the prevention of internal fouling and corrosion. (See Chapter
42.) Demineralized water or condensate treated with
10 ppm of ammonia for pH control and 500 ppm of
hydrazine for control of oxygen should be used for all
nondrainable superheaters and reheaters. A clear filtered water is suitable for components that will be
drained immediately after the hydrostatic test.
Temperature plays an important part in hydrostatic
testing. The metal temperature and therefore the
water temperature must be at or above applicable
Code restrictions for hydrostatic testing. For example,
these restrictions, as stated in the ASME Code, specify
that the hydrostatic test temperature will not be below 70F (21C) to take advantage of the inherent toughness of carbon steel materials as related to temperature.
The water temperature should be kept low enough so
that the pressure parts can be touched and close inspections can be made. It should not be so high that water
escaping from small leaks evaporates immediately or
flashes to steam. Also, the water temperature should
not be more than 100F (56C) above the metal temperature to avoid excessive metal stress transients.
Finally, no air should be trapped in the unit during the hydrostatic test. As the unit is being filled, each
available vent should be open until water appears.
Instrumentation and controls Every natural circulation boiler has at least two indicating instruments:
a water/steam pressure gauge and a water level gauge
glass. If a superheater is involved, some type of steam
temperature indicator is also used. Once-through type
boilers have steam pressure gauges, flow meters and
temperature indicators. These indicators are important
in that the pressure, temperature levels and flows indicated by them must be controlled within design limits. Therefore, the indicators must be correct. Operation should not be attempted until these instruments
are calibrated, and the calibrations should include corrections for actual operating conditions. Water-leg
correction for the pressure gauge is one example. (See
Chapter 40.)
Most modern boilers are controlled automatically
once they are fully commissioned. However, before
these boilers can be started up, the controls must be
operated on manual until the automatic controls have
been adjusted for site-specific conditions. Automatic
control operations should not be attempted until the
automatic functions have been calibrated and proven
reliable over the load range.
Auxiliary equipment The auxiliary equipment must
also be prepared for operation. This equipment includes fans to supply air for combustion and to transport fuel, feedwater pumps to supply water, fuel equipment to prepare and burn the fuel, and air heaters to
heat the air for combustion. This equipment also includes an economizer to heat the water and cool the
flue gas, ash removal equipment, a drain system to
drain the boiler when required, a functioning
sootblowing system to adequately clean the heat
transfer surfaces, and post-combustion environmental control equipment.


Chemical cleaning Water-side cleanliness is important for all boilers because water-side impurities can
lead to boiler tube failures. They can also lead to carryover of solids in the steam, resulting in superheater
tube failure or turbine blade damage.
The flushing of all loose debris from the feedwater
system and boiler, and the use of high quality water
for the hydrostatic test, must be supplemented by
proper water-side cleaning before startup. To remove
accumulations of oil, grease and paint, the natural
circulation boiler is given a caustic and phosphate
boilout after the feedwater system has been given a
phosphate flush. The once-through boiler and its associated pre-boiler equipment are given a similar flushing. This boiling out and/or flushing should be accomplished before operation.
After boiling out and flushing are completed, products of corrosion still remain in the feedwater system
and boiler in the form of iron oxide and mill scale. It
is recommended that acid cleaning for the removal of
this mill scale and iron oxide be delayed until operations at fairly high capacities have carried loose scale
and oxides from the feedwater system to the boiler.
This results in a cleaner boiler for subsequent operations. Chemical cleaning of internal heating surfaces
is described in Chapter 42.
Steam line blowing Fine mesh strainers are customarily installed in turbine inlet steam lines to protect
turbine blades or valves against damage from scale
or other solid material that may be carried by the initial flow of steam. In addition, many operators use
high velocity steam to clean the superheater and steam
lines of any loose scale or foreign material before coupling the steam line to the turbine. The actual procedure used depends on the design of the unit. Temporary piping for flow bypass to the atmosphere is required
with all procedures. This piping and any noise reduction silencers must be securely anchored to resist the high
nozzle reaction created during the high velocity blowing period.
Several methods are used for blowing steam lines,
including particularly high pressure air and steam
blowing. The recommended method and the one most
used is steam blowing because experience has shown
that temperature shock and high velocities are the
most effective means of removing loose scale. Sufficient shock is obtained with a series of blows where
the steam temperature changes during each blow.
Lower pressure, high velocity steam blowing techniques are also available, including those with high
velocity treated water injection to promote thermal
shocking of the mill scale and debris. Designed and
managed correctly, these techniques provide safe removal of scale and other solid particles detrimental to
turbine components.
There are two basic methods of supplying steam for
steam line blowing with a natural or forced circulation boiler. The first method is to use steam returning
from the flash tank to the superheater on the forced
circulation unit or steam flow from the drum on the
natural circulation unit. The second method is to use
high pressure steam directly from the boiler. The latter method supplies large quantities of steam at higher

43-3

pressures. Temporary valving is required to control the
flow rates during the blowing period.
Boiler pressure and temperature can be maintained
during the blowing period by continuous firing. If firing is discontinued during the blowing period, it must
be remembered that any change in boiler pressure
changes the saturation temperature throughout the
system. To avoid excessive thermal shock, changes in
boiler pressure should be limited to those corresponding to 75F (42C) in saturation temperature during the
relatively short blowing periods.
Safety valves Safety valves are essential to the safe
operation of any pressure vessel, allowing adequate
relief of excess pressure during abnormal operating
conditions. The set point of each safety valve is normally immediately checked and adjusted if necessary
after reaching full operating pressure for the first time
with steam. Safety valve seats are susceptible to damage from wet steam or grit. This is an essential reason for cleaning the boiler and blowing out the superheater and steam line before testing safety valves.
Safety valves on drum-type boilers are normally
tested both for set point pressure and for the closing
pressures. This generally requires that the boiler pressure be raised until the valve opens and then reduced
for the valves to close.
The testing of safety valves always requires caution. Safety valve exhaust piping and vent piping
should not exert any excessive forces on the safety
valve. Gags should always be used as a safety measure while making adjustments to the valves.
As an alternate, safety valves can be tested and set
with the boiler pressure below the safety valve design
pressure by supplementing the boiler pressure with a
hydraulic lift, attached to the valve stem, in accordance
with the manufacturer’s instructions. This hydraulic
assist method reduces the risk of damage to the valve
seat from extended steam flow in a conventional test.
Startup Operating procedures vary with boiler design. There are, however, certain objectives that
should be included in the operating procedures of every boiler. These objectives include:
1. protection of pressure parts against corrosion,
overheating and thermal stresses,
2. prevention of furnace explosions,
3. production of steam at the desired temperature,
pressure and purity, and
4. compliance with environmental regulations.
Filling In filling the boiler for startup, certain precautions should be taken to protect the pressure parts.
First, high quality water should be used to minimize
water-side corrosion and deposits. Second, the temperature of the water should be regulated to match
the temperature of the boiler metal to prevent thermal stresses. High temperature differentials can cause
thermal stresses in the pressure parts and, if severe,
will adversely affect the life of the pressure parts. High
temperature differentials can also distort the pressure
parts enough to break studs, lugs and other attachments. Differential temperatures up to 100F (56C) are
generally considered acceptable.
A third precaution taken during the filling opera-

43-4

tion is the use of vents to displace all air with water.
This reduces oxygen corrosion and assures that all
boiler tubes are filled with water.
A fourth precaution on drum-type boilers is to establish the correct water level before firing begins. The
water level rises with temperature. Therefore, only 1
in. (25 mm) of water is typically required in the gauge
glass, except with certain special designs that may
require a higher starting level in order to fill all circulating tubes exposed to the hot flue gases.
Circulation Overheating of boiler tubes is prevented
by the flow of fluid through the tubes. Flow is produced
in the natural circulation-type boiler by the force of
gravity acting on fluids of different densities. Flow
starts when the density of the water in the heated tubes
is less than that in the downcomers. This flow increases
as firing rate is increased. (See Chapter 5.) Some drumtype boilers are designed for forced circulation and depend on a circulating pump to assist this flow.
The once-through type boiler depends on the boiler
feedwater pump to produce the necessary flow. Whenever a once-through boiler is being fired, a minimum
design flow must be maintained through the furnace
circuits. With the use of the bypass system, the fluid
can bypass the superheater and turbine to maintain
this minimum design flow until saturated steam is
available for admission to the superheater and until the
turbine is using sufficient steam to maintain the design minimum furnace circuit flow. (See Chapter 19.)
Purging Considerable attention has been given to
the prevention of furnace explosions, especially on
units burning fuel in suspension. Most furnace explosions occur during startup and low load periods. Whenever the possibility exists for the accumulation of combustible gases or combustible dust in any part of the
unit, no attempt should be made to light the burners
until the unit has been thoroughly purged. The National Fire Protection Association Boiler and Combustion Systems Code (NFPA 85:2004) provides the consensus procedures for purging of various boiler and
combustion systems. For multi-burner boilers, the
purge rate from the forced draft fan through the stack
is at least 25% of the full load mass air flow which
must be maintained for the greater of five minutes or
five volume changes of the boiler enclosure. A maximum of 40% of the full load mass air flow is specified
for coal-fired units only, while no upper limit is set for
oil- or gas-fired units.
Protection of economizer Very little water, if any,
is added to the drum-type boiler during the pressure
raising period; consequently, there is no feedwater
flow through the economizer. Economizers are located
in relatively low temperature zones. Nevertheless,
some economizers generate steam during the pressure
raising period. This steam remains trapped until feedwater is fed through the economizer. It not only makes
the control of steam drum water level difficult; it causes
water hammer. This difficulty is overcome if feedwater
is supplied continuously by venting the economizer of
steam or by recirculating boiler water through the
economizer. If a recirculating line is available, the valve
in this line must remain open until feedwater is being
fed continuously through the economizer to the boiler.


Protection of primary, secondary and reheat superheater During normal operation, every superheater

tube must have steam flow sufficient to prevent overheating. During startup and before there is steam flow
through every tube, the combustion gas temperature
entering the superheater section must be controlled
to limit superheater metal temperatures to 900F
(482C) for carbon steel tubes and 950 to 1000F (510
to 538C) for various alloy tubes. While firing rate is
used primarily to control gas temperatures, other
means are useful, e.g., excess air, gas recirculation and
burner selection.
Gas temperature entering the superheater during
startup is typically measured with retractable thermoprobes that are removed as soon as steam flow is established in every superheater tube. (See Chapter 40.)
Other permanent gas temperature monitoring devices
are available, but precautions must be taken so that their
installed locations, usage and maintenance are adequate
for the task of measuring gas temperatures entering the
superheater. These devices are required for the first few
startups to establish acceptable firing rates. They should
always be used on the once-through type boiler.
The two prerequisites for steam flow through every superheater tube are: 1) removal of all water from
each tube, and 2) a total steam flow equal to or greater
than approximately 10% of rated steam flow. Water
is removed from drainable superheaters by simply
opening the header drains and vents. Nondrainable
superheaters are not as simple, because the water
must be boiled away. There will be no steam flow
through a tube partially filled with water, and those
portions of the tube not in contact with water will be
subjected to excessive temperatures unless the gas
temperature is limited.
Thermocouples attached to the outlet legs of
nondrainable superheater tubes, where they pass
into the unheated vestibule, will read saturation temperature at the existing pressure until a flow of steam
is established through the tube. The temperature of
these outlet legs rises sharply to significant increases
above saturation immediately after flow is established.
Superheater tubes adjacent to side walls and division
walls are normally the last to boil clear. These should,
therefore, have thermocouples.
Protection of drums and headers In most installations, the time required to place a boiler in service is
limited to the time necessary for raising pressure and
protecting the superheater and the reheater against
overheating. In some cases, however, the time for both
starting up and shutting down may be determined by
the time required to limit the thermal stresses in the
drums and headers. Protection of drums and headers can
pose significant challenges for operators faced with the
need to cycle the steam generator on/off for load demand.
Various rules, based on thermal stress analysis and
supported by operating experience, have been formulated and accepted as general practice. The rules fall
into three categories: one for drums and headers with
rolled tube joints, a second set for headers with welded
tube joints, and a third set for steam drums with
welded tube joints.
On drums and headers with rolled tube joints, the


relatively thin tubes contract and expand at a much
faster rate than the thicker drum or header walls;
therefore, tube seat leaks are likely to occur if heating and cooling rates are not controlled. Heating and
cooling rates have, therefore, been established at 100F
(56C) change in saturation temperature per hour.
Headers with welded tube connections present no
problem with tube seat leaks or with header distortion because the tubes are welded to the headers and
the headers are normally filled with fluid at a constant
temperature. The concern is mainly with temperature
differentials through the header wall and the resulting
incipient cracking if excessive thermal stresses occur.
Steam drums with welded tube connections are not
subject to tube seat leaks but, because they contain
water in the bottom and steam in the top, the heating
and cooling rates vary between the top and the bottom. This results in temperature differences between
the top and the bottom. Stress analyses show that the
principal criterion for reliable rates of heating and
cooling should be based on the relationship between
the temperature differential through the drum wall
and the temperature differential between the top and
bottom of the drum, both of which are measured in
the same circumferential plane. Analysis also shows
that the allowable temperature differentials are based
on tensile strength, drum diameter, wall thickness and
pressure. Therefore, each steam drum has its own
characteristics.
To determine the temperature differentials during
the periods of startup and shutdown, it is necessary
to continuously and accurately obtain the outside and
inside surface temperatures of the drum shell. Temperatures of the outside of the drum shell are best
determined by thermocouples. At least six outside thermocouples are required: two on each end, one on the
top and bottom (all outside the internal baffle and
scrubber area) and two in the center, one top and one
bottom. Temperatures of the inside of the drum shell
are best determined by placing thermocouples on one
of the riser tubes entering the bottom of the drum, one
on each end, and one in the center.
There are two periods when the steam in the top of
the drum is hotter than the water occupying the lower
half. One period is soon after firing begins on boilers
with large nondrainable superheaters. Steam forms
first in the superheater and flows back to the steam
drum where it heats the top of the drum. A second
period is during cooling when cold air is pumped
through the boiler by the forced draft fans. The boiler
water cools, but the steam in the top of the steam drum
remains at essentially the same temperature.
The temperatures of the top and bottom can be
brought close together by flooding the steam drum
with water. Firing must be stopped and water must
not be allowed to spill over into the superheater. A high
level gauge glass is needed for this operation. However, thermocouples attached to the superheater supply tubes can be used to indicate when the drum is
flooded because there is a sharp change in temperature when water enters these supply tubes. Allowable
temperature differentials for cooling are stringent,
considerably more so than for heating. Fast cooling

43-5

should, therefore, be supervised with the use of thermocouples and a high level gauge glass.
Cooling is particularly important when the boiler
is to be drained for short outages. The steam drum
must be cooled to permit filling with the available
water without exceeding the allowable temperature
rate of change. (See Fig. 1.) A wider latitude is permitted if the water used for filling is hotter than the
steam drum.
Before removing the unit from service, a more uniform cooling can be achieved by reducing pressure to
approximately two-thirds of the normal operating
pressure. This reduces the temperature of both the
water and steam in the steam drum.

Rate of Change, F(C)/h

Operating techniques for maximum efficiency
Fuel is a major cost in boiler operation. It is therefore important to minimize fuel consumption and
maximize steam production. Although a boiler’s efficiency is primarily a result of its design, the operator
can maintain or significantly improve efficiency by
controlling heat losses to the stack and losses to the
ash pit.
Stack losses The total heat that exits the stack is
controlled by the quantity and the temperature of the
flue gas. The quantity of gas is dependent on the fuel
being burned, but is also influenced by the amount
of excess air supplied to the burners. While sufficient
air must be provided to complete the combustion process, excessive quantities of air simply carry extra heat
out of the stack.
The temperature of the flue gas is affected by the
cleanliness of the boiler heat transfer surfaces. This
in turn is dependent on sootblower and air heater
operation. Optimal cleanliness of the heat transfer
surfaces is achievable with commercial sensors and
control systems that measure the heat transfer effectiveness of the boiler banks, evaluate against the design duty, and clean only on an as-needed basis. While
high gas exit temperatures waste energy, excessively
low temperatures may also be unacceptable. Corrosion
can occur at the acid dew point of the gas where corrosive constituents condense on the cooler metal surfaces.
Ash plugging of heat transfer surfaces can be aggravated by the presence of condensate. Equipment protec-

400
(222)
Unsafe
300
(167)
Safe
200
(111)

0
0

100
200
300
400
500
(56)
(111)
(167)
(222)
(278)
Total Change of Saturation Temperature, F(C)

600
(333)

Fig. 1 Permissible rate of change for saturation temperature, drum
and furnace.

43-6

tion and performance of backend environmental components [selective catalytic reduction (SCR) system protection, for example] can also be constraints in desirable
steam generator gas temperature.
Pressures and temperatures Most boilers supply
steam to turbines or processes that require heat. These
processes rely on design pressures and temperatures.
Deviations from the set points may result in lower overall efficiency of the power cycle, loss of production, or
damage to the product or process.
In units that produce saturated steam, boiler temperature is directly related to the operating pressure.
For many industrial applications, the process requirements dictate the steam temperature and consequently the operating pressure.
For electric power producing steam systems, steam
temperature has a significant impact on turbine efficiency. Modern controls can typically maintain this
temperature within 10F (6C) of the desired setting.
Each 50F (28C) reduction in steam temperature reduces cycle efficiency by approximately 1% on a supercritical pressure unit.
Variable pressure operation Historically, utility
power boilers in the United States (U.S.) have been
operated at a constant steam pressure and the turbine
load has been controlled by varying the throttle valves
at the turbine inlet. This causes an efficiency loss due
to the temperature drop across the throttle valves.
In variable pressure operation, boiler pressure is
varied to meet turbine requirements. This can significantly improve cycle efficiency when operating at low
loads (15 to 40% of MCR). However, boiler response
to turbine requirements is slower in this mode. When
fast response is needed, pressure increments are used.
At a given pressure, the throttle valves control the
steam to the turbine and provide quick response. As
turbine requirements increase and the valves approach full open position, the boiler pressure is increased to the next increment. This arrangement provides high efficiency while retaining quick response.
Emissions requirements The majority of the steam
generators in operation today were not originally designed for today’s environmental regulations. Hardware changes made to accomplish the emissions reduction are typically accompanied by new operating
philosophies and guidelines for efficiency and equipment protection. To maintain optimal SCR efficiency
and minimal ammonia usage/slip the combustion system is optimized to generate the lowest level of nitrogen oxides (NOx) possible. Staging of combustion air
is frequently used in firing system upgrades. Sufficient care must be taken to ensure that lower furnace
corrosion associated with the reducing atmosphere is
not excessive, especially with high sulfur content fuels. Depending on system design, there may be
tradeoffs between lower NOx generation and increases
in the carbon content in the ash and carbon monoxide (CO) in the flue gas. To maintain ash quality suitable for disposal/sale, operational balance must be
achieved within the combustion process. Furnace combustion is also usually controlled to achieve any specific CO emissions rate.
Combustion optimization A modern DCS is equipped


to offer significantly more information and analysis,
assisting the operating personnel in optimizing the
steam generator. Closed loop neural network systems
and other advanced intelligent control systems have
made strides in maintaining optimum operations consistently throughout the operating range. Variants of
these systems use complex databases and algorithms
of unit-specific operating scenarios to guide the controlling parameters during steady state and transient
operation. Extensive parametric testing of the unit is
conducted to define the characteristics and boundaries
of the operating variables. As long as no subsequent
mechanical modifications are added and proper equipment maintenance is available, these advanced control systems are capable of consistently returning the
steam generator to its most optimum operating condition. A significant attribute of these systems is the
ability to target specific results during optimization
and change the targeted parameter as needed. As the
result, NOx can be minimized during selected periods
and heat rate can be minimized the rest of the operating year.

Key operation functions
Burner adjustments The fuel and combustion air
combine and release heat at the burners. To maintain
even heat distribution across the width of the furnace,
air and fuel flows must be evenly supplied to all burners. While individual burner adjustments affect a
particular burner, they also impact adjacent burners.
Most boilers have multiple burners in parallel flow
paths on the front and/or rear furnace walls. Burners must be similar in design and must be adjusted in
the same way to optimize air flow distribution. For a
detailed discussion of burner features refer to Chapters 11 and 14.
Adjustments can typically vary the turbulence and
flow rates in burners. Increased turbulence increases
the air-fuel mixing. It also increases the combustion
intensity, provides faster heat release, reduces unburned carbon (UBC) in the ash, permits operation
with less excess air, and increases boiler efficiency.
However, increased slagging, increased NOx emissions
and higher fan power consumption can also result.
Fuel adjustments on an individual burner basis are
also possible, either through diverter mechanisms in
the fuel preparation system or through flow balancing devices in the coal transport piping. While possible,
the dynamic balancing of fuel flows is difficult. As with
combustion air adjustments, potential impacts to adjacent burners will require reliable feedback on relative flow rates to be effective as a dynamic operational
tool. Advances in flame characterization systems and
sensors for post-combustion constituents are providing more precise feedback targets for on-line fuel balancing, as are in situ coal and combustion air flow
measurement devices.
Overfire air port adjustments Burner systems intended for NOx reduction are typically staged at the
primary combustion elevation and usually operated
with less than theoretical air for complete combustion.
The remaining air needed to complete the burning process is introduced separately, above the highest burner

zone. The overfire air (OFA) flows are typically varied as a function of load, based on parametric testing
performed during commissioning. While normally satisfactory for ensuring complete combustion and emissions compliance, any changes to fuel type, fuel preparation quality, or the fuel/air transport systems will
require close monitoring of OFA system performance.
More advanced dynamic control schemes are available, dependent on measurement feedback of the combustion process in the upper furnace zones.
Excess air The total combustion air flow to a boiler
is generally controlled by adjusting forced and induced
draft fan dampers in relation to the fuel flow. Excess
air is the amount of additional combustion air over that
required to theoretically burn a given amount of fuel.
The benefits of increasing excess air include increased
combustion intensity, reduced carbon loss and/or CO
formation, and reduced slagging conditions. Disadvantages include increased fan power consumption, increased heat loss up the stack, increased tube erosion,
and possibly increased NOx formation.
For most coal ashes, particularly those from eastern U.S. bituminous coals, the solid to liquid phase
changes occur at lower temperatures if free oxygen is
not present (reducing conditions) around the ash particles. As a result, more slagging occurs in a boiler
operating with insufficient excess air where localized
reducing conditions can occur.
Localized tube metal wastage may also occur in
furnace walls under low excess air conditions but the
impact is less clearly defined. The absence of free oxygen (a reducing atmosphere) and the presence of sulfur (from the fuel) are known causes of tube metal
wastage. The sulfur combines with hydrogen from the
fuel to form hydrogen sulfide (H2S). The H2S reacts
with the iron in the tube metal and forms iron sulfide,
which is subsequently swept away with the flue gas.
High chlorine levels can also promote tube wastage.
Although coals and most conventional fuels burned
in the U.S. contain very little chlorine, it is a problem
in refuse-derived fuels. (See Chapter 29.)
Fuel conditions Fuel conditions are temperature,
pressure and, if solid, mean particle size and distribution. Cooler temperatures, lower pressure and
larger particle size contribute to less complete combustion and increased unburned carbon in the ash. Conversely, if the fuel is hotter, finer and at a higher pressure, combustion is improved. Unfortunately NOx emissions and slagging can also increase with these conditions. Current day combustion technologies employ
multi-zone low NOx burners to control the pace of combustion and are more demanding on mean particle size
and distribution for control of NOx and UBC production.
Effects of fuel preparation equipment on boiler performance Fuel preparation equipment readies the fuel
for combustion and can have a significant impact on
pollutant emissions. The preparation equipment may
be the crushers, pulverizers and drying systems on
coal-fired units; fuel oil heaters and pumps on oil-fired
units; refuse handling, mixing or drying equipment
on refuse-fired boilers; or fuel handling, blending, sizing and delivery equipment on stoker-fired units. If
this equipment is not properly operated, the fuel may

43-7

not be completely burned, leaving UBC in the ash or
carbon monoxide (CO) in the flue gas.
The operator must monitor the fuel preparation
equipment. Knowledge of the equipment, its maintenance record and operating characteristics is essential.
Feedwater and boiler water conditioning requirements
The main function of a boiler is to transfer heat from
combustion gases through tube walls to heat water and
produce steam. Clean metal tubes are good conductors, but impurities in the water can collect on the
inside surface of the tubes. These deposits reduce heat
transfer, elevate tube temperatures, and can lead to
tube failures. Water conditioning is essential to minimize deposits and maintain unit availability. (See
Chapter 42.)
Sootblower operations As discussed in Chapter 24,
a sootblower is an automated device that uses steam,
compressed air, or high pressure water to remove ash
deposits from tube surfaces. Sootblowing improves heat
transfer by reducing fouling and plugging. However,
excessive sootblowing can result in increased operating cost, tube erosion and increased sootblower maintenance. Conversely, infrequent sootblower operation
can reduce boiler efficiency and capacity. Optimum
sootblowing depends on load conditions, combustion
quality and fuel. With the increased dependency in
the U.S. on Powder River Basin (PRB) coal and the
cost attractiveness of spot market fuels, advanced sootblowing control systems are being increasingly deployed to assist the operators. Unlike manual guidelines, these intelligent systems do not rely on fuel
characteristics to influence cleaning patterns. Rather,
they focus primarily on the heat transfer surfaces and
monitor efficiency. Since cleaning decisions are based
solely on an as-needed basis, the intelligent sootblowing systems are ideally suited for operations dealing
with changing fuel blends. Furnace-based sootblowing
equipment is increasingly being controlled with advanced control schemes that monitor the heat flux in
select zones, supervise blower operation for effectiveness,
and minimize thermal shock to the furnace wall tubes.
Personnel safety Operating instructions usually
deal primarily with the protection of equipment. Rules
and devices for personnel protection are also essential. The items listed here are based on actual operating experience and point out some personnel safety
considerations.
1. When viewing flames or furnace conditions, always wear tinted goggles or a tinted shield to protect the eyes from harmful light intensity and flying ash or slag particles.
2. Do not stand directly in front of open ports or
doors, especially when they are being opened.
Furnace pulsations caused by firing conditions,
sootblower operation, or tube failure can blow hot
furnace gases out of open doors, even on suctionfired units. Aspirating air is used on inspection
doors and ports of pressure-fired units to prevent
the escape of hot furnace gases. The aspirating jets
can become blocked, or the aspirating air supply can
fail. In some cases, the entire observation port or door
can be covered with slag, causing the aspirating air
to blast slag and ash out into the boiler room.
43-8

3. Do not use open-ended pipes for rodding observation ports or slag on furnace walls. Hot gases
can be discharged through the open ended pipe
directly onto its handler. The pipe can also become
excessively hot.
4. When handling any type of rod or probe in the
furnace, especially in coal-fired furnaces, be prepared for falling slag striking the rod or probe.
The fulcrum action can inflict severe injuries.
5. Be prepared for slag leaks. Iron oxides in coal can
be reduced to molten iron or iron sulfides in a
reducing atmosphere in the furnace resulting
from combustion with insufficient air. This molten iron can wash away refractory, seals and
tubes, and leak out onto equipment or personnel.
6. Never enter a vessel, especially a boiler drum,
until all steam and water valves, including drain
and blowdown valves, have been closed and
locked or tagged. It is possible for steam and hot
water to back up through drain and blowdown piping, especially when more than one boiler or vessel
is connected to the same drain or blowdown tank.
7. Be prepared for hot water in drums and headers
when removing manhole plates and handhole covers.
8. Do not enter a confined space until it has been
cooled, purged of combustible and dangerous
gases and properly ventilated with precautions
taken to keep the entrance open. Station a worker
at the entrance and notify the responsible person.
9. Be prepared for falling slag and dust when entering the boiler setting or ash pit.
10. Use low voltage extension cords or cords with
ground fault interrupters. Bulbs on extension
cords and flashlights should be explosion proof.
11. Never step into flyash. It can be cold on the surface yet remain hot and smoldering underneath
for extended periods even after the pressure parts
are cool.
12. Never use toxic or volatile fluids in confined
spaces.
13. Never open or enter rotating equipment until it
has come to a complete stop and its circuit breaker
is locked open and any other drive devices are
immobilized. Some types of rotating equipment
can be set into motion with very little force. These
types should be locked with a brake or other suitable device to prevent rotation.
14. Always secure the drive mechanism of dampers,
gates and doors before passing through them.
15. Do not inspect for tube leak locations until metal
and refractory surfaces are cool, and ash accumulations are removed.
Performance tests Many steam generating units are
operating day after day with efficiencies at or near
design values. Any unit can operate at these efficiencies with the proper instrumentation, a reasonable
equipment and instrument maintenance program,
and proper operating procedures.
Early in the life of the unit when the gas side is
relatively clean, the casing is tight, the insulation is
new, the fuel burning equipment has been adjusted
for optimum performance and the fuel/air ratio has

been set correctly, performance tests should be conducted to determine the major controllable heat losses.
These losses are the dry gas to the stack and, on coalfired units, combustible in the ash or slag.
During these tests, accurate data should be taken
to serve as reference points for future operation. Sampling points that give representative indications of
gas temperatures, excess air and combustibles in the
ash should be established and data from these points
recorded. Items related to the major controllable losses
should also be recorded at this time, e.g., draft losses,
air flows, burner settings, steam flow, steam and feedwater temperatures, fuel flow and air temperatures.
Procedures for performance tests are provided in the
American Society of Mechanical Engineers (ASME)
Performance Test Codes, PTC 4, Steam Generating Units;
PTC 4.2, Coal Pulverizers; and PTC 4.3, Air Heaters.
Abnormal operation
Low water If water level in the drum drops below
the minimum required (as determined by the manufacturer), fuel firing should be stopped. Caution
should be exercised when adding water to restore the
drum level due to the potential of temperature shock
from the relatively cooler water coming in contact with
hot drum metal. Thermocouples on the top and bottom of the drum will indicate if the bottom of the drum
is being rapidly cooled by feedwater addition, which
would result in unacceptable top-to-bottom temperature differentials. If water level indicators show there
is still some water remaining in the drum, then feedwater may be slowly added using the thermocouples
as a guide. If the drum is completely empty, then water may only be added periodically with soak times
provided to allow drum temperature to equalize. (See
Protection of drums and headers.)
Tube failures Operating a boiler with a known tube
leak is not recommended. Steam or water escaping
from a small leak can cut other tubes by impingement
and set up a chain reaction of tube failures. By the
loss of water or steam, a tube failure can alter boiler
circulation or flow and result in other circuits being
overheated. This is one reason why furnace risers on
once-through type boilers should be continuously
monitored. A tube failure can also cause loss of ignition and a furnace explosion if re-ignition occurs. As
discussed later in the chapter, process recovery boilers are particularly sensitive to tube leaks because of
the potential for smelt-water reactions, which can lead
to boiler explosions.
Any unusual increase in furnace riser temperature
on the once-through type boiler is an indication of
furnace tube leakage. Small leaks can sometimes be
detected by the loss of water from the system, the loss
of chemicals from a drum-type boiler, or by the noise
made by the leak. If a leak is suspected, the boiler
should be shut down as soon as normal operating procedures permit. After the leak is then located by hydrostatic testing, it should be repaired.
Several items must be considered when a tube failure occurs. In some cases where the steam drum water
level can not be maintained, the operator should shut
off all fuel flow and completely shut off any output of
steam from the boiler. When the fuel has been turned

off, the furnace should be purged of any combustible
gases and feedwater flow to the boiler should be
stopped. The air flow should be reduced to a minimum
as soon as the furnace purge is completed. This procedure reduces the loss of boiler pressure and the corresponding drop in water temperature within the boiler.
The firing rate or the flow of hot gases can not be
stopped immediately on some waste heat boilers or on
certain types of stoker-fired boilers. Several factors are
involved in the decision to continue the flow of feedwater, even though the steam drum water level can
not be maintained. In general, as long as the temperature of the combustion gases is hot enough to damage the unit, the feedwater flow should be continued.
(See later discussion for chemical recovery units.) The
thermal shock resulting from feeding relatively cold
feedwater into an empty steam drum should also be
considered. (See Protection of drums and headers.)
Thermal shock is minimized if the feedwater is hot,
the unit has an economizer, and the feedwater mixes
with the existing boiler water.
After the unit has been cooled, personnel should
make a complete inspection for evidence of overheating and for incipient cracks, especially to headers,
drums, and welded attachments. (See Personnel
safety, especially when the potential of hot materials,
boiler fluids, or combustibles is present.)
An investigation of the tube failure is very important so that the condition(s) causing the tube failure
can be eliminated and future failures prevented. This
investigation should include a careful visual inspection of the failed tube. In some cases, a laboratory
analysis or consideration of background information
leading up to the tube failure is required. This information should include the location of the failure, the
length of time the unit has been in operation, load
conditions, startup and shutdown conditions, feedwater treatment and internal deposits.

Shutdown operations
Boiler shutdown is less complicated than startup.
The emphasis again is on safety and protection of unit
materials. Two shutdown situations may occur: a controlled shutdown, or one required in an emergency.
Under controlled conditions, the firing rate is gradually reduced. Once the combustion equipment is
brought to its minimum capacity, the fuel is shut off
and the boiler is purged with fresh air. If some pressure is to be maintained the fans are shut down and
the dampers are closed. The drum pressure gradually
lowers as heat is lost from the boiler setting; a minimal amount of air drifts out of the stack. If inspection
and maintenance are required, the draft fans remain
on to cool the boiler more quickly. If the unit is
equipped with a regenerative air heater, it is shut
down, allowing the boiler to cool faster. If a tubular
air heater is present, this heat trap can only be bypassed
to help cool the boiler. The cool down rate should not
exceed 100F (56C) per hour of saturation temperature
change to prevent damage due to thermal stress.
In an emergency shutdown, the fuel is immediately
shut off and the boiler is purged of combustible gases.
Additional procedures may apply to the fuel feed equip43-9

ment. The boiler may be held at a reduced pressure
or may be completely cooled as described above.

Operation of Cyclone furnaces
The Cyclone component of a Cyclone™ furnace is
a cylindrical chamber designed to burn crushed coal.
The basic design, sizing and general operation of Cyclone furnaces are covered in Chapter 15. The key
feature that affects operations is the collection of most
of the coal ash as a liquid slag in the Cyclone chamber. This slag is continuously tapped into the furnace
through a hole at the discharge end of the Cyclone.
The slag collects on the furnace floor and flows through
a tap into a water filled tank where the chilling effect of
the water leaves the slag in granular form. Unique operational issues center upon maintaining desired furnace
slag tapping without excessive maintenance.

Fuels
A key operating parameter of Cyclone units is the
selection of a proper coal. Fuels acceptable for Cyclone
firing must generally meet the following specifications
subject to site-specific conditions:
Bituminous coals:
1. maximum total moisture – 20%
2. ash content – 6 to 25%, dry basis
3. minimum volatile matter – 15%, dry basis
4. ash (slag) viscosity – refer to Table 2
5. ash iron ratio and sulfur content – See Chapter
15, Fig. 4
Subbituminous coals and lignite:
1a. maximum total moisture for a direct-fired system,
but without a pre-dry system – 30%
1b. maximum total moisture with pre-dry system –
42%
2. minimum high heating value – 6000 Btu/lb
(13,956 kJ/kg), as-fired
3. ash content – 5 to 25%, dry basis
4. ash (slag) viscosity – refer to Table 2
For proper combustion and efficient unit operation,
properly sized crushed coal is required. This is especially important for subbituminous coals, where the
higher moisture content requires a finer coal grind to
maintain Cyclone temperatures and to minimize unburned carbon in the flyash.

Combustion air
All Cyclone furnaces use heated air at a high static
pressure. The air temperature ranges from 500 to 750F
(260 to 399C), depending on the unit design and the
rank of the fuel. The static differential across the
Cyclone ranges from 32 to 50 in. wg (8 to 12.5 kPa).
This high pressure produces the very high velocities
which, in turn, produce the scrubbing action required
for complete combustion of the crushed coal.
A key variable in Cyclone operation is excess air.
For bituminous coals, which are generally high in
sulfur and iron content, 15 to 18% excess air is recommended at full load operation. Operation at lower
excess air can promote an oxygen-deficient reducing
atmosphere, which can significantly increase unit
43-10

maintenance. Operation with molten slag and deficient air can result in iron sulfide attack (wastage) of
the boiler tubes. When operated with insufficient excess air, fuels with high iron content can smelt the iron
from the ash. A pig iron, which forms a strong bond
to the boiler tubing, can form and may result in tube
damage during deposit removal.
Operation with high levels of excess air leads to
lower thermal efficiency and results in Cyclone cooling. This hinders slag tapping. On multiple Cyclone
units, it is important to accurately measure the secondary air and coal flow to each Cyclone to ensure it
is operating with the proper air/fuel ratio.
Because proper excess air is essential, theoretical
air curves should be used to readjust the excess air
levels when one unit of a multiple Cyclone furnace is
removed from service.
Firing subbituminous coals is generally more difficult due to increased fuel moisture which must be
evaporated during combustion. Units designed for
subbituminous coal firing have provisions for higher
air temperature and generally run with 10 to 12%
excess air.
Due to environmental concerns, some bituminous
coal-fired Cyclone furnaces have been converted to
burn low sulfur subbituminous coal or coal blends.
Subbituminous coal has a lower ash content than most
bituminous coals. As a result, less slag is available to
trap the raw coal particles. This, combined with the
depressed flame temperature caused by the increased
moisture content, can result in less coal being entrapped in the slag where the combustion is completed.
Acting on the additional environmental concerns, utilities have installed OFA systems for combustion NOx
control. While furnace wall corrosion remains a concern, worthwhile NOx reductions have been attained
with fuel rich stoichiometry and lower sulfur fuels. These
Cyclone operating techniques have changed the operating practices of these slagging combustors.
When firing higher moisture subbituminous coal,
smaller crushed coal particle size is required and
higher transport air temperature is desired.

Table 2
Ash Viscosity Requirements
Maximum T250*
Coal Rank Ash Viscosity

As-Fired
Total Moisture %

Bituminous
2450F (1343C)
Subbituminous − direct-fired
2300F (1260C)
Subbituminous/lignite**
2300F (1260C)
Lignite***
2300F (1260C)

0 to 20
21 to 30
31 to 35
36 to 42

* T250 is the temperature at which the ash viscosity
is 250 poise.
** For lignite firing, a fuel pre-dry system is required.
*** For high moisture lignite firing, pre-dry and
moisture separator systems are required.


As the moisture content reaches the 20% range at
design Cyclone fuel inputs, clinkering and UBC in the
Cyclone and on the furnace floor can increase dramatically. Levels of unburned carbon also increase in
the ash in the economizer, air heater and precipitator
hoppers. Supplemental firing with fuel oil or natural
gas along with design changes may be required if the
unit was not originally designed for this condition.
Several Cyclone units are operating on high moisture North Dakota lignite fuel. This is accomplished
by the use of a pre-dry system, as illustrated in Chapter 15. In this system, hot air [750F (399C)] is introduced to the raw coal stream prior to crushing in a pressurized and heated conditioner. The hot air-coal mixture
then travels to a cyclone separator, where the saturated
air and some coal fines are separated from the coal
stream and are injected into the lower furnace. The dried
coal is then carried by a lift line to the Cyclone burner.

Operation of once-through boilers
Principles
In full once-through operation, high pressure water enters the economizer and high pressure steam
leaves the superheater; there is no recirculation of
steam or water within the unit. The path is through
multiple parallel tube circuits arranged in series. Design and construction details are found in Chapters
19 and 26. This type of boiler can be conceptualized
as a long heated pipe with continuous coolant flowing through it. As the fluid progresses through the
components, heat is absorbed from the combustion
process. The final steam temperature is dependent on
the feedwater inlet temperature and ratio of the fluid
flow to the heat available, which have important implications on unit operation.
Operating practice
The once-through steam generator, referred to by
The Babcock & Wilcox Company (B&W) as the Universal Pressure (UP) boiler, has operating characteristics not seen in drum units. The UP boiler is capable
of operating above the critical pressure point [3200 psi
(22.1 MPa)] and can deliver steam pressure and temperature conditions without a steam-water separation
device after startup. The original UP boilers are typically designed and operated for base load operation.
To address the increasing demand for operational flexibility, the B&W Spiral Wound Universal Pressure
(SWUP) boiler is capable of variable pressure operation and on/off cycling, as well as load cycling and base
load operation. This spiral wound tube geometry UP
boiler, including its startup and bypass systems, minimize the thermal upsets during transients, allowing
rapid load changes.
To start up a UP boiler, a steam/water separation
device (flash tank or vertical steam separator), with
appropriate valving and piping to bypass and return
fluid to the cycle, is supplied. The modern bypass systems are highly automated and very effective in
achieving smooth operation. The bypass system is in
service only during low load operation.

The major control functions for fuel, air, water and
steam flow are highly interactive placing unique constraints on operation. Though today’s integrated control systems manage many operating functions, it is
still important for the operator to fully understand the
relationships between short-term (transient) and longterm (steady-state) energy transfer effects and to carefully monitor and coordinate, as required, all control
actions. Modern control systems are often referred to
as coordinated systems. (See Chapter 41.) The combustion systems are conventional; they are subject to the
normal concerns of fuel utilization, efficiency and safety.
The operator has three main controls for operating
a UP boiler:
1. firing rate,
2. feedwater control, and
3. steam flow/steam pressure.
Firing rate The long-term demand for firing rate is
directly proportional to load. The short-term effects of
firing rate impact steam temperature and pressure.
During increases in firing rate the steam temperature
increases until the feedwater flow is increased to compensate and balance the new firing rate. Steam pressure increases in a similar fashion to that of a drum
boiler. In a supercritical pressure application, there is
no large rise in specific volume during the transition
from liquid to vapor conditions. However, there is still
a large increase in specific volume as a supercritical
fluid is heated. With this expansion, the turbine control valves are opened and flow is increased to maintain pressure. With the many interactions that are a
consequence of firing rate, the operator and automated control system should strive to position firing
rate for the desired electrical load and then manipulate
other variables to control temperature and pressure.
Feedwater flow The outlet steam temperature is
dependent in steady-state conditions on the ratio of
feedwater flow rate to firing rate. Because it is desirable to position firing rate based on electrical demand,
feedwater flow control is based on outlet steam temperature. The short term effect of feedwater flow
changes is to increase or decrease steam pressure and
electrical load. The load change results because energy is placed into or brought out of storage through
cooling or heating of the boiler metals. However, this
load change is transitory. Pressure is a measure of the
balance between steam flow and feedwater flow. The
outlet pressure is constant if they are matched. The
operator can, therefore, use feedwater to assist in recovery from transients and upsets, but ultimately must
position feedwater flow for the appropriate outlet steam
temperature.
Steam flow/steam pressure In steady-state conditions, steam flow is the same as feedwater flow, and
boiler pressure is determined by turbine throttle valve
position. In the short term, a change in steam flow
impacts steam temperature and electrical load. This
is because increasing steam flow at a constant firing
rate affects the balance of the two and the steam temperature drops initially as a consequence to electrical
load increase. This can not be a lasting effect, however, as steam and feedwater flows eventually match

43-11

each other at a different pressure. Similarly, load may
be changed by adjusting the turbine throttle valve
which increases or decreases steam flow, but this load
change comes from depleting or building stored energy in the form of pressure. As above, steam flow may
be manipulated to help restore control of steam temperature and load, but it ultimately must be controlled
to achieve the desired operating pressure.

Operating skills
Efficiency The supercritical boiler provides very
high cycle efficiency. This inherent efficiency can be
maintained throughout boiler life with proper instrumentation and maintenance. The operator must be
thoroughly trained to know the optimum operating
parameters. Deviations in these parameters may then
be addressed with instrument maintenance, direct
operator action (such as sootblowing) or an engineering investigation. Performance tests should be conducted on a regular basis. Besides the conventional
need to minimize heat losses, these tests can be used
to confirm control system calibration. Test results
should be reviewed with the operator.
Startup systems Chapter 19 provides a comprehensive overview of the configuration and operation of
state-of-the-art startup and bypass systems for variable and constant furnace pressure once-through
boiler systems. Systems for UP boilers have evolved
as the understanding and experience of the oncethrough concept have increased. A key requirement
for the startup system is to maintain adequate flow
in the furnace walls (30% for most variable pressure
supercritical units, 25% for most constant pressure
supercritical units, and 33% for most subcritical units)
to protect them from overheating during startup and
low load operation. Initial designs (first generation)
simply bypassed any excess flow from the furnace, not
required for the turbine power generation, directly to
the condenser from the high pressure turbine inlet.
Second generation startup systems added a steamwater separation device called a flash tank (including steam-water separation equipment) after the convection pass enclosure circuits, but upstream of the
primary superheater. This permitted the generation
of dry steam for turbine roll and synchronization. The
flash tank was effectively a small drum including
drum internals. (See Fig. 2.)
Subsequent constant pressure third generation designs moved the bypass line plus necessary valves
(200 and 201) downstream of the primary superheater
so that the primary superheater is always in the initial flow circuit. (See Fig. 3 for key elements.)
Steam is produced in the flash tank because the
pressure reducing valve (207 in Fig. 3) drops the pressure from supercritical to approximately 1000 psig
(6.89 MPa) in current designs. For a smooth transition or changeover from startup (flash tank) to oncethrough operation, the enthalpy of the flash tank steam
must be matched with the enthalpy leaving the 201
valve. Because the flash tank generally operates at
1000 psig (6.89 MPa), the throttle pressure to the turbine is only ramped to full pressure after transition
from the flash tank.
43-12

Due to the need for flexibility of the variable furnace pressure SWUP designs, startup and bypass
systems have changed to incorporate features of the
subcritical drum and supercritical once-through
startup systems. As shown in Fig. 4 (key elements
only), the SWUP system has evolved from the second
generation system shown in Fig. 2 with the replacement of the valves and flask tank with vertical steam
separators, a water collection tank and a boiler circulation pump. At startup and low load, the flow passes
through the vertical steam separators where steam is
removed and sent to the superheater and water is
discharged to the water collection tank. Water then
flows through the boiler circulation pump to maintain
the minimum furnace wall circulation. Any excess
water accumulated during startup is sent to the condenser through the 341 valves. When unit operation
reaches the load where the sum of the furnace flow
plus the attemperator spray flows is equal to the main
steam flow rate, once-through operation is achieved,
the 381 valves are closed, and the boiler circulation
pump is shut down.
Limits and precautions The once-through nature of
UP boilers results in special limits and precautions that
must be observed for reliable and dependable operation:
1. Feedwater conductivity – unlike a drum boiler
which can release suspended solids through
blowdown, all hardness and other contaminants
that enter the boiler in the feedwater are deposited on the water side of the heating surface or in
the superheater. Deposition can lead to overheating and tube failures. Boiler firing must be stopped
if conductivity exceeds 2.0 microsiemens for five minutes or if it exceeds 5.0 microsiemens for two minutes. The operator should be trained in water quality control requirements. (See Chapter 42.)
2. Minimum feedwater flow – firing is not permitted
unless the boiler feedwater flow is above the specified minimum. The boiler is to be immediately shut
down if flow falls below 85% of minimum for twenty
seconds or 70% of minimum for one second.

Fig. 2 Second generation UP startup system schematic.



Fig. 3 Third generation UP startup system with primary superheater
in initial flow circuit.

3. Feedwater temperature – the heat input required
per unit of water flow is dependent on the difference between the feedwater inlet temperature and
the controlled outlet steam temperature. If feedwater temperature is reduced while the outlet temperature is maintained (by overfiring), the heat
input to the furnace can exceed design levels that
may result in damage to the tube material. For
units that were not designed for a feedwater
heater out of service, removal of a feedwater
heater will require that the final steam temperature be reduced to hold furnace heat input rates
within design limits. Unless specific information
is provided, the general rule is to reduce steam
temperature one degree F for every two degrees
F that the feedwater temperature is low.

TTV

Spray Water
Attemperator
Secondary
Superheater

HP

Reheater

Primary
Superheater
Convection Pass
Vertical
Steam
Separator(s)

L

P

341

Furnace
Economizer
381

Water
Collection
Tank
Boiler
Circulation
Pump

Fig. 4 Startup system for a SWUP boiler (key elements).


IP

Condenser

4. Overfiring – for supercritical units, the fluid in the
furnace has no latent heat of vaporization as in a
subcritical boiler. Consequently, as heat is absorbed,
the fluid temperature is always increasing and the
furnace tube metal temperatures increase. Firing
in excess of design rates can result in excessive tube
metal temperatures in selected furnace locations.
The operator must therefore observe a strict limit
of transient heat input. A maximum of 1.15 times
the steady-state rate is a typical guideline. This rate,
at various load conditions, should be clearly established by combustion tests.
5. Tube leaks – operation with a tube leak is not recommended on any boiler. For once-through units,
the situation is more critical because the leakage
can reduce cooling flow to subsequent tubes or
circuits downstream.
6. Low pressure limit – a constant pressure supercritical
UP boiler must be tripped if the fluid pressure in the
furnace falls below 3200 psig (22.1 MPa) for fifteen
seconds. Failure to do so can result in improper circuit flow, inadequate tube cooling and furnace tube
failures. For the SWUP boilers the units are designed
for specific variable pressure ramps. To avoid possible tube damage, the units must operate along design pressure ramp curves.

Operation of fluidized-bed boilers
Chapter 17 provides a detailed discussion of fluidized-bed combustion systems. The following sections
provide selected remarks on general fluidized-bed
boiler operation, both circulating fluidized-bed (CFB)
systems and bubbling fluidized-bed (BFB) systems.

CFB systems overview
The CFB is constructed and behaves like a conventional drum boiler in many respects. However, thermal performance, combustion efficiency, furnace absorption pattern and sulfur dioxide (SO2) control are
strongly influenced by the mass of solids in the bed
(inventory), the size distribution of the bed material
(bed sizing), and the circulating rate of the bed (flow
rate). Bed density can be described as bulk density
which is a measure of the material weight per unit
volume. There is a higher density and inventory in
the lower furnace, made of coarser particles (average
size 200 to 400 micron), and a lower density and inventory in the upper furnace (also called furnace
shaft) made of finer particles (average size 100 to 200
micron). Fig. 5 shows the density of the bed with respect to furnace height and indicates the effect of load.
To integrate these influences into operating procedures, the CFB is equipped with additional instrumentation which provides operator input for bed management. These inputs are as follows:
1. Primary zone ∆P – The gas-side differential pressure
is measured across the primary furnace zone [from
the air distribution grid to an intermediate elevation
of about 6 ft (1.8 m) above the grid] and is an indication of the coarser bed inventory. This variable is
managed as a function of boiler load and desired furnace shaft ∆P, utilizing the bed drain flow for control.
43-13

2. Shaft ∆P – The furnace shaft ∆P, from the intermediate elevation to the furnace roof, indicates the
shaft bed density and is managed to follow boiler
load with corrections for primary zone temperature control. It is influenced by the multi-cyclone
dust collector (MDC) recycle rate, the primary to
secondary air split, and excess air setting.
3. Lower bed (or primary zone) temperature – The
lower bed temperature is set by the operator as a
primary control variable for optimal combustion
and emission performance. The shaft ∆P, primary
to secondary air split, and excess air controls are
used to control this operating parameter.
The variables mentioned above are typically not
available on conventional boilers. However, the overall operation is similar. Fuel feed is set by steam requirements (pressure), total air flow is adjusted to follow fuel flow, and excess air is set to optimize combustion and unit efficiency. Shaft bed density is then
predominantly used to control the lower bed temperature, the most important variable on a CFB boiler. The
lower bed temperature is usually controlled to a fueldependent set temperature [for example 1550F (843C)
for lignite and 1620F (882C) for petroleum coke] which
results in optimal combustion efficiency and SO2 absorption. The optimum bed operating temperature
from combustion and emission standpoints is from 1500
to 1650F (816 to 899C), depending on fuel.
Another variable that is controlled somewhat differently in a CFB is the air admission to the furnace.
The total air flow is divided into primary and secondary flows. Because total air flow is based on fuel flow,
the primary to secondary air split becomes another
important parameter affecting emissions and bed temperature. The split affects the lower bed density, shaft
density, and control of the primary zone temperature.
The optimum air split is determined as a function of
steam flow during commissioning tests. Once the optimum primary to secondary air split (as a function of
steam flow) has been determined for automated control, the operator should not need to independently
manipulate the split.
Solids management is also unique to CFBs. Once
the bed material inventory has been established, bed
inventory is maintained by the fuel ash and sorbentderived solids flows in most cases. Any change in inventory necessary to accommodate load change comes
from the MDC hoppers. In the case of firing low-ash
and low-sulfur fuels, solids input with fuel ash and
sorbent may not be adequate to provide enough bed
material for furnace temperature control. This also
may be the case when firing waste fuels requiring a
high bed drain rate for removing oversized material,
e.g., rocks. If a shortage of solids for maintaining bed
inventory occurs, the first source to add bed material
would be recycling a usable part (properly sized material) from the lower furnace bed drain. If this is not
sufficient, inert bed material fed from an external
source, e.g., sand, would be provided.
With the sometimes complex relationships where
changes in one variable impact several temperatures
and flows, control logics are provided to automatically
control these inter-relating parameters with minimal,

43-14

if any, operator actions needed. However, the operator must be trained to understand these relationships
and to control upsets to establish and maintain stability if necessary.
Fuel sizing and fuel characteristics
Coal firing Fuel sizing is very important to successful boiler operation. It impacts the furnace heat release profile: fine particles tend to burn higher in the
furnace shaft while coarse ones burn predominantly
in the primary zone. For medium and high ash fuels,
fuel sizing also impacts sizing of bed particles and,
correspondingly, bottom ash to flyash split. When fuel
variation occurs, the operator should be thoroughly
trained on the required adjustments in case the variations are outside the range of the programmed control logics.
Biomass firing Biomass fuels provide a particular
challenge in CFB operations because of continuous
variations in size, shape, moisture content, and heating characteristics. To minimize operating problems,
fuel sources should be continuously blended to achieve
as uniform a consistency as possible. Modest inventories are needed – large enough to permit blending for
uniformity of feed but not large enough to result in
excessive inventory storage times. Bed material sizing should be checked on a regular basis to ensure that
the bed material is not deteriorating. Care must be
taken in such sampling procedures because of the high
bed material temperature.
Startup and shutdown considerations Chapter 17
provides general guidelines for the startup of CFBs.
Hot and cold startup conditions are distinguished by
the temperature of the furnace solids inventory, either higher or lower than the auto-ignition temperature of the main fuel established at the end of the
boiler purge sequence. As with any boiler, prior to
startup and after shutdown the unit must be purged
according to the latest applicable NFPA codes. An important part of a cold startup is the warming of the
bed material with auxiliary fuel overbed burners designed for this purpose. During normal operation, a

Fig. 5 Typical bed density profile for a circulating fluidized bed.


CFB is loaded with enough bed material to provide a
20 in. wg (50 kPa) pressure differential across the
primary zone. During the warming process, bed materials are introduced to raise the bed pressure drop
from 5 in. wg (1.25 kPa). Auxiliary fuel is used to increase and stabilize the primary zone temperature at
about 1000F/538C (varies somewhat depending on
main fuel) in preparation for main fuel introduction.
Simultaneously, the boiler metal temperatures as indicated by steam pressure (saturation temperature)
must be within the heatup rate allowed for the boiler
pressure parts. Upon ignition of the auxiliary fuel, the
flue gas temperature entering the U-beams and the
steam-cooled surfaces must be monitored and maintained below 950F (510C) until 10% of the MCR
steam flow is established through the steam-cooled
circuits. Once the primary zone temperature is stabilized at the fuel auto-ignition point, the main fuel is
introduced and the bed temperature can be gradually
raised to about 1500F (816C) where the auxiliary
burner may be shut off. Boiler load can be increased
from this low load operation with circulating mode
being established with increasing solids, fuel and air
flow. The rate of increase must be controlled such that
the bed temperature remains stable. Primary air to
total air ratio is further adjusted to improve combustion and reduce emissions.
Overbed burners are used to assist with the burnup
of unburned carbon particles in the primary zone of
the furnace. If the boiler is being shut down for maintenance and personnel entry into the boiler setting is
required, all solids must be completely removed from
the boiler and hoppers, and the boiler temperature
must be below 120F (49C) prior to entry. (See personnel safety discussed earlier.)

BFB systems
Overview As is the case with its CFB counterpart,
bed management of a BFB is important. Bed inventory, bed sizing, makeup and drainage must be integrated into operating procedures from data collected
during commissioning tests. The BFB is also equipped
with additional instrumentation to assist the operator in
developing the unit-specific operating guidelines.
1. Primary zone ∆P – the gas-side differential pressure is used as an indication of bed height. The
primary zone may be compartmented on the air
side for coal firing, and multiple ∆P cells are then
displayed.
2. Bed temperature – the typical bed temperature
range is 1350 to 1650F (732 to 899C) and is a primary control variable. Because control of this variable is critical, multiple thermocouples are installed in the bed.
The operation of a BFB is similar to that of other
combustion technologies in that fuel and air demands
are set by the required steaming conditions. Bed temperature is controlled within the desired range by the
primary/overfire air split for biomass firing and by selected compartment slumping for coal firing (see Chapter 17). If an SO2 sorbent is used, it is usually metered
in proportion to the fuel flow. Various interactions can


occur when manipulating control variables and the
operator must be specifically trained to respond to upsets. These responses include:
1. Fuel flow control – fuel feed is increased or decreased
based on steaming requirement. Changes in fuel
feed have a short-term impact on bed temperature.
2. Bed height – height is controlled by adding material from the makeup system or by removing material through the drain system.
3. Air control – total air is primarily controlled based
on steam flow. Air may be biased by the operator
to change bed conditions. Increasing primary or
bed air at a given load increases bed turbulence
and burnout in the bed, while the secondary air
changes opposite to the bed air change to control
constant total air at a given load. Reducing bed
air at a given load would have the opposite effect.
The operator must, therefore, bias the set point
based on combustion conditions. Fuel sizing variations, moisture content, and higher heating value
are most likely to influence combustion conditions.
4. Bed material flow – material flow to the primary
zone is through makeup and bed drains. Because
these are generally intermittent devices, the operator must observe control variable trends, particularly height, and make appropriate adjustments.
Coal sizing Careful attention to coal sizing (minimum and maximum) is critical to successful unit operation for both under-bed and over-bed feed systems.
Finer particles are elutriated too quickly and coarser
particles tend to take too long to burn completely. In
either case, UBC and SO2 emissions (if being controlled) both increase. An optimum size range exists
for each fluidized-bed system and fuel type. The proper
size range is fine tuned through unit operating practice. In addition, for the over-bed feed system fuel size
interacts with spreader speed, angle of injection and
gas velocity.

Operation of Kraft recovery boilers
Overview
The Kraft recovery boiler has three purposes in
today’s pulp and paper industry:
1. recovery of sodium and sulfur compounds from the
spent pulping liquor in forms suitable for regeneration,
2. efficient heat recovery from burning the liquor to
generate steam for process use, and
3. operation in an environmentally responsible manner, cooling the combustion gases to allow back
end particulate collection and minimizing the discharge of objectionable gases.
Steam flows can exceed 1,000,000 lb/h (126 kg/s) at superheater outlet pressures as high as 1500 psi (10.34
MPa) and final steam temperatures of up to 950F
(510C). These units burn black liquor with solids contents up to 75 to 80% and with heating values decreased to about 5500 to 5600 Btu/lb (12,793 to 13,026
kJ/kg). A detailed review of designs and general op-

43-15

erating practice is provided in Chapter 28. Selected
operating issues are highlighted below:
1.
2.
3.
4.

black liquor combustion process and air flow,
auxiliary burners,
operating problems, and
smelt-water reactions.

Black liquor combustion process and air flow
Unlike the firing of conventional fossil fuels, recovery boiler combustion goes through several distinct
stages. Black liquor firing is composed of drying, volatile burning, char burning and smelt coalescence as
discussed in Chapter 28. This has a distinct impact on
unit operation and air addition. All modern B&W recovery boilers are equipped with three levels of combustion air. These are known as the primary, secondary and tertiary air streams in order of increasing elevation in the furnace. A fourth level, called quaternary, can be added for additional NOx and particulate control (see Chapter 28).
Primary air Primary air is in the lowest zone in a
recovery boiler furnace. The air ports are located approximately 3 ft (0.9 m) above the furnace floor. Admitted on all four walls of the unit, the primary air
provides perimeter air around the bed at low velocity
and low penetration, so the boiler does not lose combustion. The primary air is critical to bed stability, bed
temperature and reduction efficiency.
Secondary air High pressure secondary air penetrates the full cross-section of the unit and is admitted at the top of the bed providing the combustion air
for ignition and the heat to dry black liquor droplets
and support pyrolysis. This air also helps control SO2,
total reduced sulfur (TRS) and CO emissions. Finally,
secondary air controls the shape of the top of the bed.
Fig. 6 indicates the proper bed shape with the relative locations of the air ports and liquor nozzles.
Tertiary air Tertiary air is admitted at the upper
elevation, above the liquor guns. Like secondary air,
it is admitted at high pressure to provide penetration
across the width of the furnace to complete the combustion process. This is an oxidizing environment to
control CO and TRS emissions.
To maintain combustion in the proper location, the air
flow splits and pressures must be properly maintained.
Ranges of typical air flow distributions, inlet temperatures
and pressure differentials are summarized in Table 3 for
the two dominant firing systems, stationary and oscillating.
Successful stationary or oscillating firing depends
on the correct liquor droplet size. This size must permit complete in-flight drying before reaching the furnace wall or bed. The variables in black liquor combustion include liquor percent solids, temperature and
pressure at the spray nozzles, spray nozzle sizing and
splash plate angle, and number and position of black
liquor guns in service. Other variables include the
vertical and angular movement of the oscillators or the
off-horizontal angle of the liquor guns for stationary
firing. Other factors on the air side include total excess air; air temperature(s); air splits between the primary, secondary and tertiary ports; and the static air
pressure in each of these air zones.
43-16

Fig. 6 Proper bed shape for a black liquor recovery boiler – three air
level design.

The objective in the manipulation of all of these
variables is to control the steps of the drying and combustion of the liquor, and control bed temperatures.
The result is stability of operation, with minimum
plugging and emissions.
A comprehensive discussion of recovery boiler emissions is provided in Chapter 28.

Auxiliary burners
Recovery boilers are equipped with oil- and/or natural gas-fired auxiliary burners located at the secondary
and tertiary air port elevations. The burners in the secondary windboxes are used for unit startup, as black
liquor can only be fired into a heated furnace with an
auxiliary ignition source. The secondary burners are also
used to stabilize the smelt bed during an upset condition and to burn the bed out of the unit on shutdown.
Operating problems
Two problems unique to recovery boiler operations
are plugging and aggressive tube corrosion.
Plugging of the superheater, boiler bank or economizer is generally caused by two mechanisms. The first
is condensation of the fume or normal gases given off
by the black liquor combustion. The hot combustion
gases that leave the lower furnace contain vaporized
compounds that condense when the gas temperature
is cooled in the upper zones of the boiler, superheater
or boiler bank. This condensation is dependent on gas
temperature. The material condenses on the cooled
heat transfer surfaces such as furnace screen tubes
or primary superheater tubes. It also precipitates out
when the gas temperature falls below approximately
1100F (593C). In either case, this material is a source
of fouling in convection surfaces. Condensation or precipitation depend upon the temperature regime and
chemistry of the fume. The deposit can be in the plastic range and very difficult to remove. On a properly
designed and operated unit, this transition of the fume


Table 3
Typical Air Flow Splits and Operating Conditions*
Firing Technique
Stationary
Oscillating
Firing
Firing
Primary air

30 to 40%
300F (149C)
3 to 4 in. wg ∆P
(0.7 to 1 kPa)

40 to 50%
300F (149C)
1 to 3 in. wg ∆P
(0.2 to 0.7 kPa)

Secondary air

40 to 50%
300F (149C)
8 to 18 in. wg ∆P
(2 to 4.5 kPa)

20 to 30%
300F (149C)
6 to 10 in. wg ∆P
(1.5 to 2.5 kPa)

Tertiary air

10 to 20%
80F (27C)
10 to 20 in. wg ∆P
(2.5 to 5 kPa)

20 to 30%
300F (149C)
8 to 12 in. wg ∆P
(2 to 3 kPa)

Economizer outlet conditions

< 2.5% O2
100 to 200 ppm
CO

2.5 to 3% O2
200 to 300 ppm
CO

* Units with four air levels are discussed in Chapter 28.

from a dry gas to a sticky substance takes place in the
upper furnace, wide spaced screen or superheater.
Here the deposits can be controlled by sootblowers. On
an overloaded or improperly operated unit, the gas temperature remains elevated farther back into the closer
side-spaced boiler bank or economizer, where controlling
the plugging with sootblowing equipment becomes difficult. The gas temperature at which the fume turns to
a sticky liquid is also liquor chemistry dependent, with
higher levels of chlorides or potassium compounds being detrimental to unit cleanability.
The second major cause of plugging is mechanical
carryover of smelt, or unburned black liquor, into the
convective heat transfer sections of the boiler. This

Sound an alarm to clear the
area of all unnecessary
personnel.

Immediately stop firing all
fuel-auxiliary fuel and black
liquor. Secure the unit’s
auxiliary fuel system at a
remote location.

material is predominantly made of sodium carbonate
(Na2CO3), sodium sulfate (Na2SO4) and sodium sulfide
(Na2S) compounds. The cause of this carryover is related to operation of the liquor nozzles, oscillators and
various air port settings. As previously noted, the
black liquor firing equipment and air system settings
must produce complete in-flight or wall drying of the
liquor droplets. If this drying occurs too high above
the smelt bed, the less dense droplets are entrained
in the gas stream and carry over into the convection
sections of the boiler. In practice, most recovery boiler
plugging results from a combination of fume condensation and mechanical carryover.
Recovery boilers are also subject to aggressive corrosion compared to conventional fossil fuel-fired units
due to the presence of corrosive sulfur, chloride and
other trace compounds in an elevated temperature
environment. The Kraft recovery boiler also operates
in both an oxidizing and reducing atmosphere due to
the combustion process. Because of these conditions,
the floor and lower furnace walls are constructed using one or a combination of corrosion protection systems: metallic spray coatings or carbon steel tubes,
high-density pin studs with refractory, 304L stainless
steel tubes, Incoloy® alloy 825 and Inconel® alloy 625
composites tubes, and weld overlay of carbon steel tubes.

Smelt-water reactions
One unique and undesirable feature of a Kraft recovery boiler is the possibility of water entering an
operating furnace through a tube leak or external
source, resulting in a smelt-water reaction. A smeltwater reaction occurs when water combines with hot
or molten smelt, and a violent explosion can result.
This concern has resulted in years of study and testing and has prompted enhanced industry standards
on unit design, operation and maintenance. Modern
units are equipped with the provisions for an emergency shutdown procedure. This is initiated if water is
suspected to have entered the furnace of an operating
recovery boiler. Refer to Fig. 7 for procedural overview.

Immediately shut off
feedwater supply and all other
water and steam sources
except smelt shatter steam to
the boiler.

Close primary air dampers and
immediately set other air flows
to essentially stop combustion
and smelting in the bed while
maintaining some level of
purge air. Regulate induced
draft fan flow to maintain
furnace balanced draft.

Drain the boiler as rapidly as
possible to a level 8 ft (2.44
m) above the low point to the
furnace floor. Reduce steam
pressure as rapidly as
possible after the boiler has
been drained to this level.

Fig. 7 Emergency shutdown procedure overview for an operating recovery boiler (adapted from the Black Liquor Recovery Boiler Advisory
Committee, October, 2003).
Inconel and Incoloy are trademarks of the Special Metals Corporation group of companies.


43-17


Babcock & Wilcox built and operates this refuse-to-energy plant in the southern U.S.

43-18


Effective boiler operations fundamentals

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