The primary function of a utility boiler is to convert water into steam to be used by a steam turbine/ generator in producing electricity. The boiler consists of a furnace, where air and fuel are combined and burned to produce combustion gases, and a feedwater tube system, the contents of which are heated by these gases.

1. www.yokogawa.com/us
Boiler Optimization Toolkit

2. 2
Table of Contents
Boiler and Feedwater Pump Efficiency Optimization .................................................................. 3
Accurate Steam Measurement.................................................................................................... 5
Pressure Start-Up........................................................................................................................ 7
Combustion Optimization............................................................................................................ 9
Carbon Monoxide Measurement................................................................................................11
Boiler Life-Cycle Considerations............................................................................................... 13

3. 3
Boiler and Feedwater Pump Efficiency Optimization
Introduction
The primary function of a utility boiler is to convert water into steam to
be used by a steam turbine/ generator in producing electricity. The
boiler consists of a furnace, where air and fuel are combined and
burned to produce combustion gases, and a feedwater tube system,
the contents of which are heated by these gases. The tubes are
connected to the steam drum, where the generated water vapor is
drawn. In larger utility boilers, if superheated steam (low vapor
saturation) is to be generated, the steam through the drum is passed
through superheated tubes, which are also exposed to combustion
gases. Boiler drum pressures can reach 2800 psi with temperatures
over 680°F. Small to intermediate size boilers can reach drum pressures
between 800 and 900 psi at temperatures of only 520°F if superheated
steam is desired. Small to intermediate size boilers are only being
considered for this application note.
With oil‐burning and gas‐burning boiler efficiencies over 90%, power
plants are examining all associated processes and controls for efficiency
improvements. Between 1 and 3% of the gross work produced by a
boiler is used to pump feedwater. One method of improving overall
efficiency is by controlling feedwater pump speed to save on pump
power.
Application
Feedwater Flow Control - In electrical power plants, demineralized
feedwater is pumped to the boiler tube header. The feedwater flow is
regulated by controlling the pump speed by using a process control
valve. The normal effect of pure water corrosion‐erosion (or cavitation)
that causes premature seat failure within the valve is amplified because
velocities of 10+ fps can be reached.
Industry: Power
Product: DPharp Pressure Transmitter, EJA‐E and EJX‐A series

4. 4
The added cost of frequent valve replacement makes utilizing a
feedwater pump the preferred method of flow control. Controlling
pressure by varying the pump speed saves on overall pump power
usage.
Pump Speed Control - Controlling pump speed is accomplished by
variable‐speed electric drives or by close‐coupling a steam turbine
to the pump. By definition, cogeneration power plants produce both
electricity and excess steam where turbine exhaust is used as a heat
source. A steam turbine driven feedwater pump is most often applied
because of the abundance of available steam.
Boiler Optimization - With a boiler’s firing rate held constant,
feedwater pressure and flow affect boiler pressure. As electricity
demands change, so do associated boiler loads. When more
electricity needs to be generated, the boiler produces more steam,
therefore feedwater flow must be increased to the boiler. Significant
savings are realized if boiler drum pressure and feedwater discharge
pressure are held to a constant differential. This can be accomplished
by accurately measuring this pressure differential and controlling the
pump speed and feedwater flowrate accordingly. In this example, boiler
drum pressures can vary between 800 and 900 psi depending upon the
load, (See Figure 2). The feedwater pump discharge pressures can vary
between 875 and 1000 psi depending upon boiler demand. Differential
pressure between the two points can be up to 200 psi, or even higher in
system upset conditions. This differential pressure must be accurately
measured, without regard to the 800 psi and above changing boiler
drum static pressure.
Yokogawa Solution
DPharp’s EJA110E and EJX110A “V” range capsule can measure
differential pressures up to 2000 psi with the same ±0.055% and
±0.040%, respectively, of span reference accuracy of lower range
capsules. In this common application example, ranging the EJA110E V
range transmitter 0 to 300 psi allows for the measurement of both
boiler pressure and feedwater pump discharge pressure. During pump
start‐up severe pressure spikes of 500+ psi can occur which can cause
shifts in zero.
Many competitors claim re‐zeroing their transmitter at static line
pressure minimizes these zero shifts but this task may not be practical
under fluctuating pressure conditions. The DPharp transmitter can be
bench calibrated and installed into a high static pressure line without
re‐zeroing. DPharp is unaffected by these pressure surges due to its
superior overpressure protection. The transmitter performance specs
are guaranteed over two years.
The power plant’s control system can use the high pressure
differential measurement to automatically set the feedwater rate
depending on the boiler load demand. At lower demand periods, less
steam is used to power the steam turbine driven pump and less
feedwater is consumed. Significant savings are realized through steam
conservation and by lowered maintenance costs with the use of the
DPharp transmitter.
(Also see Application Note on Boiler Drum Level Measurement
PAG‐505)

5. 5
Accurate Steam Measurement
Introduction
Steam has often been described as the ‘lifeblood’ of industry. It is
the medium by which heat from a boiler is converted into an easily
transportable form that can provide diverse services from office heating
to the mechanical energy that drives turbine generators. Steam is still
one of the most popular methods of providing an energy source to a
process and its associated operations.
It is now a well-accepted fact that measuring energy consumption is an
important factor in the quest to improve energy efficiency. Efficient and
accurate metering is paramount to determining excess use, along with
an accurate picture of where the steam is being used. A sound energy
management policy can only have a positive effect on the ‘bottom line’
profitability.
The Challenges
Most boiler systems are scalable to the plant’s needs, meaning steam
generation can be ramped up or down depending on the need from the
facility. This can range from low flows during start up, to higher flows
during full operation and back down to low flows during downtimes of
maintenance. It is important however that accurate measurement of
steam is essential in controlling boiler efficiency and safety. The more
accurate and reliable measurements that are made, the more informed
decisions can be taken that affect costs and product quality.
Traditionally the most common method of steam metering is the orifice
plare and differential pressure transmitter technique. General areas
of concern with this type of measurement are the orifice plate’s
susceptibility to wear introducing immediate inaccuracies, the
relatively high permanent pressure losses introduced into the system
by the orifice plate and the small measuring range typically 3:1.
The orifice flow meter is not suitable for low-flow measurement, and
can develop zero drift and span drift when the temperature/pressure
conditions fluctuate beyond the design specifications. In order to
measure larger turn downs with a orifice, the plates must be changed
periodically and the pressure transmitters re-calibrated and spanned.
Vortex meters are known to be superior devices for steam flow
measurement due to their inherent linear measurement, large turndown,
low pressure drop and high accuracy. It is often thought that it is no
problem to install a line size meter to capture a wide range of flows but
that is not always the case. This practice can lead to losing a lot of the
low end measurement. When sizing a vortex meter, it is common to have
to reduce the line size using concentric reducers to increase the velocity
through the meter for optimum performance. Unfortunately, piping
changes need to be made and this can increase costs.
Solution
To meet the customers’ needs, Yokogawa introduced the digitalYEWFLO
Reduced Bore Type Vortex Flow meter featuring a cast stainless steel
body and a concentric reducer and expander that enable stable flow
rate measurements in low-flow conditions. This expands the range of
measurements that can be performed, from the higher flow rates down
to the lower end of the flow span, which is normally difficult for Vortex
Flow meters, and ensures stable and accurate flow rate output.
• Face to face
is the same as
Standard unit.
• Drop in without
piping changes
Each Flange size
available in 3 bore
sizes:
• Full Bore
• 1 size
reduction
• 2 size
reduction

6. 6
While formerly two to three different types of orifice plates had to be
changed to adapt to fluctuations in the line flow rate, this is no longer
necessary with the digital YEWFLO reduced bore type. This model
reduces installation cost and expands the range of applications
available to end user.
The flow meter is available with a single reduction or a double reduction
in bore size, while still keeping the same face to face dimension of a
standard full bore vortex. This makes installations on new projects
simplified with no need for additional reducers or piping, and it makes
swapping already installed Vortex units simple, as there are no piping
changes required.
Reduced bore digitalYEWFLO vortex meters are flow tested with the
reducers; this ensures the accuracy of the unit is not compromised by
reductions in the line. Manual reductions in piping cannot guarantee
this accuracy.
The main benefits of Yokogawa’s reduced bore type vortex flow
meter:
• Minimum measurable flow up to five times lower than conventional
vortex flow meter.
• Integrated construction with reducers built into the flow meter body.
• The same face-to-face dimensions ease the task of installing other
sizes or types of digitalYEWFLO flow meters.
• No need for costly piping modifications such as reducers/expanders
or short pipes to achieve the required straight pipe length.
• Increases the space for installation of additional instrumentation
Yokogawa vortex flowmeters are also well suited to high temperature
applications, and the quality of flow management can be improved even
further through the use of anti-vibrating efficiency and self diagnostic
functions that rely on the digitalYEWFLO’s SSP system.
A multi-variable design is also available. With the multivariable option,
a built-in integral temperature sensor allows the meter to make a true
mass flow measurement of saturated steam by referring to steam tables
embedded in the software. This eliminates the need for separate
pressure and temperature sensors and a flow computer.
Traditional Instrumentation
New Instrumentation Using Reduced Bore Type
Flow Upstream side 10D
Upstream
side 5D
Down stream
side 5D
Process
piping
Reducer
Short pipe Short pipe
Expander Process
piping
Process
piping
Flow Upstream side 10D Down stream side 5D
Process
piping

7. 7
Pressure Start-Up
Introduction
The response time of a pressure transmitter is key to safe and
accurate process control. Yokogawa’s DPharp transmitter family
features the fastest response time on the market today. Having a
faster response time allows for a tighter process control and increased
plant efficiency. Fast start‐up and response is crucial for protecting
capital equipment, such as compressors, from abnormal or surge
conditions. By responding quickly to process changes, compressor
flow can be regulated to keep it running at maximum efficiency.
Yokogawa’s performance has been evaluated and found suitable for
anti‐surge controls. Overall, Yokogawa’s fast start‐up and response
time allows for reduced process variability, increased safety, and
increased plant availability.
Applicable Models
EJA‐E Series: All models
EJX‐A Series: All models except the EJX910A / EJX930A
Response Time
The industry definition for Response Time is the amount of time it
takes for the output signal to reach 63.2% of the actual pressure
change from the time the input change occurs. The 63.2% figure is
derived from an equation used for modeling exponential decay rates
and represents the output change for the first time constant.
Response time consist of two important components, Dead Time and
the Time Constant.
Total Response Time = Dead Time (Td) + Time Constant (Tc)
Dead Time (Td)
The response time of a pressure transmitter is key to safe and
accurate process control. Yokogawa’s DPharp transmitter family
features the fastest response time on the market today. Having a
Time Constant (Tc)
Time constant consists of the mechanical and electronic response time.
Mechanical response time is the time it takes for the process pressure
change to be transmitted by hydraulic force to the sensor. Electronic
response is the time from the sensor detecting the pressure change to
the transmitter electronics producing an output signal.
Damping
Damping is a setting that allow the customer to increase the dead time
of the transmitter. This is done to keep the transmitter from “chattering”.
Chattering is when the output signal has small but rapid changes due
to process variations. The damping removes this noise by extending the
response time.
Setting when Shipped
Damping is set to 2.0 seconds.
The EJA‐E and EJX‐A transmitters are designed to not allow the
damping to be set less than 0.5 sec unless the Quick Response feature
is turned on. With the feature enabled, the damping can be set down
to 0. To achieve the 90 msec response time, the damping must be set
to 0. The damping may be set using DTM works in FieldMate.
Although FieldMate is highlighted here, any Hart Communicator has
access to these functions. Refer to the User’s Manual for the HART
programming tree.
This function is available in HART 5 or HART 7.
Brain Protocol
The feature described in this FieldGuide are also available for EJA‐E
and EJX‐A transmitters with BRAIN Protocol communication. Please
refer to the User’s Manual for details.

8. 8
Sample Test Results
Digital Performance
DPharp pressure sensors come standard with two times better installed
performance. Yokogawa’s unique digital sensor provides superior
performance and stability compared to analog sensor types. Digital
sensors also provide stable measurements in all operating conditions.
Conclusion
With a response time of 90 msec, the Yokogawa EJA‐E and EJX‐A
series of smart pressure transmitters are some of the fastest
microprocessor based transmitters on the market today. This fast
response time allows customers to track process changes more
accurately than ever before, thus improving product quality and plant
efficiency and safety.

9. 9
Combustion Optimization
What is combustion?
Perfect combustion occurs when the correct amounts of fuel and
oxygen are combined so that both are totally consumed, with no
combustibles or uncombined oxygen remaining in the resulting flue gas.
However, fuel may contain impurities and additives to improve viscosity,
therefore ideal combustion can only be achieved if all of the following
requirements are met simultaneously:
• Consistent fuel composition at all times
• Pure oxygen in used instead of simple plant air
• Complete molecular mixing of oxygen and fuel, at the same
temperature and pressure
• Unlimited reaction time and zone
• Constant in-outlet conditions (pressure, temperature, flow,
composition) are maintained
• Consistent boiler/furnace load
In practice, none of the above requirements are completely achieved
due to the physical restrictions in burner design, use of (economical)
ambient air rather than expensive pure oxygen, and aging of boiler
equipment.
When there is insufficient air for combustion control, the fuel is not
completely consumed and gives off smoke. This is a sign of energy
loss and undesirable emissions. If left unchecked the buildup of
combustibles will lead to a safety hazard. On the other hand, if excess
air for combustion is supplied, the unused air is overheated and emitted
from the stack, causing a heat loss. This increases the emissions of
NOx and SO2, which cause air pollution. In order to achieve complete
combustion there must be a balance or air-fuel ratio where the boiler is
operating as close to zero “excess air” as possible
Why Measure O2
?
Either the measurement of oxygen or carbon monoxide can be used to
determine the level of excess air. However, measuring CO alone will not
define which type of an environment, fuel rich or air rich, a burner is
operating in. Therefore combustion control needs to be based on
accurate and dependable Oxygen analysis.
“Air-fuel ratio” or “Excess air” refers to the amount of air theoretically
required to achieve complete combustion of the fuel supplied to the
furnace of the boiler. The “air-fuel ratio” or “excess air” is used to
achieve the highest efficiency for a system based on each different fuel
source. “Excess air” can be obtained by measuring the oxygen
concentration in the exhaust gas and calculated by:

10. 10
Under actual operating conditions some amount of excess air is always
necessary to bring the combustibles level close to zero. The challenge
is to minimize these effects by achieving completed combustion with
the lowest excess air levels possible. It is important to accurately
measure and control oxygen analysis because:
Insufficient air is a waste of fuel which is a waste of money. As a rule of
thumb each 10% excess O2 is equivalent to a 1% in wasted fuel.
• To minimize heat loss since the more excess-air used, the more heat
required to warm it prior to combustion resulting is wasted heat
contained in the waste gas carried to the stack.
• Optimizing fuel consumption by maintaining complete combustion.
• Minimizing power consumption by ancillary devices (air blowers;
damper positioners).
• Reduction of air pollution since a surplus of excess air at high
temperatures allows for the formation of SO2, SO3 and NOx from the
fuel impurities and air-nitrogen.
What products would I use?
Application Notes
1. Boiler Control Solution Instruments and Solution for Automatic Boiler Control
2. Air Leak Detection in Sintering Furnaces to Enhance Efficiency and Product Quality
3. Measurement of O2 Concentration in Exhaust Gases from Pulverized Coal-fired Boilers
4. Measurement of O2 Concentration in Hot Blast Stoves
5. Oxygen Concentration in Package Boiler Flue Gases
Oxygen Analyzer Products
Oxygen Analyzers
Specifically for Package Boilers:
Integral Oxygen Analyzer ZR202

11. 11
Carbon Monoxide Measurement
Background Information
There are currently 1470 generators at 617 facilities in the United
States alone that use coal as the major source of energy to generate
electricity. Of these facilities, 141 are considered industrial,
institutional or commercial sites that consume most of the electricity
produced on-site. The remaining 476 sites are identified as “power
plants” owned by electric utilities and independent power
producers that generate and sell electricity as their primary business1
.
The primary goals that drive these power plants are increasing
efficiency and throughput, reducing emissions of pollutants, and
maintaining a high level of safety. Obtaining these goals ensures that
the power plants generate the highest profits, while complying with
environmental regulations and assuring workplace and community
safety.
Introduction
An accurate measurement of the carbon monoxide (CO) concentration
in the boiler flue gas can be used to achieve the goals of combustion
efficiency, pollutant emissions reduction, and safe operation. By
measuring the concentration of CO, power plants are able fine tune the
air to fuel ratio used on the burners to obtain the highest combustion
efficiency. Measuring the CO concentration allows the power plants
to reduce the amount combustion air used while ensuring complete
combustion, reducing the production of the pollutant NOx. The
concentration of CO in the flue gas is also the most sensitive indicator
of unburned combustibles in the process and can indicate the
emergence of an unsafe situation.
Efficiency, Emissions, Safety
Given complete mixing, a precise or stoichiometric amount of air is
required to completely react with a given quantity of fuel to produce
complete combustion. In real world applications, conditions are never
ideal so additional or “excess” air must be supplied to completely burn
the fuel.
Too little excess air will result in a “fuel rich” situation producing a flue
gas containing unburned combustibles (carbon monoxide, soot, smoke,
coal). This situation results in a loss of efficiency because not all of
the potential energy of the coal is captured in the combustion process
resulting in fuel wastes. Combustion processes that run fuel rich are
“running dirty” meaning an increase in pollutant emissions. Also, this is
not a safe situation as the unburnt fuel could possibly come into contact
with an ignition source further down the process resulting in an
uncontrolled explosion.
Too much excess air results in an “air rich” situation, resulting in
complete combustion and safety, but also produces undesirable
effects. Efficiency is lost in an air rich process because the increased
flue gas flow results in heat loss. More fuel is required to generate the
same amount of heat, so fuel is wasted in this low “boiler fuel-to-steam”
efficiency situation. Since air is comprised of over 78% nitrogen,
increasing the air used for combustion significantly increases the
concentration of nitrogen. Nitrogen exposed to temperatures above
1600°C (2912°F) may result in the formation of “thermal NOx” (NO,
NO2). These substances are major contributors to the formation of
acid rain and their release into the atmosphere is heavily regulated by
environmental agencies.
The ideal situation is to provide just enough excess air to produce
complete combustion, but not any more than that. This will produce the
highest efficiency, lowest emissions of pollutants, and maintain a high
level of safety. The question is: How is the excess air setpoint
determined?
Using CO to trim excess O2
The amount of excess air in the flue gas is determined by measuring the
concentration of oxygen (O2). The ideal excess O2 level (the lowest
possible that allows complete combustion) depends on several factors:
the fuel type, the burner type, humidity changes in the air, moisture
content changes in the fuel, varying boiler loads, fouling of the burner
system, and mechanical wear of combustion equipment. Since many
of these factors are continuously changing, the ideal amount of excess
oxygen continuously changes as well. Measuring carbon monoxide
(CO) can help to determine the excess oxygen setpoint.
CO is the most sensitive indicator of incomplete combustion. As
the amount of excess O2 is reduced, the emergence of CO will occur
before other combustibles appear (unburnt fuel). When the concentration
of CO reaches the desired setpoint (typically around 400 ppm), the
excess O2 concentration is at the desired level and becomes the
new excess O2 setpoint. As the concentration of CO increases or
decreases, the excess O2 setpoint can be trimmed accordingly. CO
trim control of excess O2 concentration assures minimal energy loss,
maximum efficiency, and reduced NOx emissions independent of boiler
load, fuel type, humidity, moisture content of fuel and other variables
that make excess O2 control difficult. The key to obtaining these
benefits is an accurate and reliable measurement of CO in low ppm
levels.
1. Source: Department of Energy Website (www.energy.gov)

12. 12
Obstacles to Measuring CO in Coal Fired Boilers
Measuring CO accurately and reliably in coal fired applications has
traditionally been extremely challenging. Some of the obstacles that
must be overcome:
• Flue gas laden with fly ash particulate
• High temperature in the optimal measuring location
• Stratification of gas concentrations
• Presence of SO2 in the flue gas
• Speed of response in non-insitu installations
Current measuring technologies that are employed to measure CO
(or combustibles in general) are Catalytic Bead sensors, Thick/Thin Film
thermistors, and IR spectroscopy.
The Catalytic Bead and Thick/Thin Film thermistors utilize the thermal
properties of combustion to change the resistance of an active element
compared to that of an inactive reference element. The active element is
coated with metal that acts as a catalyst for combustion when exposed
to air and a hydrocarbon. The other element is left in a natural state
without a coating to act as a reference against background changes
that would affect both elements (i.e. process temp, gas thermal
conductivity etc). Combustion on the surface of the active bead
increases the temperature of the bead in effect raising its resistance.
The difference between the reference and active resistance values is
proportional to the concentration of combustibles in the process gas.
Infra-red Analyzers use an infrared source mounted
directly on the flue gas duct or stack on the side
opposite from the receiver. Infrared energy is radiated
by the source, through the flue gas, to the receiver.
The receiver employs gas filter correlation and narrow
band pass optical filtration with a solid state detector to
determine the absorption of radiation by CO in the flue
gas. The magnitude of the absorption is proportional to
the concentration of CO in the flue gas.
Catalytic Bead Sensor
Infrared Analyzer
These measuring technologies are prone to the following problems:
• The catalytic sensors require sample extraction (not insitu) installations.
These sample extraction systems are prone to plugging and fouling
with fly ash in coal fired applications. They require frequent preventative
maintenance and the filters they require cause slow response times.
• The catalytic sensors are discreet or point measurements. They do
not provide a path or average measurement across the firebox. They
are subject to stratification errors, may not detect isolated areas of
CO breakthrough, and require multiple points of installation to
provide adequate coverage.
• IR analyzers cannot make the measurement in particulate laden (fly
ash) flue gas. This combined with temperature limitations prevents IR
installation directly across the fire box. They must be installed further
down the process, at lower temperatures after particulate removal
(precipitators). This introduces more lag time in detecting CO
breakthrough. Also CO that reacts after the fire box will not be
detected (CO quenching).
• IR analyzers are subject to interference from CO2 and water.
Catalytic sensors are subject to interference from NO2 and water,
and quickly deteriorate in the presence of SO2. This mandates
frequent calibrations, replacements, and suspect accuracy.
• These problems prevent these traditional measurement technologies
from providing an accurate and reliable CO measurement.
• Solution to Measuring CO in Coal Fired Boilers
• Tunable Diode Laser Spectroscopy (TDLS) manufactured by
Yokogawa Corporation of America has been proven in the field to
be a solution for this difficult measurement. Tunable Diode Laser
measurements are based on absorption spectroscopy. The TruePeak
Analyzer (TDLS200) is a TDLS system and operates by measuring the
amount of laser light that is absorbed (lost) as it travels through the
gas being measured. In the simplest form a TDL analyzer consists
of a laser that produces infrared light, optical lenses to focus the
laser light through the gas to be measured and then on to a detector.
The detector and electronics that control the laser then translate the
detector signal into a signal representing the CO concentration.
• The TruePeak Analyzer utilizes powerful lasers that are highly sensitive
and selective for CO. This results in many benefits over traditional IR
analyzers and catalytic sensors:
• The TruePeak Analyzer measures CO directly in the fire box. This
means no lag time in detecting CO breakthrough and no false low
reading due to CO quenching after the fire box.
• The TruePeak Analyzer measures CO insitu. There is no extractive
sample system induced maintenance or lag time.
• The TruePeak Analyzer is a path (across the fire box) measurement.
This provides an average reading that ensures isolated areas of CO
breakthrough are detected. Multiple installations are not required.
• The powerful, selectable laser of the TruePeak Analyzer penetrates fly
ash and is sensitive to low ppm levels of CO.
Summary
Coal fired power plants can achieve the highest efficiency, lowest emis-
sion levels, and ensure safety by using CO concentration measurements
to fine tune their excess O2 setpoint. These benefits are achievable
only if the CO measurement is accurate and reliable. Using TDLS, the
TruePeak Analyzer from Yokogawa can provide that accurate, reliable
CO measurement in coal fired power plants.
Product Recommendations
The TruePeak Analyzer -
Model TDLS200
Flue Gas Stratification

13. 13
Boiler Life-Cycle Considerations
Whether a boiler should be repaired or replaced is largely dependent on
age and condition. Proper monitoring of water quality (pH, Cond, DO),
chemical addition control (ORP), and real time corrosion control (ECP).
Regular maintenance is important to prolonging the life of a boiler.
However continuous of monitoring of water quality allows for predictive
maintenance and prevention of shutdown.
Where and what should be monitored?
For the Pure Water applications, the primary measurement we encounter
is conductivity but we have offered pH/ORP, and Dissolved Oxygen
configurations as well for over 15 years with great success.
Quick Run Down of Applications:
• Reverse Osmosis Filters
• Conductivity: Ratio or % Passage/Rejection (two sensors)
• pH occasionally, for membrane life
• Demineralizers:
• Cation, Anion, Mixed Bed
• Cation
• Cation Conductivity (two sensors in ratio)
• Charged Cation Beads “remove” (change to acid) positive Ions
and release H+ into stream
• Cation Conductivity has special Temp Comp to take the H+ into
account
• % Concentration (1 sensor)
• Beads are regenerated with acid (typically HCL or H2SO4)
• Anion
• Specific Conductivity (1 or 2 sensors)
• Charged Beads “remove” (change to water) negative ions
• % Concentration (1 sensor)
• Beads are regenerated with Caustic (NaOH)
• pH occasionally
• Completeness of after-regeneration Rinse
• Mixed Bed (“Polisher”)
• Specific Conductivity (1 sensor)
• Removal of both +/- Ions (“fine” cleaning, < 0.1 uS/cm)
• pH occasionally for complete monitoring
• Deion Storage
• Specific Conductivity (1 sensor)
• Ensure Water Quality after storage
• Second Polisher
• Specific Conductivity
• Final cleaning (Boiler applications)

14. 14
To defray energy costs, many industrial plants have their own boilers to
generate steam to produce a portion of their energy needs. In addition,
the steam may also be used directly in plant processes or indirectly via
heat exchangers or steam jacketed vessels.
The Problem for this application is that the raw water used to feed the
boilers, contains varying levels of impurities that must be removed to
protect the boiler and associated equipment.
Pretreatment processes such as reverse osmosis, ion exchange, filtra-
tion, softening and demineralization may be used to reduce the level of
impurities, but even the best pretreatment processes will not remove
them all and there will be a continuous carryover of some dissolved
mineral impurities into the boiler.
Boiler feed water usually contains one limiting component such as
chloride, sulfate, carbonate, or silica. Even if the component is not
conductive, for example silica, its concentration is usually proportional
to a component that can be measured by conductivity; therefore,
conductivity is a Tech Note: TNA1409 Date: August 20, 2014 viable
measurement for monitoring the overall total dissolved solids present in
the boiler. A rise in conductivity indicates a rise in the “contamination” of
the boiler water. So, measuring conductivity of the feed water is important
to this application.
The most common methodologies used for boiler blowdown control
include: (1) continuous, (2) manual and (3) automatic.
Continuous blowdown utilizes a calibrated valve and a blowdown tap
near the boiler water surface. As the name implies, it continuously takes
water from the top of the boiler at a predetermined rate to reduce the
level of dissolved solids. The rate is usually set slightly greater than
necessary to be on the safe side.
Manual blowdown is accomplished at most plants by taking boiler water
samples once a shift and adjusting the blowdown accordingly. This grab
sample approach means that operators cannot immediately respond
to changes in feedwater conditions or variations in steam demand and
scaling conditions can occur and go undetected until the next sample
check.
Automatic blowdown control is achieved by constantly monitoring the
conductivity value of the boiler water and adjusting the blowdown rate
and duration based on a specific conductivity set point. This provides
control of the water chemistry regardless of the boiler load conditions.
Actual operation data verifies that automatic control can maintain boiler
water conductivity consistently within 5% of the set point. Manual
blowdown control cannot maintain this level of control more than 20%
of the time. Again, measuring conductivity is essential for controlling
this application.

15. 15
Want more detailed information?
Application Notes
1. AN10B01B02‐10E‐A: Reverse Osmosis
2. AN10B01B02‐21E‐A: Pure Water pH
3. AN10D01P01‐01E: Boiler Leak Detection
4. SC‐A‐002: Demineralizer
5. SC‐A‐004: Boiler Blowdown
Technical Information
6. TNA0915: Care and Maintenance of a High Purity pH System
7. TNA0916: Proper Calibration
8. TNA0918: Maintaining Yokogawa pH Monitoring System
9. TNA0923: Sensor Diagnostics
10. TNA0925: Wet vs Dry Electrodes

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