&EPA
United States Office of Air Quality EPA-453/B-94-056
Environmental Protection Planning and Standards September 1994
Agency Research Triangle Park NC 27711
Air
High Capacity Fossil Fuel
Fired Plant Operator
Training Program
Student Handbook
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EPA-453/B-94-056
HIGH CAPACITY FOSSIL FUEL-FIRED PLANT
OPERATOR TRAINING PROGRAM
STUDENT HANDBOOK
U S Environmental Protection Agency
Region 5, Library (PL-12J)
77 West Jackson Boulevard, iztn noor
Chicago, IL 60604-3590
U. S. Environmental Protection Agency
Industrial Studies Branch/ESD
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
September 30, 1994
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NOTICE
This Student Handbook is part of a model state training program which addresses the
training needs of high capacity fossil fuel-fired plant (boiler) operators. Included are generic
equipment design features, combustion control relationships, and operating and maintenance
procedures which are designed to be consistent with the purposes of the Clean Air Act
Amendments of 1990.
• This training program is not designed to replace the site-specific, on-the-job training
i programs which are crucial to proper operation and maintenance of boilers.
Proper operation of combustion equipment is the responsibility of the owner and
^} operating organization. Therefore, owners of boilers and organizations operating such facilities
^ will continue to be responsible for employee training in the operation and maintenance of their
specific equipment.
DISCLAIMER
This Student Handbook was prepared by the Industrial Studies Branch, Emission
Standards Division, U. S. Environmental Protection Agency (USEPA). It was prepared in
accordance with USEPA Contract Number 68-D1-0117, Work Assignment Number 68.
Any mention of product names does not constitute an endorsement by the U. S.
Environmental Protection Agency.
The U. S. Environmental Protection Agency expressly disclaim any liability for any
personal injuries, death, property damage, or economic loss arising from any actions taken in
reliance upon this Handbook or any training program, seminar, short course, or other
presentation based on this Student Handbook.
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AVAILABILITY
This Student Handbook and the accompanying Instructor's Guide are issued by the Office
of Air Quality Planning and Standards of the U.S. Environmental Protection Agency. These
training materials were developed, as required by the Clean Air Act Amendments of 1990, to
assist operators of high capacity fossil fuel-fired plants in becoming certified as may be required
by state regulatory agencies.
Individual copies of this publication are available to state regulatory agencies and other
organizations providing training of operators of high capacity fossil fuel-fired plants. Copies
may be obtained from the Air Pollution Training Institute (APTI), U.S. EPA, MD-17, Research
Triangle Park, NC 27711. Others may obtain copies, for a fee, from the National Technical
Information Service, 5825 Port Royal Road, Springfield, VA 22161.
Although this government publication is not copyrighted, it does contain some
copyrighted materials. Permission has been received by the authors to use the copyrighted
material for the original intended purpose as described in the section titled Handbook
Introduction. Any duplication of this material, in whole or in part, may constitute a violation
of the copyright laws, and unauthorized use could result in criminal prosecution and/or civil
liabilities.
The recommended procedure for mass duplication of the Student Handbook is as follows:
Permission to use this material in total may be obtained from the APTI, provided the
cover sheet is retained in its present form. Permission to use part of this material may also be
obtained from the APTI, provided that the APTI and the authors are properly acknowledged.
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COURSE HANDBOOK INTRODUCTION
This Student Handbook was developed by the U. S. Environmental Protection Agency
(USEPA) in support of improving the air pollution control practices at high capacity fossil fuel-
fired plants (boilers). The USEPA was required to develop a model state training and
certification program for boiler operators under Title HI, Section 129 of the Clean Air Act of
1990.
The training materials are composed of this Student Handbook and an Instructor's Guide
which includes the masters for the projection transparencies. State and regional air pollution
control agencies are encouraged to use these training materials in their training and certification
programs. The materials will also be useful in private entity training programs.
TRAINING PROGRAM GOAL
The primary goal of the training program is to provide an adequate level of understanding
to boiler operators to successfully complete the Operator Certification Examination of the ASME
Standard for Qualifications and Certification of High Capacity Fossil Fuel-Fired Plant Operators
(under development).
The training program focuses on the knowledge required by operators for understanding
the basis for proper operation and maintenance of boilers in minimizing air pollutant emissions.
Particular emphasis is placed on the various aspects of combustion which are important for
environmental control. Fundamental information is related to applications and to the operator's
own work experiences.
Participants are encouraged to make comments and ask questions throughout the program,
as such discussion will help establish a creative environment for the course.
The program is designed to augment the normal site-specific, on-the-job, and supervised
self-study training programs which are typically provided by the vendor, owner, or operating
company. The program is not a substitute for such hands-on operator training programs.
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TABLE OF CONTENTS
Section Title Page
1. INTRODUCTION
1.1 Purpose of Course 1-1
1.2 Steam Generators 1-2
1.3 Regulatory Requirements 1-4
1.4 Course Overview 1-9
2. WATER AND STEAM CIRCUIT
2.1 Steam Fundamentals 2-1
2.2 Boiler Fundamentals 2-3
2.3 Water - Steam Circuit 2-6
2.4 Water Treatment 2-11
3. COMBUSTION GAS CIRCUIT
3.1 Introduction 3-1
3.2 Combustion Process 3-1
3.3 Heat Transfer 3-6
3.4 Combustion Gas Flow Path 3-7
3.5 Flue Gas Treatment 3-9
4. FOSSIL FUELS
4.1 Introduction 4-1
4.2 Natural Gas 4-1
4.3 Fuel Oil 4-6
4.4 Coal 4-13
5. COMBUSTION PRINCIPLES
5.1 Basic Combustion Concepts 5-1
5.2 Air-Fuel Mixture 5-2
5.3 Combustion Equations 5-3
5.4 Combustion Calculations 5-8
5.5 Heat Transfer Fundamentals 5-14
6. AIR POLLUTION FUNDAMENTALS
6.1 Introduction 6-1
6.2 Fuel Dependent Air Pollutants 6-1
6.3 Combustion Dependent Air Pollutants 6-3
6.4 Smoke and Particulates 6-3
6.5 Gas Concentrations 6-5
6.6 Emission Factors 6-7
6.7 Correcting Concentrations 6-8
6.8 Excess Air Calculations 6-15
6.9 Combustion Efficiency Calculation 6-16
6.10 Boiler Efficiency Calculations 6-17
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TABLE OF CONTENTS (Continued)
Section Title Page
7. NATURAL GAS FIRED BOILERS
7.1 Introduction 7-1
7.2 Fuel Supply System 7-1
7.3 Burner Arrangements 7-4
7.4 Boiler Design Parameters 7-12
7.5 Emissions 7-14
8. OIL FIRED BOILERS
8.1 Introduction 8-1
8.2 Fuel Supply System 8-1
8.3 Burner Arrangements 8-7
8.4 Boiler Design Parameters 8-8
8.5 Emissions 8-8
9. PULVERIZED COAL FIRED BOILERS
9.1 Introduction 9-1
9.2 Pulverizing Properties of Coal 9-1
9.3 Coal Preparation 9-3
9.4 Methods of Pulverizing and Conveying Coal 9-7
9.5 Pulverizing Air Systems 9-10
9.6 Types of Pulverizers 9-12
9.7 Pulverized Coal Boilers 9-18
9.8 Emissions 9-24
10. STOKERS
10.1 Introduction 10-1
10.2 Types of Stokers 10-2
10.3 Underfeed Stokers 10-2
10.4 Mass Feed Stokers 10-6
10.5 Spreader Stokers 10-10
10.6 Emissions 10-20
11. FLUIDIZED BED BOILERS
11.1 Introduction 11-1
11.2 Typical Fluidized-Bed Conditions 11-2
11.3 Fluidized-Bed Combustion Advantages 11-3
11.4 Atmospheric Pressure Fluidized-Bed Boilers 11-5
11.5 Fluidized-Bed Boiler Furnace Design 11-7
11.6 Fluidized-Bed Boiler Arrangements 11-8
11.7 Operation 11-10
11.8 Emissions 11-12
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TABLE OF CONTENTS (Continued)
Section Title Page
12. GAS TURBINE WITH A HEAT RECOVERY
STEAM GENERATOR
12.1 Introduction 12-1
12.2 Gas Turbine Description 12-1
12.3 Design Classifications 12-4
12.4 Operating Cycles and Efficiency 12-10
12.5 NOX Formation Mechanisms 12-15
12.6 Control Options 12-19
13. PACKAGE BOILERS
13.1 Introduction 13-1
13.2 Package Boiler Types 13-1
13.3 Emissions 13-9
14. NORMAL OPERATION
14.1 Introduction 14-1
14.2 Maintaining Suitable Combustion Conditions 14-1
14.3 Monitoring Combustion 14-7
14.4 Maintaining Steam Temperature and Pressure 14-11
14.5 Maintaining Suitable Feedwater Conditions 14-12
14.6 Monitoring the Steam/Water Circuit 14-14
14.7 Controlling the Steam Temperature 14-15
14.8 Startup Procedures 14-17
14.9 Shutdown Procedures 14-20
15. AUTOMATIC CONTROL SYSTEMS
15.1 Introduction 15-1
15.2 Types of Analog Control Systems 15-1
15.3 Types of Digital Control Systems 15-3
15.4 Automatic Control System Elements 15-4
15.5 Gas-side and Water-side Control Parameters 15-6
15.6 Single, Two, & Three Element Controllers 15-7
15.7 Microprocessor Based Control Systems 15-12
15.8 Control System Applications 15-13
in
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TABLE OF CONTENTS (Continued)
Section Title Page
16. INSTRUMENTATION: GENERAL MEASUREMENTS
16.1 Introduction 16-1
16.2 Pressure Measurement 16-1
16.3 Temperature Measurement and Equivalence 16-2
16.4 Level Measurement 16-4
16.5 Flow Measurement 16-4
16.6 Weigh Scales 16-5
17. ELECTRICAL THEORY
17.1 Introduction 17-1
17.2 Fundamental Parameters 17-1
17.3 Electrical Power Equipment 17-9
17.4 Instruments and Meters 17-13
18. TURBINE GENERATOR
18.1 Introduction 18-1
18.2 Steam Turbine Generator Description 18-1
18.3 Steam Turbine Designs 18-5
18.4 Steam Turbine Generator Operation 18-8
18.5 Generator Synchronization Utility Grid 18-10
18.6 Turbine Generator Off-Nominal Conditions 18-11
19. PREVENTATIVE MAINTENANCE
19.1 Potential Economic Losses 19-1
19.2 Features of Preventative Maintenance 19-2
19.3 Periodic Inspections 19-4
19.4 In-Service Maintenance 19-5
19.5 Outage Maintenance Planning 19-5
20. SAFETY
20.1 System Safety Hazards 20-2
20.2 Consequences of Exposure to Hazards 20-5
20.3 Standard Safety Considerations 20-6
20.4 Personnel Protection Equipment 20-8
21. AIR POLLUTANTS OF CONCERN
21.1 Introduction 21-1
21.2 Air Quality Overview 21-2
21.3 National Ambient Air Quality Standards 21-3
21.4 Primary Pollutants 21-7
21.5 Secondary Pollutants 21-12
21.6 Hazardous Pollutants 21-15
IV
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TABLE OF CONTENTS (Continued)
Section Title Page
22. ENVIRONMENTAL REGULATIONS
22.1 Regulatory Overview 22-1
22.2 Provisions of the Clean Air Act Relative to
Boiler Operations 22-7
22.3 New Source Performance Standards 22-9
22.4 Additional Standards 22-19
22.5 Permits 22-23
23. CONTINUOUS EMISSION MONITORING
23.1 Statement of Purpose 23-1
23.2 General Classifications of CEMS 23-1
23.3 Components of CEMS 23-5
23.4 Usage of CEMS in Utility/Industrial Boilers 23-7
23.5 Analytical Methods 23-8
23.6 Flow Monitors 23-18
23.7 Opacity Monitors 23-22
23.8 Maintenance and Continuing Operations 23-24
24. PARTICULATE CONTROL
24.1 Control Methods and Typical Arrangement 24-1
24.2 Cyclones 24-2
24.3 Electrostatic Precipitators 24-6
24.4 Fabric Filters 24-12
25. NITROGEN OXIDES CONTROL
25.1 Nitrogen Oxides Control Overview 25-1
25.2 NOX Formation 25-3
25.3 Control of NOX Emissions 25-5
26. SOX CONTROL
26.1 Introduction 26.1
26.2 Wet Scrubbers 26-2
26.3 Dry Scrubbers 26-13
26.4 Furnace Injection 26-19
27. WATER POLLUTION 27-1
28. WASTEWATER TREATMENT
28.1 Removal of Suspended Solids 28-1
28.2 Neutralization 28-6
28.3 Dechlorination 28-8
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TABLE OF CONTENTS (Continued)
Section Title Page
29. SOLID WASTES
29.1 Introduction 29-1
29.2 Bottom Ash and Fly Ash 29-1
29.3 Ash Removal and Handling Techniques 29-3
29.4 Ash Characterization and Testing 29-8
29.5 Flue Gas Desulfurization Wastes 29-11
29.6 Handling of FGD Wastes 29-12
29.7 Groundwater Contamination from
Ponds and Landfills 29-12
30. SOLID POLLUTION CONTROL
30.1 Introduction 30-1
30.2 Disposal Methods 30-1
30.3 Wet Disposal - Ponds 30-2
30.4 Dry Disposal - Landfills 30-3
30.5 Treatment Methods 30-4
30.6 Dewatering 30-5
30.7 Stabilization 30-11
30.8 Fixation 30-11
30.9 Utilization 30-12
31. GLOSSARY
VI
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CHAPTER 1. INTRODUCTION
1.1 Purpose of Course
1.2 Steam Generators
1.3 Regulatory Requirements
A. NAAQS
B. NSPS
C. SIPs
D. NESHAPS
E. Clean Air Act Amendments
1.4 Course Overview
Slide 1-1
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1. INTRODUCTION
1.1
Purpose of Course
The operator of fossil fuel-fired boilers has a significant responsibility in
assuring that the unit is continuously operated in a manner which complies with the
various state and federal regulations. The Clean Air Act Amendments (CAAA) of
1990 require the Environmental Protection Agency (EPA) to "...develop and promote
a model State program for the training and certification of... high-capacity fossil fuel-
fired plant operators." The primary purpose of this course is to fulfill the training
portion of this requirement.
The course will emphasize the operating principles for all types of boilers and
for all types of control equipment used for controlling air emissions from boilers. The
course will emphasize the significant operating parameters that directly influence air
emissions. The specific objectives of this training course are to:
1. Provide boiler operators with an adequate level of understanding on the
effects of their actions on the air pollution emitted from the boiler.
2. Provide information for the proper operation and maintenance of the boiler.
3. Provide a knowledge base necessary for the proper operation and
maintenance of the associated air pollution control devices (APCD).
4. Provide an understanding to operators in the proper operation of coal, ash,
and other auxiliary systems.
This course is intended to be a supplement to site specific "hands-on" operator
training.
COURSE OBJECTIVES
1. Effects of Operation on Emissions
2. Boiler Operation and Maintenance
3. APCD Operation and Maintenance
4. Auxiliary Systems Operation
Slide 1-2
The group of high-capacity fossil fuel-fired plants which will be covered during
this course are those boilers defined in the federal regulations as electric utility steam
generating units, and industrial, commercial, and institutional steam generating
units. This group covers boilers ranging in size from 10 million Btu per hour to the
large utility boilers.
1-1
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1.2 Steam Generators
Steam generators, or boilers, convert chemical energy bound in the fuel to heat
water to produce .steam. Fuels burned in today's steam plants include coal, oil or
natural gas as well as nuclear fuel, and solid and liquid wastes among others. The
steam which is generated may be used for electric power generation and industrial
process heating, such as food preparation and paper and wood products
manufacturing as well as other applications.
There are many types of boiler designs which range in size from those needed
to heat a small building to large utility power generating stations. The design of the
boiler is dependent on the fuel used. The types of boilers which will be discussed in
more detailed throughout this course include natural gas fired, oil fired, pulverized
coal, stoker fired, fluidized bed and package boilers.
Generally, as shown in slide 1-3, a steam generating system includes a fuel
delivery system, burner/combustion system, air/gas handling, steam-water flow
system, and flue gas treatment system prior to discharge through the stack. The fuel
delivery system prepares the fuel for combustion and transports it to the steam
generator. The associated air system supplies air to the burners through a forced
draft fan. Within the steam generator, the fuel-air mixture burns. This heat release
is captured by the water which flows through tubes exposed to the hot combustion
gases and generates the high pressure and high temperature steam. The steam is
then supplied to the process or steam turbine generator equipment depending on the
application. After the steam has provided the required heat to the process/turbine,
the steam is cooled and condensed back to water for return to the steam generator to
start the cycle once again. The flue gas leaves the steam generator and passes
through air pollution control devices (APCDs). The type of APCDs employed depends
on the fuel and boiler design and applicable environmental regulations. The cleaned
flue gas is pulled by an induced draft (ID) fan and discharged to the stack.
1-2
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GENERAL SCHEMATIC FOR A STEAM GENERATOR SYSTEM
Exhaust
APCDs
Fuel
Fan
Air
Burners
ID Fan
Flue
Gas
Steam
Generator
Steam.
Process/
Turbine
Water
Condenser
Feed Pump
Slide 1-3
There are many variations of the schematic shown above and these will be
discussed in detail in the following Learning Units on different boiler designs. Today's
designs are sophisticated to achieve the maximum level of efficiency. Efficiency is
typically measured by the amount of energy produced (i.e. electricity, steam) divided
by the amount of energy provided (i.e. fuel). The specific efficiency improvements for
each type of boiler design will be discussed in Learning Units 7 through 13.
1-3
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1.3
Regulatory Requirements
The process of burning fossil fuels creates products of combustion that are
released to the atmosphere as flue gas. The air pollutants which are generated by
burning fossil fuels include sulfur oxides, particulate matter, nitrogen oxides,
hydrocarbons, and carbon monoxide. The impact of each of these pollutants will be
discussed in more detail in Learning Unit 21. In the late 1960s, no effective
mechanism existed for controlling air pollution so, legislation was developed resulting
in the 1970 Clean Air Act which passed as amendments to the 1963 Clean Air Act.
The Clean Air Act amendments of 1970 required the Environmental Protection
Agency (EPA) to establish ambient standards for certain pollutants to protect and
enhance the nation's air resources. The following areas of the Clean Air Act may
apply to boiler operation.
CLEAN AIR ACT STANDARDS
• National Ambient Air Quality Standards (NAAQS)
• New Source Performance Standards (NSPS)
• State Implementation Plans (SIP)
• National Emission Standards for
Hazardous Air Pollutants (NESHAPs)
Slide 1-4
1-4
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National Ambient Air Quality Standards (NAAQS)
The most fundamental of the Clean Air Act regulations are the National
Ambient Air Quality Standard (NAAQS) which are directly related to human health.
These standards are developed and monitored by the federal EPA and set upper limits
on the allowable concentration of various chemical compounds in the local
atmosphere. The pollutants regulated are those that have an adverse impact on
human health or the environment (i.e., visibility). The ambient concentration limits
are established to assure protection of the general population. Pollutants covered by
NAAQSs are referred to as "Criteria Pollutants." Of particular significance to fossil
fuel-fired boiler operations are the NAAQS limits for the pollutants listed in slide 1-5.
NAAQS apply to general geographic areas or basins. The local regulations maybe
more strict than the federal regulations depending on the compliance status of the air
shed with the federal standards.
NATIONAL AMBIENT AIR QUALITY STANDARDS
Limit ambient concentration of air pollutants
Concentration limits based on health risk data
Covered Pollutants called "Criteria Pollutants"
Sulfur Oxides (SOX)
Nitrogen Oxides (NOX)
Carbon Monoxide (CO), and
Particulate Matter
Standards apply to geographical areas or basins
Slide 1-5
New Source Performance Standards (NSPS)
The second type of pollutant regulation of importance to boiler operations are
New Source Performance Standards or NSPS. These standards are also developed
and administered by the Federal EPA. As the name implies, they apply to "new
sources" and establish unit "performance standards" limiting the rate at which
pollutants may be emitted from the stack. NSPSs are developed for different
groupings of pollutant emission sources including:
• Electric Utility Boilers
• Industrial-Commercial-Institutional Boilers - This grouping includes all non-
utility boilers with heat input ratings greater than 100 million Btu per hour.
1-5
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Small Industrial-Commercial-Institutional Boilers - This grouping includes
all units with heat input rates between 10 million and 100 million Btu per
hour.
Gas Turbines.
NEW SOURCE PERFORMANCE STANDARDS
Apply to New Units or Significantly Modified Units
Regulations Established for different Groupings of
Pollutant Emission Sources
Utility Boilers
• Industrial Boilers
• Gas Turbines
Establish Stack Emission Limits for Criteria
Pollutants
Limits must be based on Demonstrated Performance
of Control Technologies
Slide 1-6
For each of these major groupings, the NSPS's establish limits on the stack
emission rates or stack concentrations for various NAAQS "criteria pollutants."
Thus, there is a direct link between the ambient air quality standards and the new
source performance standards. There are, however, important differences in the
applicability and the basis for the two types of standards. The NAAQS limits are
based on consideration of health effects while the NSPS limits are established based
on the best demonstrated performance of control technologies on actual units in full-
scale operation. As will be discussed in this course, significant differences in pollutant
emissions is expected for different types of boilers burning different types of fuels. For
this reason, the utility and industrial boiler NSPS set different emission limits for
units firing gas, oil, and coal. These regulations are discussed further in Learning Unit
22 on "Environmental Regulations."
The NSPS only apply to newly constructed units (i.e., units constructed after
the date of proposal of the NSPS) ox to existing units undergoing significant
modification. The logic behind this applicability is that boilers have a lifetime of
approximately 30 to 40 years. Boilers constructed prior to passage of the original
Clean Air Act were exempted from the original NSPS but they were expected to be
retired by shortly after the turn of the century. The significant modification provision
was included to help assure that old boilers would be retired in an orderly fashion and
replaced by new units, subject to the NSPS.
1-6
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State Implementation Plans (SIPs)
Each state is required to develop a series of State Implementation Plans
(SIPs). In broad _terms, SIPs are the detailed procedures that a state will use to
assure that NAAQS requirements are maintained or the detailed corrective actions
that a state will use to bring local areas into compliance. If areas are in compliance,
the state has broad flexibility in establishing emission criteria for all source
categories. Most states rely on the NSPS for stationary sources and mobile source
standards to limit emissions from automobiles. The states may elect to impose more
strenuous emission limits than suggested by the federal government. If an area is
out of compliance with the NAAQS, a completely different set of emission criteria are
imposed. Clearly, any new source represents an additional burden to an ambient air
situation that is already considered unacceptable. Accordingly, to add a new source,
that source must (1) meet extremely stringent emission control requirements, and (2)
the owners must find a way to reduce emissions from an existing source that more
than off set emissions from the proposed new unit. Further, to remedy the non-
compliance situation in the area, states may require the existing sources to make
plant modifications to reduce the emission rate for a particular pollutant.
STATE IMPLEMENTATION PLANS (SIPs)
• Plans for Implementing the Requirements of the Clean
Air Act at the State level.
• SIPs provide the road map for States to meet NAAQS
• Regulations may apply to New and Existing sources
• Regulations may be More Stringent than NSPS
• SIPs must be reviewed and approved by Federal EPA
Slide 1-7
National Emission Standards for Hazardous Air Pollutants (NESHAPs)
The NSPS address the group of criteria pollutants and are only applicable to
new sources. There are a variety of pollutants that have been determined to pose
immediate health risks to the exposed public. To address this situation, the EPA has
authority to develop National Emission Standards for Hazardous Air Pollutants
(NESHAPs). The major factors associated with NESHAPs are that these standards
are based on acute health risk determinations and they apply equally to all sources
covered by the regulations. That is, a NESHAP emission release rate requirement is
the same for existing sources and new sources. The 1990 Amendments to the Clean
Air Act required the EPA to conduct wide ranging research relative to a group of 189
1-7
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compounds that are classified as hazardous air pollutants (HAPs). Many of those
pollutants are emitted from fossil fuel fired boilers. Those regulations have not yet
been enacted but it is likely that in the near future, control of HAP emissions will be a
major consideration for fossil fuel fired boiler operations.
Clean Air Act Amendments of 1990
Since the 1970 Clean Air Act gave States unrealistic deadlines for bringing the
areas unable to attain the NAAQS into attainment, Congress enacted a
nonattainment program in 1977 with strict new requirements for existing and new
sources and provided a revised deadline for achieving the NAAQS for those areas not
in compliance by the end of 1987. However, by the end of 1987, numerous areas of
the country still were not in compliance with the NAAQS. In November of 1990, the
Clean Air Act Amendments of 1990 were signed into law as a set of amendments
substantially more comprehensive and more complex than the prior Clean Air Act.
The amendments include eleven titles. The titles of importance to boiler operation
include the following:
Clean Air Act Amendments of 1990
Titles with Impact on Boiler Operation
Title I: Attainment and Maintenance
of NAAQS
Title III: Hazardous Air Pollutants
Title IV: Acid Deposition Control
Slide 1-8
Under Title I, each state has primary responsibility for assuring attainment of
the NAAQS through a state implementation plan (SIP). The SIP can have
significant impact on how a boiler is operated. Title III focuses on the identification
and control of hazardous air emissions. Thus, the EPA was directed to perform
studies on electric steam generating unit emissions to determine the hazards to
public health reasonably anticipated to occur as a result of emissions of listed
hazardous air pollutants. The results from this study and others may provide the
basis for EPA to formulate additional regulations to control power plant emissions.
Title IV addresses acid deposition which occurs when sulfur dioxide and nitrogen oxide
emissions are transformed in the atmosphere to acids and return to earth as rain, fog
or snow. Most of the sulfur dioxide emitted in the U.S. is the result of burning fossil
fuels by electric utilities. Therefore, this title contains sulfur dioxide emissions
reduction requirements for power plants in a two phase program.
1-8
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1.4
Course Overview
This course is divided into thirty individual learning units each designed to
present the given topic within a 45 to 90 minute class. After the course introduction,
the course content includes a review of the boiler characteristics, fuel properties,
combustion principles and air pollution fundamentals. The next group of topics
addresses typical boiler designs. Next, a discussion of normal operation and process
control systems is included with an emphasis on the effects of operation on air
pollutant emissions. Learning units are presented on electrical theory and generation
since most of the larger boilers are in service to generate electricity. The
maintenance and safety in operating all components of the power plant are discussed
in the next two units. The remaining units address the pollution regulations,
monitoring and emission control.
COURSE ORGANIZATION
1 Introduction
2-6 Fundamental Operating Principles
7 - 13 Types of Equipment
14 - 16 Operation and Control Systems
17 - 18 Electrical Theory and Generation
19 - 20 Maintenance and Safety
21 - 23 Air Pollution Regulations and Monitoring
24 - 30 Pollution Control
Slide 1-9
1-9
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REFERENCES
1. Mover, C. and Francis. M., Clean Air Act Handbook: A Practical Guide to
2.
3.
Moyer, C. and Francis, M., Clean Air Act Handbook: A Practical Guide
Compliance^ Clark Boardman Company, 1991.
Steam, Its Generation and Use, 40th Edition, Babcock and Wilcox Company,
1992.
Elliott, Thomas C., Standard Handbook ofPowerplant Engineering, McGraw-
Hill Publishing, 1989.
1-10
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CHAPTER 2. WATER AND STEAM CIRCUIT
2.1. Steam Fundamentals
2.2. Boiler Fundamentals
2.3. Water - Steam Circuit
A. Circulation
B. Water-Side Components
C. Steam-Side Components
2.4. Water Treatment
A. Mechanical Treatments
B. Chemical Treatments
Slide 2-1
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2. WATER AND STEAM CIRCUIT
2.1
Steam Fundamentals
Steam is created when enough heat is added to water to bring it to a boil and
thus vaporize the water. A good example to illustrate the properties of steam is the
boiling of water in a tea kettle.
TRANSFORMATION OF WATER INTO STEAM
Sensible Heat Addition
Heat increases the water temperature
to the Saturation Temperature
Heat
• Heat added at the Saturation
Temperature produces water vapor
or saturated steam
Heat
• Pressure increases as more
steam is produced
• Pressure is relieved by lid
opening to release the steam
from the kettle
Heat
Additional heat applied to a
closed kettle with saturated steam
produces superheated steam at a
higher temperature and pressure
Heat
Slide 2-2
2-1
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As heat is applied to the tea kettle, the water temperature increases. Heat
applied which results in a change in temperature is known as sensible heat. When
the temperature approaches the boiling point or saturation temperature (212°F at
one atmosphere of pressure), the addition of more heat results in a change of phase.
That is, some of the liquid becomes water vapor. This amount of heat added to
change a liquid at saturation temperature into a gas is known as latent heat. The
temperature at which water boils depends on the surrounding pressure. For example,
at high altitudes, the pressure of the surround air is less than at sea level, therefore
water boils at a lower temperature that 212°F at higher elevations. During boiling,
the temperature remains constant and there is a mixture of water and steam. The
steam produced under these conditions is defined as saturated steam.
As steam is produced, the steam expands into the empty space above the
water in the kettle. As more steam is produced the space above the water becomes
filled and the pressure inside the kettle rises due to the force produced by the steam
continuing to try expand against the kettle walls. (Pressure is defined as force
exerted on an area and is measured in pounds per square inch or psi; one atmosphere
is 14.7 psi) This pressure is relieved when the lid of the kettle opens and provides a
path for the steam to exit the confined space inside the kettle.
Steam Fundamentals
Sensible Heat
Saturation Temperature
Change of Phase
Latent Heat
Saturated Steam
Superheated Steam
Steam Quality
Pressure = [Force -t- Area] (psi)
Atmospheric Pressure (14.7 psi)
Maximum Allowable Working Pressure (MAWP)
Slide 2-3
If the kettle was not able to vent the steam, the pressure inside the kettle
would continue to rise as more steam is generated. The tea kettle would then be
considered a pressure vessel. As the pressure increases, the saturation pressure
also increases. When the last drop of liquid has vaporized, the continued addition of
heat would result in an increase in both temperature and pressure within the kettle.
At this point the contents of the kettle would be defined as superheated steam.
At very high pressures, a point is reached where water no longer exhibits
boiling behavior, this pressure is known as the critical point (3208 psi, 705°F).
Heat addition no longer results in the typical boiling process where there is an exact
division between steam and water. Rather, as the fluid is heated at this high pressure
it passes through a point at which the properties of the water change from those of a
liquid to those of a gas (steam). Boilers which operate at or above the critical
2-2
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pressure are known as supercritical boilers; all others are known as subcritical.
In reality, the tea kettle construction would probably not be able to withstand
the higher pressure and would result in a failure of the tea kettle (i.e. bursting apart).
To prevent this type of failure with boilers, boilers are rated to a Maximum
Allowable Working Pressure (MAWP) which is the highest pressure at which the
boiler may be operated. According to ASME code, boilers are typically design to
withstand four times the rated pressure. Similar to the tea kettle lid, boilers are fitted
with safety valves which keep the boiler from exceeding its MAWP in order to
maintain a safe operating environment.
The steam produced by a boiler is measured in terms of quality which refers to
the dryness of the steam. As steam flows, moisture may be carried along or
entrained by the steam flow. Pure steam, 100% quality, contains no moisture. So, if
the quality of steam is 92%, it contains 8% moisture. Steam that contains any
moisture is called wet steam. Superheated steam has a quality of 100% (dry steam)
which is a valuable characteristic to help eliminate condensation in the steam lines
which results in delivering less steam to the end user.
2.2
Boiler Fundamentals
By definition, a boiler is a closed vessel in which water under pressure is
transformed into steam by the application of heat. Boilers come in a variety of sizes,
configurations, and designs. The steam temperature and pressure for different boiler
applications can have a significant impact on design as will be discussed later in
Learning Units 7 through 13. As a brief overview of boiler design, the two common
boiler design categories are the watertube boiler and firetube boiler.
FIRETUBE BOILERi
Slide 2-4
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The firetube boiler can be simply described as a water-filled cylinder with tubes
running though it which provide the escape path for the combustion gases or flue gas.
As the flue gas passes through the tubes, the hot gases heat the tubes which in turn
heat the water to produce steam. The firetube boiler is primarily used in industrial
applications and will be discussed in more detail in Learning Unit 13.
The more complicated watertube boiler is used in large industrial applications
and utility powerplants and therefore will be the focus of this discussion and Learning
Units 7 through 11.
Drum
Dow/ncomer
WATERTUBE BOILER3
Reheater
P'imarY
Sjperheater
Economizer
Slide 2-5
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Generally, the boiler can be physically divided into two sections, the furnace
and the convection pass. Furnaces (fireboxes, combustion chambers) will vary in
configuration and size, but their function is to contain the flaming combustion gases
and transfer the heat energy to the water-cooled walls. The convection pass contains
the superheaters, reheater, economizer and air preheater heat exchangers where the
heat of the combustion flue gases is used to increase the temperature of the steam,
water, and combustion air.
CONVECTION PASS COMPONENTS
Superheaters
Reheater
Economizer
Air Heater
Slide 2-6
The superheaters and reheaters are designed to increase the temperature of the
steam generated within the tubes of the furnace walls. Steam flows inside the tubes
and flue gas passes along the outside surface of the tubes.
The economizer is a counterflow heat exchanger designed to recover energy
from the flue gas after the superheater and the reheater. The boiler economizer is a
tube bank type, hot-gas-to-water heat exchanger. It increases the temperature of
the water entering the steam drum. The tube bundle is typically an arrangement of
parallel horizontal serpentine tubes with the water flowing inside but in opposite
direction to the flue gas. Tube spacing is as small as possible to promote heat
transfer while still permitting adequate tube surface cleaning and limiting flue gas
side pressure loss. By design, steam is usually not generated inside these tubes.
The air heater is not a portion of the steam-water circuit, but serves a key role
in the steam generator system heat transfer and efficiency. In many cases,
especially in a high pressure boiler, the temperature of the flue gas leaving the
economizer is still quite high. The air heater recovers much of this energy and adds it
to the combustion air. Heating the combustion air prior to its entrance to the furnace
reduces fuel usage.
Functionally, a boiler has two separate but interactive circulation circuits - the
water-steam circuit and the combustion gas circuit. The combustion gas circuit will
be discussed in detail in the next Learning Unit (#3). The water-steam circuit usually
includes the furnace enclosure walls, steam drum and steam-water separation, and
associated connecting piping (downcomers, supplies and risers). The next section
provides a more detailed discussion on the operation of the steam-water circuit.
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2.3
Steam- Water Circuit
The discussion of the steam-water circuit will first cover the overall circulation
followed by a description of the components on the water and steam side of the
circuit.
Circulation
For the boiler to generate steam continuously, water must be circulated
through the tubes. Two different approaches are commonly used, natural or thermal
circulation, and forced or pumped circulation. Natural circulation consists of half of
the circulation loop being heated, a steam-water separation device or steam drum,
and a non-heated second half of the circulation loop as shown in Slide 2-7.
NATURAL CIRCULATION IN A BOBLER3
Steam Out
Feedwater In
Downcomer
(Not Heated)
Heat from
Combustion
Riser
(Heated)
Waterwall
Header
Slide 2-7
As the water in the waterwalls is heated, it rises due to the difference in density
between water at different temperatures. Hot water is lower in density than cool
water. Therefore, the hotter water in a boiler will rise toward the surface of the water
while the cooler water will descend toward the bottom of the boiler. As the water
changes phase into steam, the steam naturally expands and rises in the tubes. When
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the steam flows up the tubes some of the hotter water is entrained in the steam.
This steam-water mixture rises to the steam drum where the steam and water are
separated. From the steam drum, gravity will cause the water to flow downward
through the downcomer section. The rate of water flow depends on the difference in
average density between the water in the downcomer and the steam-water mixture in
the waterwall tubes. The density difference is a function of boiler height and boiler
operating pressure. The greater the height of the boiler, the greater the difference in
pressure between the bottom and top of the boiler. In some applications, the
pressure difference is not adequate to produce the water flow rate required. In these
cases, forced circulation is required. Forced circulation adds a mechanical pump to
the flow loop to control the water flow rate.
In addition to natural and forced circulation, there are two other common boiler
circulation configurations. The once-through system provides continuous
evaporation of water to 100% steam without the need for water separation. This
design uses forced circulation for the necessary water flow. This is a common
configuration for supercritical boilers. The other circulation configuration is a
combination of the once-through and recirculation. At low loads, recirculation
maintains the necessary water flow to cool the tube walls while at high loads, high
pressure once-through operation enhances cycle efficiency.
Water-Side Components
The water-side components of the steam-water circuit include the feedwater
pump, waterwall tubes, drum, downcomers, and risers. Boiler feedwater is the water
added to a boiler to replace evaporation and other losses. In many cases, steam is
condensed and returned to the boiler as part of the feedwater. The water needed to
supplement the returned condensate is known as "make-up" water. The feedwater is
composed of this make-up water and returned condensate for recirculating systems.
WATER-SIDE COMPONENTS
Feedwater pump
Waterwalls
Drum
Downcomers
Risers
Slide 2-8
In forced circulation systems, the boiler feedwater pump, as the name
implies, pumps water to the boiler. It maintains the water level and flow required in
the boiler and therefore the pressure of the steam. The water flow is controlled by
different methods: A constant speed driver (A.C. motor) with a flow regulating valve
or a variable speed driver (turbine and/or variable speed coupling) with or without a
flow regulating valve. The water is generally pumped through feedwater heaters to
the boiler economizer and then on to the boiler steam drum through risers.
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Furnace walls or water-walls are typically constructed of tubes arranged side-
by-side. Some waterwalls may be coated with refractory to protect the tube metal
from corrosion and/or overheating. Generally, over half of the heat generated in the
combustion process is absorbed by the water in the waterwall tubes.
The steam drum is a large cylindrical vessel at the top of the boiler in which
saturated steam is separated from the steam-water mixture leaving the boiler tubes.
Drums can be quite large with diameters of 3 to 6 ft and lengths approaching 100 ft.
The functions of the steam drum include housing the steam-water separation
equipment, purifying the steam, mixing the replacement feedwater and chemicals,
and returning the near saturated water back to the inlet of the boiler tubes.
Boiler water carryover is the contamination of steam with boiler water solids.
There are several common causes of boiler water carryover include foaming, priming
and leakage. Foaming results from very high concentrations of solids in boiler water
such as oils, greases, and suspended solids. Priming is a sudden surge of boiler water
caused by a rapid change in load, similar to the effects produced by uncapping a
bottle of charged water. Steam contamination may also occur from leakage of water
through improperly designed or installed steam-separating equipment in the boiler
drum. The best prevention against carryover is to maintain the concentration of
solids in the boiler water at the recommended levels.
Water supply to the waterwall is from the steam drum through large diameter
pipes which are unheated and are referred to as downcomers. The downcomers
bring water which is close to saturation temperature to the lower waterwall headers.
Headers are the main lines to which the bottom of each watertube is connected.
It is not possible to describe the many various configurations of furnaces or
boilers since each manufacturer or designer has preferences aind/or design variations
because of economics, fuel, desired efficiency, controllability, and a multitude of other
reasons. However, all furnace and boiler manufacturers follow the same basic
principles.
While discussing circulation, it should be pointed out that flow through a tube
located in a high temperature area is what prevents the tube from failure due to
overheating of the tube metal. It is difficult to visualize 1,000 °F steam cooling the
tube in which it is flowing, but that is what happens in a superheater with an upper
metal temperature limit of approximately 1,070 °F located in a hot gas stream of
1,200 ° to 1,500 °F. The flow rate and the allowable temperature increase must be
high enough to remove the heat absorbed by the tube external surface. This condition
exists in the furnace probably to a higher degree as temperature in the combustor
zone can easily exceed 2,000 °F and the tube material is carbon steel with an upper
temperature limit far below this temperature.
Overheated tube metal is a major cause of forced boiler outages. The primary
reason for overheated tubes is firing with no water or low water levels in the boiler,
inadequate flow for the firing rate, or a scale build-up inside the tubes which prevents
heat transfer from the tube metal to the water or steam flowing through the tube.
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The first two reasons can be eliminated by following established operating procedures.
Scale build-up on the inside surface of tubes can be controlled by the use of proper
water treatment techniques for the boiler water. Periodic inspections and cleaning of
internal tube surfaces is a necessary maintenance practice for all boilers.
Steam-Side Components
The primary components of the steam-side of the steam-water circuit may
include the steam drum, superheaters, reheaters, desuperheaters, and safety valves.
STEAM-SIDE COMPONENTS
Steam Drum
Superheater
Desuperheater
Reheater
Safety Valves
Slide 2-9
The steam drum serves three functions. The primary function of the drum is
to separate steam from the boiler water. Secondly, the apparatus used to purify the
steam is housed in the drum, and to a lesser degree the drum serves as a small water
storage area for water level in the boiler.
The drum contains various arrangements of baffles and different
configurations and types of moisture separators. The purpose of this equipment is to
remove as much as possible of the solid impurities and water droplets from the steam
before it leaves the drum. Any liquid carried over in the steam will contain impurities
which become solids when the moisture is evaporated in the superheater. The solids
in the steam flow are undesirable because of damage that they can cause to turbines
or other steam-driven equipment.
Some plants use the steam in the state that it leaves the drum for their
process; these are referred to as saturated steam plants. Most plants will dry or
superheat the stream to some degree before use by passing it through one or more
stages of the tube bank type heat exchangers in the boiler.
Steam to be superheated is routed from the drum through various tube
arrangements to the primary superheater located in the hot gas passage upstream
of the economizer. Depending on the boiler design and the end use of the steam, the
steam may go to a secondary superheater located in a higher temperature zone of the
furnace. A typical arrangement of the steam circuit with a primary and secondary
superheater is shown in Slide 2-10. The final stage of superheat is the high
temperature, which is referred to as "Radiant" or secondary superheater, as shown in
Slide 2-5, since it is exposed to the radiant heat of the furnace as well as the
conductive heat from the hot gases.
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STEAM-SIDE COMPONENTS SCHEMATIC
Desuper-
heater
Steam Drum
Primary
Superheater
Secondary
Superheater
Reheater.
Economizer
High
Pressure
Turbine
Low
Pressure
Turbine
Deaerator
Condensate
Pump
Slide 2-10
The final steam outlet temperature may be controlled by several methods
involving firing and gas flow control, however, in many boilers a desuperheater is
employed. Desuperheating is the reduction of temperature in superheated steam by
spaying water into the flue gas either ahead of or behind a superheater or reheater
section. Another method of reducing or controlling the steam temperature is by
diverting the steam through a bank of tubes submerged in boiling water which absorb
part of the energy from the steam.
The steam produced by the boiler is used for many purposes. Typically, the
large high capacity boilers are used to supply steam for turbine driven electric power
generators. The steam is expanded through the turbine, which converts the heat
energy to rotational energy and then electrical energy. The steam, then at a low
temperature and pressure, enters the condenser where it is condensed by cooling
water from a river, lake, or cooling tower. The condensate is then pumped by
condensate pumps through a train of feedwater heaters to the boiler feedwater
pumps. Some plants use a reheat cycle in which the high temperature superheater
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outlet steam goes through the High Pressure (HP) section of the turbine and returns
to the boiler reheater to be reheated before going through the Intermediate
Pressure (IP) and/or Low Pressure (LP) turbines. The steam generator reheaters are
located and function in basically the same manner as the superheater.
The boiler water/steam circuit is a large capacity pressure vessel that has a
vast amount of stored energy which must be and generally is very well controlled. To
limit the internal pressure in the boiler one or more safety relief valves are installed
on a boiler. In the strictest definition a safety valve is used for gas or vapor service, a
relief valve is used primarily for liquid service, and a safety relief valve may be
suitable for use as either a safety or a relief valve.6 These valves open at a preset
pressure and then close when the pressure drops below this pressure. These valves
are generally located on the drum, superheater outlet and reheater inlet.
2.4
Water Treatment
Boiler feed water quality directly affects the life of the boiler tubes. The
accumulation of deposits carried in by the feed water onto pipes and equipment
surfaces can (1) impair heat transfer and fluid flow, and (2) contribute to the
corrosion of metal surfaces which degrades system and equipment reliability. These
deposits form an insulating layer on the metal heat-transfer surfaces, reducing the
efficiency of heat transfer. At points of inefficient heat transfer, tube temperatures
can rise above design limits creating a point of metal stress. As deposits continue to
accumulate, fluid flow may become restricted and can lead to plugging of water tubes.
Underneath the deposits, highly corrosive conditions can exist.
Treatment of water for steam generation is necessary to preserve the boiler
components as well as steam purity. The purpose of this section is to introduce the
typical impurities in the boiler water and the water treatment techniques. The
pressure and design of a boiler determine the quality of water it requires for steam
generation. The water quality of the boiler feed water and the boiler discharge water
will depend upon the original source of the water as well as the nature of any
preceding treatment process steps. Described below are the various sources of
contamination for these water streams.
WATER IMPURITIES AND MEASUREMENTS
Dissolved Solids
Dissolved Gases
Suspended Solids
Hardness
PH
Slide 2-11
2-11
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There are three basic classifications of impurities found in natural water;
dissolved solids, dissolved gases, and suspended solids. Dissolved solids are
impurities that have passed into solution. Dissolved solids exist in natural water even
though they are not visible. Examples of solids that dissolve in natural water include
calcium, silica, and iron. Dissolved gases may be released through processes like
deaeration. Examples of gases that may be dissolved in natural water include oxygen,
carbon dioxide, and hydrogen sulfide. Suspended solids are impurities that do not
pass into solution. Suspended solids are visible in natural water and may include
algae, other organic substances and silt.
The most detrimental natural elements in the formation of scale deposits in
the boiler are calcium and magnesium. The hardness of water is the measurement
of these minerals in parts per million (ppm). A level of 0 ppm of calcium and
magnesium is desirable, but typical boiler water hardness ranges from 0.005 ppm to
1 ppm.
Another measure of the quality of the feedwater is the pH, which represents
how acidic or alkaline (basic) water is. The pH scale ranges from 0 to 14 with 0 being
the most acidic and 14 the most alkaline. Corrosion will attack the boiler metal below
a pH of 7.0. Since boiler metal plate thickness is reduced by corrosion, the pH
specifications for most steam boilers is set between 8.0 and 10.0. However, alkaline
conditions which do exist at this level are conducive to scale formation, but this can
be counteracted with chemicals. Therefore, as a safety buffer against corrosion,
slightly alkaline water is recommended by boiler manufacturers. The use of boiler
chemicals and boiler blowdown helps control pH. Boiler blowdown is the discharge of
water containing concentrated dissolved and suspended solids. As blowdown water is
replaced with feedwater, the boiler water is diluted. By regulating the amount of
blowdown, the amount of solids in the boiler water can be controlled.
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Mechanical (Physical) Treatments
Mechanical treatments include very commonly known devices such as filters
and sedimentation tanks. Various types of pollutants including floating debris,
suspended solids and dissolved solids and gases can be removed by physical means.
Slide 2-12 lists some of the mechanical water quality treatments typically employed
at an industrial or utility boiler.
Debris, usually found in water from a natural supply, must be removed before
the stream can be used. Foliage (leaves, twigs, etc.), animal debris, and other organic
matter can be quite abundant in water from lakes or river. Such contaminants must
be removed to avoid clogging of water flow lines. This is effectively accomplished by
crude devices such as rakes and flow diversion gates.
Suspended solids are removed through clarification and filtration. Both
processes are commonly used as a pretreatment of boiler feed water, and, if
required, the same techniques can be used to treat waste water discharge.
Clarification is the removal of large suspended solids and sediments. Large
suspended particles settle out of the water stream, leaving the remaining water clear.
Sedimentation is the specific use of gravity to settle out particles, thereby clarifying
Technology
Pretreatment
Cooling
Clarification
Filtration
Aeration
Demineral-
ization
MECHANICAL WATER TREATMENTS
Primary Application
Removal of debris
Regulation of water temperature
Removal of large suspended matter
Removal of remaining
suspended matter
Removal of dissolved iron &
manganese
Devices
Rakes, gates
Cooling tower, canals
Sedimentation tanks, horizontal
clarifier tanks, vertical clarifiers
Screens, beds of rigid or
granular material
Rotor brush aerators,
aerator towers
Stripping of dissolved gases (CO2, HiS) Rotor brush aerators, aerator towers
Removal of remaining
dissolved matter
Flash distillation units,
semipermeable membranes,
reverse osmosis unit,
ion exchange resins
Slide 2-12
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the water. Typical devices include sedimentation tanks, horizontal tank clarifiers,
and vertical clarifiers. Filtration is the removal of fine residual suspended solids. A
filtration system consists of two parts; filtration and backwashing. Filtration is the
passing of water through a filter medium. After the media has been saturated with
the contaminants, the filter is backwashed to remove the material. Screens, beds
composed of granular material, and cloth can all be used as filtration devices.
Dissolved gases are removed from water streams by oxidation. Oxidation is a
chemical reaction that increases the oxygen content of a compound (usually changing
a compound to its oxide form). This treatment makes use of the addition of oxygen
(62) to convert soluble gases (and some dissolved solids) to their insoluble oxide form.
The addition of C>2 is accomplished by a process called aeration. Aeration has two
primary applications. One is the oxidation of dissolved iron and manganese to form
insoluble hydroxides. Precipitated at proper pH levels, these can be settled or filtered
out. The second use is for the stripping of dissolved gases like hydrogen sulfide and
C02 from solution. Aeration devices include degasifiers and decarbonators. In these
devices, aeration is performed by allowing air bubbles to diffuse upward through
water in a holding tank. Air flows countercurrent to the downflowing water allowing
O2 in the air to come in contact with the soluble gases in the water. The dissolved
gases are stripped from the water and both the air and the stripped gases are vented
out the top of the tank.
Demineralization is the removal of soluble solids such as manganese and
calcium from the water stream. For boiler feed water, demineralization has become
an industry standard. Most other boiler feed water treatments are merely steps
applied to remove the bulk of troublesome solids, ions, gases that can interfere with
demineralization operations, reducing its effectiveness and throughput of high quality
water. Demineralization is accomplished by the use of evaporation, membrane
treatments, reverse osmosis and ion exchange.
DEMINERALIZATION TECHNIQUES
• Evaporation
• Membrane Treatments
• Reverse Osmosis
• Ion Exchange
Slide 2-13
Evaporation is the application of heat to cause a change of phase, producing a
vapor free of dissolved and suspended solids in the feed water; condensation of the
vapor produces a considerably purified product. There are numerous devices which
utilize evaporation.
Membrane treatment is the separation of pollutants from a pressurized
fluid by semipermeable membranes. Membrane treatments can be one of two
approaches; cross flow filtration or electrodialysis. Cross flow filtration differs from
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filtration in that the direction of flow need not be head on to the filter. A membrane
material, usually a polymeric material, applied to a surface is able to hold on to
particles as the fluid stream moves along parallel to the surface. In electrodialysis
pollutants are moved away from the water through the application of an electric filed
to the fluid. Here, an electric current applied perpendicular to the flow cause
positively charge impurities to move towards a cathode while negatively charged
impurities move to the anode. The impurities travel through selectively permeable
membranes (i.e.; a cation membrane allows the passage of positive ion but rejects
negative) thereby trapping impurities.
Reverse osmosis is a widely applied demoralization technique which utilizes
pressure applied to the surface of a fluid. Osmotic pressure exist when two fluids with
different concentrations are separated by a semipermeable membrane. Under
osmotic pressure, fluid moves from the more dilute to the more concentrated side.
When an opposing pressure is applied, the fluid will move in the reverse direction
leaving behind its impurities which cannot travel back through the membrane.
Ion exchange is a process whereby one type of impurity within a fluid is
exchanged for another that is less objectionable. An ion exchange resin is a synthetic
resin capable of supplying ions (impurities with an electrical charge) to a fluid in
which it conies in contact with. These ions chemically react and are exchanged for
like charged impurities already existing in the fluid. A well known example is the
replacement of calcium and magnesium ions with sodium to decrease the hardness of
water. Demineralization of condensate return is almost exclusively accomplished
through ion exchange.
Softening is a form of demineralization. Although the term commonly
designates only the removal of calcium and magnesium (hardness), silica, alkalinity
and other constituents are also removed in softening. Makeup water is softened to
prevent dissolved solids from settling on component surfaces and producing a hard
scale. Softening techniques make use of precipitation, ion exchange, or semi-
permeable membranes. The first is precipitation and settling out of calcium and
magnesium by chemical addition to the water. Chemical treatments are discussed in
the next section.
Chemical Treatments
The amount of chemicals available for treatment, either solely for water
purification or as additives to protect cooling water tubes, flow pipes and equipment
are numerous. Slide 2-14 lists a variety of chemical treatments commonly applied to
boiler cooling water systems.
Like physical treatments, chemicals can be used to remove suspended and
dissolved solids within a water stream. Clarification is the mechanical removal of
large suspended matter. To apply this technology effectively to a wider range of fluid
streams, coagulation chemicals are often added to the water. Addition of these
chemicals causes finer particles to come together into a larger suspended mass,
much easier for the clarifier to remove. Dissolved solids, also, can be removed
2-15
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Chemical
Sodium hydroxide
(caustic soda)
Sodium carbonate
Sodium phosphate
Sodium aluminate
Chelants
Tanins, starches,
lignin
Polymers,
copolymers
Sodium sulfite
Hydrazine
Ammonia
Filming amines
Neutralizing
Sodium nitrate
Antifoams
Chlorine
Potassium
permanganate
Coagulants
Calcium hydroxide
(lime)
CHEMICAL WATER TREATMENTS
Application
Increases pH, precipitates magnesium
Increases pH, precipitates calcium
Precipitates calcium
Precipitates calcium and magnesium
Controls scale by forming heat stable soluble compounds
Prevents water deposits by coating scale to produce a sludge that
does not adhere as readily to pipe surfaces
Disperses sludge, prevents scale, prevents
fouling by corrosion products
Prevent C>2 corrosion
Prevent OT corrosion
Adjusts pH
Control return line corrosion by forming protective film on metal
surfaces
Controls return line corrosion by amines adjusting condensate pH
Inhibits caustic embrittkment
Reduces foaming tendency of high solids boiler water
Removal of dissolved gases by chemical oxidation, control of slime
and algae
Control of slime and algae
Causes suspended matter to coagulate, used in conjunction with
clarification
Adjusts pH
Slide 2-14
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through the addition of chemicals to the water stream. Soda ash, lime, sodium
phosphate and sodium aluminate all chemically react with calcium or magnesium, to
precipitate out these two minerals from the fluid flow. Dissolved solids and gases can
be removed by oxidation whereby chemicals instead of oxygen (as with aerators) are
introduced into the fluid stream. Chlorine has been the customary oxidizing chemical
with hydrogen peroxide seeing some use. Typical applications include the conversion
of dissolved iron to ferric chloride; removal of the insoluble ferric chloride is then by
clarification or filtration.
Chemicals are used extensively for protection of the boiler system (water side)
against scale, corrosion and other deposits. Chemicals called polymers and
copolymers are added to makeup water to condition sludge deposits whereby
impurities are precipitated out and held in a suspended non-adherent form. Final
removal of the nonsticky sludge is then accomplished by boiler blowdown. Chemicals
known as chelants are used to reduce scale formation. Ethylenediamine-tetraacetic
acid (EDTA) and nitrilotriacetic acid (NTA) are the two most common boiler water
chelating agents.
Corrosion within the boiler water tubes, flow pipes, cooling tower equipment or
any other associated components is inhibited in one of two ways. By either the
removal of 02 and other gases which contribute to corrosion from the boiler feed
water before they enter boiler, or by the control of boiler feed water pH. Soluble
oxygen may be removed from a water supply by the use of a scavenger agent.
Injection of a chemical such as sodium sulfite can result in a reaction with O2-
Removal of the solid product is by blowdown. Corrosion in steam and return lines can
occur because of carbonic acid resulting from the reaction of water with CC>2 gas
coming from the boiler. Chemicals called amines are traditionally added to adjust the
pH of the condensate. Fed into the boiler water, these neutralizing amines volatilize
and carry over with the steam. This type of corrosion can also be prevented by the
addition of a different type of amine which provides a protective film over the metal
surfaces of the condensate return system The metals surface is thereby immune to
any corrosive effects of the carbonic acid.
2-17
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REFERENCES
1. Wilson, Dean R., Boiler Operator's Workbook,American Technical Publishers,
Inc., 1991.
2. Steam, Its Generation and Use, 40th Edition, Babcock and Wilcox Company,
1992.
3. Elliott, Thomas C., Standard Handbook ofPowerplant Engineering, McGraw-
Hill Publishing, 1989.
4. Strauss, S.D., Water Treatment • Special Report, Power, June, 1993 Vol 137;
pp. 17 -107
5. ASME Boiler Operation Code, 1986, Subsection C2.
6. ASME Boiler and Preesure Vessel Code, Section I.
2-18
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3. COMBUSTION GAS CIRCUIT
3.1 Introduction
3.2 Combustion Process
A. Process Components
B. Furnace Draft
3.3 Heat Transfer
A. Radiation
R Conduction
C. Convection
3.4 Combustion Gas Flow Path
A. Furnace
R Convection Pass
3.5 Flue Gas Treatment
Slide 3-1
-------
3. COMBUSTION GAS CIRCUIT
3.1
Introduction
In the previous Learning Unit, the production of steam was discussed based on
an available heat source. The combustion gas circuit, which consists of the fuel, air,
and products of combustion flowpath, provides the heat to generate the steam. This
Learning Unit will discuss the release of heat from the combustion process, the heat
transfer from the combustion of fossil fuels, the flowpath of the products of
combustion, and the flue gas treatment.
COMBUSTION GAS CIRCUIT FUNCTIONS
1. Release of heat from the Combustion Process
2. Heat Transfer to Steam-Water Circuit
3. Flue Gas Treatment for Pollution Control
Slide 3-2
3.2
Combustion Process
Combustion is defined as the rapid combination (burning) of oxygen with fuel
which results in releasing heat. The oxygen for combustion is supplied by air, which is
about 21% oxygen and 78% nitrogen by volume. Therefore, the combustion gas
circuit begins with the supply of fuel and air. The ratio of air-to-fuel required for
complete combustion of the fuel is dependent on the type of fuel. A more in-depth
discussion of combustion principles is contained in Learning Unit 5.
COMBUSTION PROCESS COMPONENTS
Fuel
Primary Air
Secondary Air
Combustion Chamber
Burners
Fans
Slide 3-3
In general, air is supplied as primary and secondary air. The primary air
serves as the initial source of combustion for the fuel and sometimes acts as the
carrier gas which transports the fuel to the burner. Secondary air is provided for
ensuring complete combustion of the fuel. The mixing of the fuel and air takes place
3-1
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in the burners and the combustion chamber of the boiler furnace. The mixing
characteristics determined by the burner design and the type of fuel dictate the shape
of the flame created during the combustion process. Good mixing of the fuel and air is
important so that the mixture will be uniform throughout; that is every particle of
fuel comes in contact with a particle of air. Most fuels actually turn into a gas before
they burn. The chemical reaction of the elements in the fuel, such as carbon,
hydrogen, and sulfur, combining with oxygen produce chemical compounds and heat.
These chemical reactions are defined as exothermic reactions because heat is
released during the process.
The designs of the burner, combustion chamber and furnace are dependent on
the type of fuel and the application of the steam generated. For small boilers, a single
burner may be employed while for utility boilers, multiple burners are arranged on a
single wall of the boiler or in multiple locations. The specifics of the burner
arrangements and design will be discussed in Learning Units 7, 8, 9,10,11 and 13.
The combustion chamber is the area of a boiler where the burning of fuel
begins. The efficient combustion of fuel and transfer of heat in the boiler require that
adequate combustion air be provided and that the products of combustion or flue gas
be removed from the area of combustion. In some boilers, removal is accomplished
solely by natural convection, commonly called natural draft.
NATURAL DRAFT FURNACEi
STACK
HOT FLUE GASES
OUTLET DAMPER -
BOILER DRUM
EIGHT
VARIES
FURNACE
AIR
FLOW
\ ^- INLET DAMPER
w AIR ENTERING FURNACE
BREECH1NG
Slide 3-4
3-2
-------
Natural draft occurs as the hot flue gas rises through the stack and cool air is
drawn to the burners to replace the volume of gases leaving. Draft is controlled by
using a damper. The amount of draft, or movement of air, is determined by the height
of the stack, the difference between the inside temperature and outside temperature,
and the draft losses. Draft losses are caused by the use of high flue-gas velocities,
tube banks of small diameter, economizers, mechanical dust collectors, and air
preheaters. While these items increase the heat transfer efficiency of a boiler, for
larger boilers, the draft losses they create preclude the use of natural draft.
Mechanical draft is draft created by one or more fans. Forced draft is the
introduction of the combustion air into a furnace to combine with the fuel from
combustion. A forced draft (FD) fan provides the primary air to the burner windbox.
Induced draft is the use of a fan to lower the pressure in the furnace. An induced draft
(ID) fan draws the flue gas to the stack.
Boilers with FD fans and no induced-draft (ID) fans are called pressurized-
furnace boilers because the boiler furnace is above atmospheric pressure. This
situation can be troublesome because flue gas, which is toxic and corrosive, and
flyash leak out of the smallest openings in the furnace, causing maintenance and
personnel safety problems.
FORCED DRAFT FURNACEi
STACK
OUTLET DAMPER
BOILER DRUM
FURNACE
AIR
FLOW
-FORCED DRAFT FAN
INLET DAMPER
AIR ENTERING FURNACE
BREECHING
Slide 3-5
3-3
-------
The solution to these problems is the addition of an ID fan that draws suction
on the furnace and lowers the furnace pressure. Boilers having both FD and ID fans
include dampers or inlet vanes on the fans to balance them and to operate the
furnace at a pressure slightly less than atmospheric also known as negative furnace
pressure. With this arrangement, the leakage of the flue gas and flyash is eliminated.
This configuration is called a balance-draft boiler.
BALANCED DRAFT FURNACE 1
STACK -v
HOT FLUE GASES
INDUCED
DRAFT FAN
OUTLET DAMPER
BOILER DRUM
FURNACE
AIR
FLOW
INLET DAMPER \
•FORCED DRAFT FAN
AIR ENTERING FURNACE
BREECHING
Slide 3-6
To complete the combustion process, secondary air is air added to the
combustion process to ensure that sufficient oxygen is available to complete the
combustion. Secondary air is often introduced through high-velocity air jets or ports.
The high velocity of the secondary air creates turbulence of the burning gases which
enhances the mixing of the oxygen and the combustible gases. The secondary air
may be supplied by a separate secondary fan. The combustion process is completed
in the furnace before the gases enter the convection section of the boiler.
The fans in the combustion gas circuit move a quantity of air or gas by adding
sufficient energy to the stream to initiate motion and overcome all resistance to flow.
The fan consists of a bladed rotor, or impeller, and usually a housing to collect and
direct the air or gas discharged by the impeller. The power required depends upon the
volume of air or gas moved over a given time period. Basically, there are two different
kinds of fans; centrifugal and axial. The centrifugal fan accelerates the incoming air
radially outward into a surrounding casing. The axial flow fan design accelerates the
air parallel to the fan axis. The fan output can be achieved by controlling the flow into
3-4
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the fan or by controlling the fan speed. To control the flow into the fan, variable-inlet
vanes and parallel-blade inlet box dampers are used. For the second control
technique, any speed-changing device such as a multiple-speed motor could be used to
control the fan speed.
TYPICAL FAN DESIGNS3
Two-stage Axial Fan
Gun* HVtS
Straight-Blade Centrifugal Fan
Slide 3-7
3-5
-------
3.3 Heat Transfer
Heat is released from the combustion of the fuel and then transferred to the
steam generating side of the boiler by the three modes of heat transfer - radiation,
conduction and convection.
HEAT TRANSFER MODES
Radiation Conduction Convection
Slide 3-8
Radiation is the transfer of energy by electromagnetic waves from a hot body
to a cold body without physical contact. Light is a form of radiation, but all heat
radiation is not visible. The burning fuel is so hot that a tremendous amount of
energy (infrared and other radiation) is generated. Radiant heat travels in straight
lines and may pass through a vacuum, air, some gases, some liquids and a few solids
such as glass and quartz. Some of the thermal radiation is absorbed by the receiving
body, such as the waterwalls, and raises the temperature of the body and the
remaining energy is reflected from or transmitted through the body. The intensity of
thermal radiation is dependent on the temperature of the radiating matter. Almost
all the heat transferred to the waterwalls of the boiler in the furnace section is by
radiation due to the high temperature of combustion process.
Conduction is the transfer of heat between one molecule to the next within a
substance. For instance, when one end of a steel rod is inserted into a furnace, the
other end of the rod will become hot after a time due to conduction of the heat through
the metal rod.
Convection heat transfer occurs in the convection section of the boiler between
walls, superheater, reheater, and economizer and the flue gas by a combination of
conduction and fluid motion. As an example, heat is transferred from the hot flue gas
to the outside surface of the tube in a superheater and then moves downstream at a
lower temperature. The heat is then transferred to the inside of the tube by
conduction within the tube wall. At the same time, steam flowing on the inside of the
tubes receives the heat by conduction between the steam the inner tube wall and
moves on at a higher temperature. Note that increasing the velocity of the flue gas
through the convection portion of the steam generator increases the convective heat
transfer.
More details on the calculation of each of these modes of heat transfer are
contained in Learning Unit 5.
3-6
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3.4
Combustion Gas Flow Path
Combustion Gas Circuit
Drum
Fuel
Slide 3-9
The flow of combustion gases begins with the combustion air supply. The air
from the FD fan discharge is routed through ducts to the air heater. This is an energy
conserving device which transfers heat from the boiler exhaust gas to the combustion
air. In coal-fired units where the moisture in the coal has to be evaporated in the coal
preparation process prior to combustion, the preheated air is of special importance.
The two principle types of air heaters are the tubular recuperative and the
regenerative.
The tubular air heater is a stationary unit constructed of 2- to 3-inch tubes
through which the hot gases flow. The air flows across the tube bank. The
regenerative air heater transfers heat from the flue gas to the air by heating
regenerative heat-transfer surfaces in a rotor that turns continuously through the
gas and air stream. The air heater will typically reduce the hot combustion product
gas from 600-800 °F to 250- 350 °F and increase the combustion air from 70-80 °F to
500-700 °F.
3-7
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AIR PREHEATERSi
-JE-GAS
OUTLET
SEAL
SECTION
SEGMENTED
WHEEL
FLUE-GAS
INLET
COLD AiR
INLET
FLUE-GAS
OUTLET
COLD AiR
INLET
BAFFLE
AIR BYPASS
HOT AIR
OUTLET
HOT AIR
OUTLET
TUBES
BAFFLE
FLJE-GAS
INLET
HOPPER
REGENERATIVE
TUBULAR
Slide 3-10
After being heated in the air heaters, the air is ducted to the furnace "windbox"
which is basically an air supply chamber attached on the outside of the furnace walls
in the burner or fuel supply zones. The air that is discharged through the windbox will
supply the secondary air for the combustion process. In some furnace designs this
secondary air will be divided between the windbox and the upper section of the
furnace. The air that is routed to the upper furnace is known as overfire air (OFA).
The OFA is supplied by a OFA fan that pulls the air from the combustion air supply
header. By staging the combustion, the lower furnace temperature will be reduced
which is helpful in reducing the formation of some pollutants.
On coal-fired units, hot air is ducted from downstream of the air heater to the
coal pulverizers, which prepare the coal for combustion, to be used in the coal drying
process as well as for transporting the pulverized coal to the furnace area.
Following the combustion process in the boiler furnace, the air flow is referred
to as "combustion products," "flue gas," or "exit gas." Products of combustion is
probably the most applicable name from an environmental viewpoint because these
gases contain the components of air which remain following the combustion process
as well as those components of the fuel that were not consumed.
3-8
-------
These hot gases exit the furnace or radiant zone of the boiler and move through
the convection zone or rear pass section. Then the gases cross the tube banks of the
steam secondary superheater (SSH), reheater (RH), primary superheater (PSH) and
the feedwater economizer (Econ) where heat is transferred to the steam/water cycle;
as shown in Slide 3-9.
Some units have a flue gas recirculating (FGR) fan in the gas circuit. This fan
will typically take hot gas downstream of the economizer and recirculate it into the
lower furnace area. Flue gas recirculation is one method of steam temperature
control that basically increases the total flow of gases through convection section and
increases the heat transferred to the steam.
3.5 Flue Gas Treatment
The flue gas contains the products of the combustion process. Some of these
products have been determined to be detrimental to the environment as "pollutants."
Air quality or environmental regulations may require (depending on the fuel type and
quantity) that these gases be treated to remove those undesirable elements before
the gases are released to the atmosphere. These air pollution control devices
(APCDs) will be located in the gas stream between the economizer outlet and the
stack or chimney.
As will be discussed in Learning Units 21 through 30, there are many different
types of pollution control devices depending on the air pollutant to be controlled. The
more common devices control participate matter, nitrogen oxides, and sulfur oxides.
Depending on the local regulations, a continuous emissions monitoring system
(GEMS) may also be required to measure the emissions levels of the air pollutants
prior to being emitted to the atmosphere. Therefore, the GEMS is the last device in
the stack.
3-9
-------
REFERENCES
1. Wilson, R. Dean, Boiler Operator's Workbook, American Technical Publishers,
Inc., 1991.
2. Elliott, Thomas C., Standard Handbook ofPowerplant Engineering, McGraw-
Hill Publishing Co., 1989.
3. Perry, Robert H. and Green, Don, Perry's Chemical Engineers' Handbook, Sixth
Edition, McGraw-Hill Publishing Co., 1984, p. 6-22.
3-10
-------
CHAPTER 4. FOSSIL FUELS
4.1 Introduction
4.2 Natural Gas
A. Gaseous Fuel Characterization
B. Natural Gas Properties
4.3 Fuel Oil
A. Fuel Oil Grades
B. Liquid Fuel Characterization
C. Fuel Oil Properties
4.4 Coal
A. Formation of Coal
B. Classification of Coal
C. Coal Characterization
D. Items of Proximate Analysis
E. Items of Ultimate Analysis
F. Example Coal Analysis
Slide 4-1
-------
4. FOSSIL FUELS
4.1
Introduction
FOSSIL FUELS
Natural Fuels
Natural gas
Fuel oils
Coal
Byproduct Fuels
Residual oils
Manufactured Fuels
Coke
Char, tar
Chemical and industrial gases, etc...
Slide 4-2
Fossil fuels used for steam generation in utility, industrial, commercial and
institutional power plants may be classified into solid, liquid, and gaseous fuels. Each
fuel is classified as natural, byproduct fuel, or manufactured. Obvious examples of
natural fuels are coal, crude oil, and natural gas. Byproduct fuels include residual oils,
which are byproducts of the refining of crude oils, gas, char, tars, and chemicals and
industrial gases which are derived from coal. Among the fuels, natural fuels are
typically used to generate steam in power plants. This section focuses on
characteristics of natural gas, fuel oil, and coal.
4.2
Natural Gas
Natural gas is perhaps the closest approach to an ideal fuel because it is
practically free of noncombustible gas or solid residue. It is found in porous rock and
shale formations, or cavities, which are sealed between layers of closed-textured
rocks under the earth's surface. When a natural-gas field is tapped by drilling wells,
it is usually found to be under rock pressure, which can be high as 2000 psig.
Natural-gas fields frequently exist in the neighborhood of oil deposits. Usually,
natural gas occupies the space above the oil and the oil, in turn lies over salt water.
Not all natural gas is associated with oil. Sometimes, it is found by itself, or indirect
contact with salt water.
4-1
-------
Although, whenever possible, natural gas is delivered at the required
destination under well pressure, it is frequently transported over long distances by
means of pipelines and compressors. The conditions of the pipelines may change the
composition of natural gas going to the furnace. For instance, aside from the effect of
compression, which liquefies the heavy members of the hydrocarbon family, water
and oil are sometimes sprayed into the gas to keep it "moist." For this reason, any
natural gas analysis, as fired, should be taken at the furnace rather than at the well.
Gaseous Fuel Characterization
GASEOUS FUEL CHARACTERIZATION
Gas Analysis
Heating Value
Specific Gravity
Direct Weighing Method
Pressure Balance Method
Displacement Balance Method
Slide 4-3
Characterization of gaseous fuels (manufactured and natural gases) consists
of determining the gas compositions, heating value and specific gravity.
Gas Analysis: The analysis of fuel gas is expressed in terms of volume
percentages of the component gases. Several methods have been used for fuel gas
analysis. These are absorption in chemical solution, distillation, spectrometry, and
chromatography. Components of fuel gases consist of typical gases including oxygen,
nitrogen, carbon dioxide, etc..., saturated hydrocarbons, and unsaturated
hydrocarbons.
Heating Value: The heating values refers to the quantity of heat released
during combustion of a unit amount of fuel gas. Constant pressure gas calorimeters
are used for the heating value determination. A calorimeter in general is an
apparatus used for measuring heat quantities generated in or emitted by materials in
processes such as chemical reactions, change of state, or formation of solution. The
heating value as determined by calorimeters is termed higher heating value, which is
the quantity of heat evolved when the products of combustion are cooled to 60°F and
the water vapor produced completely condensed to a liquid at that temperature. The
lower heating value differs from the high heating value by the latent heat of
evaporation of water formed in the combustion process. Latent heat is defined as the
4-2
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amount of heat absorbed or evolved by one mol, or a unit mass, of a substance during
a change of state at constant temperature and pressure.
The heating value of gaseous fuels, typically expressed in Btu per cubic foot
(Btu/ft3) measured at 60°F and 30 in. of mercury and saturated with water vapor,
varies considerably, depending on the constituents present.
American Society for Testing and Materials (ASTM) Standards D 3588 gives a
method for calculating calorific value and specific gravity of gaseous fuels and
includes a method for determining the repeatability of the calculated values. ASTM,
founded 1898, is a scientific organization formed for the development of standards on
characteristics and performance of materials, products, systems, and services.
Standard as used in ASTM is a document that has been developed and established
within consensus principles of the Society and that meets the approval requirements
of ASTM procedures and regulations.
Specific Gravity: Various methods for determining the specific gravity of a fuel
gas are available but three methods have been adopted as ASTM Standards D
1070.
Direct Weighing Method: This method involves the determination of the weight
differential between two equal volumes of gas and air, both at identical
conditions of temperature and pressure.
Pressure Balance Method: In this method, a flask containing the gas is
counterbalanced on a beam enclosed in a container. The beam is brought to
balance by adjusting the air pressure within the container which varies the
buoyancy of the flask. The procedure is repeated with air in the flask and the
specific gravity determined from the ratio of the required absolute pressures
Displacement Balance Method: The instrument consists of a balance beam on
each end of which two bells are suspended in a sealing liquid. One bell,
containing air, is open to the atmosphere through holes on its top; the other
4-3
-------
bell, containing the gas, is open to the atmosphere through a 59-in gas column
connected to the space under the bell. An unbalanced force is produced which
is equal to the pressure differential above and within the gas-filled bulb. The
magnitude of this force is an indication of the specific gravity.
Natural Gas Properties
NATURAL GAS PROPERTIES
Composition of Natural Gas
Dry and Wet Natural Gas
Sweet and Sour Natural Gas
Heating Value
Specific Gravity
Slide 4-4
Composition of Natural Gas: The characteristics of natural gas, as it comes
out of the earth's surface, depend to some extent on its underground conditions.
Generally, it is odorless and colorless. It burns with a blue flame and is highly
explosive when mixed with air in the correct proportions. Typical natural gas
compositions are shown in Slide 4r-5.
TYPICAL NATURAL GAS ANALYSESi
Constituents (% by volume)
C02 5.50
N2
H2S 7.00
CHj 77.73
CaHe 5.56
C3H8 2.40
C4HiQ 1.18
CsHtf 0.63*
Density
(Ib/ft3) 0.0562
High Heating Value
Btu/ft3t 1,061
Btu/lb 18,880
* All hydrocarbons heavier
3.51
32.00
0.50
52.54
3.77
2.22
2.02
3.44*
0.0661
874
13,220
than C5H
1 If gas is saturated with moisture at
reduce by 1.74%.
26.2
0.70
—
59.20
13.9
—
—
—
0.0675
849
12,580
0.17
87.69
—
10.50
1.64
—
—
—
0.0712
136
1,907
12 are assumed to be CsH^
60°F and 30
0 in. Hg,
Slide 4-5
4-4
-------
Methane, CHU, and ethane, CgHe, are its principal combustible components.
When sulfur is present in the oil deposit, the analyses of natural gas associated with
this oil often include hydrogen sulfide, H2S. This hydrogen sulfide is removed in most
instances before distributing the gas because it is a potential source of pipeline
corrosion. In addition to its combustible constituents, natural gas may contain
considerable amounts of carbon dioxide, CO2, or nitrogen, N£. Sometimes, the
analysis of natural gas also shows the presence of oxygen.
Dry and Wet Natural Gas: If natural gas has been in contact with oil, it would
absorb various amounts of heavy hydrocarbon vapors, such as pentane, CsH^, or
hexane, CeHi4, which are liquid at ordinary pressure and temperature. This is known
as "wet" natural gas. In a complete analysis of natural gas, a certain fraction of a
heavy hydrocarbon is sometimes preceded by the letter "n," such as "n-butane,"
which means "normal" butane, and the remainder uses the prefix "iso," meaning
"equal," as "iso—butane." The chemical formula is the same in both cases; however,
the physical and chemical properties of these so-called "isomers" are not usually the
same.
"Dry" natural gas comes from wells away from oil deposits and is, therefore,
comparatively devoid of heavy hydrocarbons.
Sweet and Sour Natural Gas: Natural gases are also classified as either
"sweet" or "sour." The sour gas is one which contains some mercaptans and a high
percentage of hydrogen sulfide while the sweet gas is one in which these objectionable
constituents have been removed. Mercaptan is a group of compounds derived from
hydrogen sulfide. It has a characteristically strong odor, and is often added to natural
gas to give it a scent for easy detection.
Heating Value: The heating value refers to the quantity of heat released during
combustion of a unit amount of natural gas. Determinations are made with a
continuous flow (constant pressure) gas calorimeter. The heating value as
determined in calorimeters is termed higher heating value and is the quantity of heat
evolved when the products of combustion are cooled to 60°F and the vapor produced
is completely condensed to a liquid at that temperature. The lower heating value
differs from the higher heating value by the latent heat of evaporation of water
formed in the combustion process. The higher heating values of natural gas are
commonly reported at a pressure of 14.7 psia or 30 in. of Hg, at a temperature of
60°F, and generally on a dry basis.
The higher or gross heating value of natural gas is usually about 1,000 Btu per
cubic foot (Btu/ft3), and it can be computed by adding together the heat contributed
4-5
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by volumetric percentages of the various component gases. The method will usually
result in a lower value per cubic foot than that obtained by calorimetric
determinations, because the unsaturated hydrocarbons are frequently grouped and
reported with CaHe- For the same reason, the corresponding density, under standard
conditions of 60°F and 30 in. Hg, will also be lower. The calculated Btu per pound,
however, will be close to its actual value, because of the compensating effect of the
lower calculated density.
4.3
Fuel Oil
Over millions of years, rivers carried mud and sand which deposited and
ultimately became sedimentary rock formations. Along with this inorganic material,
tiny marine organisms were buried with the silt. Over time, in an airless and high
pressure environment, the organic material containing carbon and hydrogen was
converted to the hydrocarbon molecules of petroleum. Because of the porosity of
sedimentary rock formations, the oil flowed and collected in traps, or locations where
crude oil is concentrated.
Fuel Oil Grades
FUEL OIL GRADES
Distillate Fuel Oils
Fuel Oil No. 1
Fuel Oil No. 2
Residual Oils
Fuel Oil No. 4
Fuel Oil No. 5
Fuel Oil No. 6
Slide 4-6
Fuel oils include virtually all petroleum products that are less volatile than
gasoline. They range from light oils, suitable for use in internal combustion or turbine
engines, to heavy oils, suitable for steam generation boilers. To burn fuel oil, it is
necessary to atomize the fuel before mixing with combustion air. Fuel oils can be
divided into two classes: distillate and residual.
Distillate fuels: Distillate fuels are those that are vaporized in a petroleum
process. They are typically clean, essentially free of sediment and ash, and relatively
free of viscosity. These fuels fall into the No. 1 and No. 2 category in ASTM D 396.
Although No. 2 oil is sometimes used as a premium steam generation fuel, it best
4-6
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lends itself to applications where cleanliness and ease of handling outweigh its cost.
Examples includes home heating and industrial applications where low ash and/or
sulfur are important. Steam generating applications are primarily limited to use
distillate fuels as a startup or support fuel.
Residual fuels: Residual fuel oils are those that are not vaporized by heating
and contains virtually all the inorganic constituents present in the crude oil.
Frequently, residual oils are black, high viscosity fluids that require heating for proper
handling and combustion.
Grade No. 4 and 5 fuel oils are less viscous and therefore more easily handled
and burned than No. 6 oil. Depending on crude oil used, a fuel meeting the No. 4
specification may be a blend of residual oil and lighter distillate fractions. This oil does
not usually require heating for pumping and handling. Grade No. 5 oils may require
heating, depending on the firing equipment and the ambient temperature. Grade No.
6 oils usually require heating for handling and burning.
Liquid Fuel Characterization
LIQUID FUEL CHARACTERIZATION
Ultimate Analysis
Specific Gravity
Heating Value
Viscosity
Pour Point
Flash Point, and
Water and Sediment
Slide 4-7
Characterization of liquid fuels consists of determining fuel compositions, and
their properties including specific gravity, heating value, viscosity, pour point, flash
point, and water and sediment. .
Ultimate Analysis: The ultimate analysis of a liquid fuel is similar to that for a
solid fuel, and uses the ASTM D 3176 Standard Method. The results indicate the
quantities of sulfur, hydrogen, carbon, nitrogen, oxygen, and ash.
Sulfur is a very undesirable element in fuel oils because its products of
combustion are acidic and cause corrosion in economizers, air heater and gas ducts.
Because of the high hydrogen content in fuel oils, and the resulting high water vapor
4-7
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content in the products, a given amount of sulfur in fuel oils has the potential of doing
more damage than the same amount of sulfur in coal.
Fuel oils contain all of the solid impurities originally present in the crude oil. If
these solids, contain a large proportion of salt, they are very fusible and can cause
considerable trouble.
Specific Gravity: This is the ratio between the density of a liquid oil and the
density of water at 60°F. Gravity determinations are conducted by immersing a
hydrometer into the sample and reading the scale at the point to which the
instrument sinks into the oil. The specific gravity is either read direct or the gravity
is measured in degrees API (American Petroleum Institute). The relationship
between the API gravity and the specific gravity is given by the following formula:
141.5
°API = 131.5 (Equation 4-1)
Sp. Gr. 60/60°F
Heating Value: The heating value of a liquid fuel is expressed in Btu per pound
or Btu per gallon at 60°F. Bomb calorimeters are used to determine the heating
value of a liquid fuel.
Viscosity: Viscosity is defined as the measure of the resistance to flow. The
greater this resistance, the longer it takes a given volume of liquid fuel to flow through
a fixed orifice. Viscosity is expressed in Seconds Saybolt Universal (SSU), which is
the time it takes to run 60 cubic centimeters (cc) through a standard size orifice at
the desired temperature. Viscosity is commonly measured at 100, 150, and 210°F.
The liquid fuel is at a held constant temperature within ±0.25°F during the test period.
Other scales, which are Seconds Saybolt Furol (SSF), Centipoise, and
Centistokes, are also used to measure viscosity of a liquid fuel. Sixty-two SSF is
equal to 600 SSU. Centipoise is used to measure absolute viscosity and centistoke is
used to measure kinematic viscosity of a liquid fuel. Kinematic viscosity is a ratio of
absolute viscosity divided by density of the liquid fuel.
Pour Point: Pour point is the lowest temperature at which a liquid fuel flows
under standardized conditions. The viscosity of liquids decreases as temperature is
increased and the pour point is the minimum temperature at which a liquid will flow.
Flash Point: Flash point of a liquid fuel is the lowest temperature at which
sufficient vapor is given off to form a momentary flash when flame is brought near
4-8
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the surface. This is measured by increasing the temperature of the liquid in air and in
the presence of a flame or repeating spark.
Water and Sediment: The water and sediment is a measure of the
contaminants in a liquid fuel. The sediment normally consists of calcium, sodium,
magnesium, and iron compounds. For heavy fuels, the sediment may also contain
carbon. Problems that can be caused by sediment during combustion include line
plugging, and strainer, control-equipment, and burner-nozzle blockage. Water can
lead to corrosion, erratic and inefficient combustion, and even flame failure.
Fuel Oil Properties
TYPICAL ANALYSES AND PROPERTIES OF FUEL OILS*
Grade
Type
Color
API gravity, 60°F
Specific gravity, 60/60°F
Density, Ib/U.S gal, 60°F
Viscos., centistokes, 100°F
Viscos. SSU, 100°F
Viscos., SSF, 122°F
Pour point, °F
Temp, for pumping, °F
Temp, for atomizing, °F
Carbon residue, %
Sulfur, %
Oxygen and nitrogen, %
Hydrogen, %
Carbon, %
Water and sediment, %
Ash, %
Heating Value, Btu/gal
No. 1
Fuel Oil
Distillate
Light
40
0.8251
6.870
1.60
31
Below zero
Atmospheric
Atmospheric
Trace
0.1
0.2
13.2
86.5
Trace
Trace
137,000
No. 2
Fuel Oil
Distillate
Amber
32
0.8654
7.206
2.68
35
Below zero
Atmospheric
Atmospheric
Trace
0.4-0.7
0.2
12.7
86.4
Trace
Trace
141,000
No. 4
Fuel Oil
Very Light
Residual
Black
21
0.9279
7.727
15.00
77
10
15 min.
25 min.
2.5
0.4-1.5
0.48
11.9
86.1
0.5 max.
0.02
146,000
No. 5
Fuel Oil
Light
Residual
Black
17
0.9529
7.935
50.00
232
30
35 min.
130
5.0 max.
2.0 max.
0.70
11.7
85.55
1.0 max.
0.05
148,000
*Data from Exxon Corporation
No. 6
Fuel Oil
Residual
Black
12
0.9861
8.212
360.00
170
65
100
300
12.0 max.
2.8 max.
0.92
10.5
85.7
2.0 max.
0.08
150,000
Slide 4-8
Typical analyses and properties of fuel oils are shown in Slide 4-8.
4-9
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Ultimate Analysis: The different grades of fuel oils have varying percentages of
sulfur, ranging from about 0.3 to 3.0 percent. Distillate oils usually are at the lower
end of the range, and heavy fuels are generally at the upper end. Depending on crude
composition, however, it is possible for a distillate to contain more sulfur than some
residual oils. Distillate oils have about 0 to 0.1 percent ash, and the heavier grades
from 0.2 to 1.5 percent. Although the percentages are quite small, a considerable
amount of ash can accumulate on the fireside of a boiler if firing rates are high.
Heating Value: The heating value per gallon increases with specific gravity,
because there is more weight per gallon, and ranges from about 135,000 to 150,000
Btu per gallon. The heating value per pound varies inversely with the specific
gravity, because the lighter oil contains more hydrogen; it ranges from 18,300 to
19,500 Btu/lb. There is an approximate relationship between specific gravity and
higher heating value. For an uncracked (applied to those oils not produced by
cracking process, which is used to reduce the molecular weight of hydrocarbons by
breaking molecular bonds using thermal or catalytic methods) distillate or residue,
HHV (Btu/lb) = 17,660+ (69 x API gravity)
For a cracked distillate,
HHV (Btu/lb) = 17,780 + (54 x API gravity).
4-10
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Specific Gravity: As previously shown, the API degree has an inverse
relationship with the specific gravity, according to Equation 4—1. Therefore, heavier
liquid fuels are denoted by lower API gravity values. Slide 4-9 shows an example
calculation to convert specific gravity to degrees API and density.
CALCULATING API GRAVITY FROM SPECIFIC
GRAVITY
Given:
Sp. Gr. (60/60°F) =
°API =
1.000
141.5/(Sp. Gr. (60/60°F)) - 131.5
141.5/U)- 131.5
10°
CALCULATING DENSITY FROM SPECIFIC
GRAVITY
Given:
Sp. Gr. (60°F)ofoil
Water Density (60°F)
Oil Density (60°F) =
0.973
8.328 Ib/gal
0.973x8.328
8.099 Ib/gal
Slide 4-9
4-11
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Viscosity: Handling and burning equipment is usually designed for a maximum
oil viscosity. If the viscosities of heavy oils are known at two temperatures, their
viscosities at other temperatures can be closely predicted by a linear interpolation (a
process to find a value of a function between two known values under the assumption
that the three plotted points lie on a straight line) between these two values on the
standard ASTM chart shown in Slide 4-10. Viscosity-temperature variations for
certain light oils can also be found using the ASTM chart. In this case, however, the
designer only needs to know the viscosity at one temperature. For example, the
viscosity of a light oil at a given temperature within the No. 2 fuel oil range can be
found by drawing a line parallel to the No. 2 boundary lines through the point of
known temperature.
VISCOSITY RANGES FOR FUEL OILS
ASTM Std Viscosity -
Temperature Charts for Liquid
Petroleum Products (D 341)
SSU - SayBolt Universal Viscosity
100,000
Fuel Oil Composition
(Kerosene Straight
No 1 Kerosene Plus 5% No 2
No 2 Straight
No 4 Straight and Up to 15% Residuals
Residual f No 5 Heavy Distillates Plus Up to 40% Residuals
Oils \ No 6 Up to 100% Residuals
-20 0
20 40 60 80 100 140
Temperature, ° F
Slide 4-10
Pour point: Pour points for domestic heavy oils range from 25 to 65°F. But
normal heating of storage tanks, pipelines, and pumping equipment above this range
of temperatures reduces the resistance to flow.
4-12
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Flash point: Distillate oils normally have flash points from 145 to 200°F, while
the flash points for heavy oils can be as high as 250°F. Thus, fuels oils do not present
a fire hazard at ambient temperatures unless they are contaminated with a volatile
product.
Water and Sediment: Distillate oils have a trace to 0.2 percent of water and
sediment; the heavier grades have from 0.1 to 2 percent.
4.4 Coal
Formation of Coal
Coal is formed from plants which have undergone chemical and geological
processes over millions of years. Layers of plant debris are deposited in wet and
swampy regions under conditions which prevent exposure to air and complete decay
as the debris accumulate. Bacterial actions, pressure, and temperature act on the
organic matter over time to form coal. The geological process that transforms debris
to coal is called coalification. The first product of this process, peat, often contains
partially decomposed stems, twigs, and bark and is not classified as coal. However,
peat is progressively transformed to lignite which eventually can become anthracite
given the proper progression of the geological changes.
Coal is very heterogeneous and can vary in chemical composition by location.
In addition to the major organic ingredients—carbon, hydrogen, and oxygen—coal also
contains impurities. The impurities that are of major concern are ash and sulfur.
The ash results from mineral or inorganic material introduced during coalification.
Ash sources include inorganic substances, such as silica, which are part of the
chemical structure of the plants. Dissolved inorganic ions and mineral grains found in
swampy water are also captured by the organic matter during early coalification.
Mud, shale, and pyrite are deposited in pores and cracks of the coal seams. Sulfur
occurs in coal in three forms: 1) organic sulfur, which is part of the coal's molecular
structure, 2) pyritic sulfur, which occurs as the mineral pyrite, and 3) sulfate sulfur,
primarily from iron sulfate. The principal source is sulfate ion, which is found in
water. Fresh water has a low sulfate concentration while salt water has high sulfate
content. Therefore, bituminous coal, deposited in the interior of the U.S. when seas
covered this region, are high in sulfur. Some Iowa coals contain as much as 8%
sulfur.
4-13
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Classification of Coal
Coals are grouped according to rank, the degree of progressive alteration in the
transformation from lignite to anthracite. The system used in the U.S. for classifying
coal by rank was established by the American Society for Testing and Materials
(ASTM). ASTM classification is a system which uses the volatile matter and fixed
carbon (FC) results from the proximate analysis and the heating value of the coal as
ranking by criteria. This system aids in identifying commercial uses of coals and
provides basic information regarding combustion characteristics.
The classification system is given in Slide 4-11 and described in section D 388
of the ASTM standards. For older and higher rank coals, fixed carbon and volatile
matter are used as the classifying criteria. These criteria are determined on a dry,
mineral-matter-free basis using formulas developed by S.W. Parr in 1906 (Slide
4-12). The younger or lower rank coals are classified by Btu content on a moist,
mineral-matter free basis. Agglomerating or weathering indices as described in the
ASTM D 388, are used to differentiate adjacent groups.
4-14
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CLASSIFICATION OF COAL BY RANK*
Fixed Carbon
Limits, %
(Dry, Mineral-
Matter-Free
Basis)
Class and Group
Equal or
Greater
Than
Less
Than
L Anthracite
1. Meta-Anthracite 98
2. Anthracite 92
3. Semi-Anthracitec 86
II. Bituminous Coals
1. Low-volatile 78
2. Medium-volatile 69
3. High-volatile A —
4. High-volatile B —
5. High-volatile C —
III. Subbituminous Coals
1. Subbituminous A —
2. Subbituminous B —
3. Subbituminous C —
IV Lignite
98
92
86
78
69
1.
2.
Lignite A
Lignite B
Volatile Matter Calorific Value
Limit,s, % Limits, Btu/lb
(Dry, Mineral-
Matter-Free
Basis)
Equal or
Greater Less
Than Than
(Moistb, Mineral-
Matter-Free
Basis)
Equal or
Greater
Than
Less
Than
2
8
14
22
31
2
8
14
22
31
Agglomerating
Character
Nonagglomerating
14,000*
13,000d
11,500
10,500
10,500
9,500
8,300
— 6,300
— Agglomerating8
14,000
13,000
11,500 Agglomerating
11,500
10,500 Nonagglomerating
9,500
8,300
6,300
a This classification does not include a few coals, principally nonbanded varieties, which have usual
physical and chemical properties and which come within the limits of fixed carbons or calorific value 01
the high-volatile bituminous and Subbituminous ranks. All of these coals either contain less than
48% dry, mineral-free-matter fixed carbon and have more than 15,500 moist, mineral-matter free Btu
per pound.
b Moist refers to coal containing its natural inherent moisture but not including visible water on the
surface of the coal.
c If agglomerating, classify in low-volatile group of the bituminous class.
d Coals having 69% or more fixed carbon on the dry, mineral-matter-free basis shall be classified by
fixed carbon, regardless of calorific value.
e It is recognized that there may be nonagglomerating varieties in these groups of the bituminous
class, and there are notable exceptions in high-volatile C bituminous group.
Data from ASTM Standards D 388. Classification of coals by Rank.
Slide 4-11
4-15
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Dry, mineral-free FC =
Dry, mineral-free VM =
Moist, mineral-free Btu =
PARR FORMULAS2
FC - 0.15S
xlOO
100 - (M+ 1.08A + 0.55S)
100 - Dry, mineral-free FC
Btu - SOS
xlOO
100 - (1.08A + 0.55S)
APPROXIMATION FORMULAS*
FC
Dry, mineral-free FC =
Dry, mineral-free VM =
Moist, mineral-free Btu =
Where:
Btu = Heating value per Ib,
FC = Fixed carbon, %
VM = Volatile matter, %
M = Bed moisture, %
A = ash, %
S = Sulfur, %
xlOO
100-(M + 1.1A + 0.1S)
100 - Dry, mineral-free FC
Btu
100-U.1A + 0.1S)
xlOO
Slide 4-12
Anthracite: Anthracite, the highest rank of coal, is shiny, black, hard and
brittle, with little appearance of layers. It has the highest content of fixed carbon, 86
to 98%. However, its low volatile content makes it a slow burning fuel. Most
anthracite have a very low moisture content of about 3% and heating values of about
15,000 Btu/lb. Anthracite is low in sulfur and volatiles and burns with a hot clean
flame. These qualities make it a premium fuel used mostly for domestic heating.
Bituminous: Bituminous coal is the rank most commonly burned in electric
utility boilers. In general, it appears black with banded layers, of glossy and dull black.
Typical bituminous coals have heating values of 10,500 to 14,000 Btu/lb and a fixed
carbon content of 69 to 86%. The heating value is higher but moisture and volatile
matter content are lower than subbituminous and lignite coals. Bituminous coals
rarely experience spontaneous combustion in storage. Furthermore, the high heating
4-16
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value and fairly high volatile matter enable bituminous coals to burn easily when
pulverized to a fine powder. Some types of bituminous coals, when heated in the
absence of air, soften and release volatiles to form a porous, hard, black product
known as coke.
Subbituminous: Subbituminous coals are black, having little of the plant like
texture and none of the brown color, associated with the lower rank coals.
Subbituminous coals are noncoking (undergo little swelling upon heating) and have
relatively high moisture content which averages from 15 to 30%. They also display a
tendency toward spontaneous combustion when drying.
Although they are high in volatile matter content and ignite easily,
Subbituminous coals generally have less ash and are cleaner burning than lignite
coals. Subbituminous coals in the U.S. in general have a low sulfur content, often less
than 1%, and reasonably high heating values, 8,300 to 11,500 Btu/lb.
Lignite: Lignite is the lowest rank coal. Lignite are relative soft and brown to
black in color with heating value less than 8,300 Btu/lb. The deposits are geologically
young and can contain recognizable remains of plant debris. The moisture content of
lignites is as high as 30% but the volatile matter is also high; consequently, they
ignite easily. Lignite coal dries when exposed to air and spontaneous combustion
during storage is a concern. Long distance shipment is not economical because of
their high moisture and low Btu contents.
Peat: The first product in the formation of coal, is a heterogeneous material
consisting of partially decomposed plant and mineral matter. Its color ranges from
yellow to brownish black, depending on its geologic age. Peat has a moisture content
up to 70% and a heating value as low as 3,000 Btu/lb.
4-17
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Coal Characterization
COAL CHARACTERIZATION
Proximate Analysis
Ultimate Analysis
Bases of Analyses
As-received basis
Dry basis
Dry mineral-matter free basis
Slide 4-13
There are two types of fuel characterization methods: proximate analysis and
ultimate analysis. Proximate analysis, typically conducted for solid fuels, gives
information on the behavior of a solid fuel when it is heated; that is, how much of the
fuel burns as gas or volatile matter, and how much remains as fixed carbon.
Proximate analysis provides useful information to assist in the selection of a fuel for a
boiler. In addition to the volatile matter and fixed carbon determination, proximate
analysis provides moisture and ash contents as well as the heating value of the fuel.
ANSI/ASTM Standards D 3172 is the basic method for proximate analysis of coal
and coke.
The ultimate analysis gives the elemental analysis of the fuel. The elements
include carbon, hydrogen, nitrogen, oxygen, and sulfur. Ash which consists of several
compounds is usually determined as a whole, and whenever necessary, composition of
the ash is given in a separate analysis. ASTM Standards D 3176 is the standard
method for ultimate analysis of coal and coke.
Fuel analysis may be given in several bases. In combustion calculations, the
as-received basis is applicable. Typically, the dry or moist and mineral-matter-free
bases are used.
As-Received Basis: The as-received analysis of a fuel represents the actual
proportions of the constituents in the fuel sample as received at the laboratory. The
sample may be fuel as fired, as mined, or in any other given condition.
Dry Basis: Moisture content is variable, even in the same coal, under different
conditions of handling and exposure. For example, coal as received at a plant may
4-18
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contain an amount of moisture different from that received at the laboratory for
analysis, and both may vary with weather conditions.
Dry Mineral-Matter-Free Basis: As mentioned previously, because the ash
does not correspond in percentage to the mineral matter in the coal, errors are
introduced which becomes significant in problems of classifying coals according to
rank. Parr and other approximation formulas (Slide 4-12) are used for such
calculations.
Items of Proximate Analysis
ITEMS OF PROXIMATE ANALYSIS
Moisture
Volatile Matter
Fixed Carbon
Ash
Heating Value
Ash Fusion Temperature
Free Swelling Index
Grindability
Slide 4-14
Moisture: Coal received at an electric power plant contains varying amounts of
moisture in several forms. There is inherent and surface moisture in coal. Inherent
moisture is that which is a naturally combined part of coal deposit. It is held tightly
within the coal structure and can not be removed easily when the coal is dried in air.
The surface moisture is not part of the coal deposit and has been added externally.
Surface moisture is more easily removed from coal when exposed to air. It is not
possible to distinguish, by analysis, inherent and surface moisture.
There are many other moistures which arise when characterizing coal including
equilibrium, free and air dry moisture. Their definitions and use depend on the
application. The ASTM standard procedure for moisture determination, D 121,
defines the total coal moisture as the loss in weight of a sample under controlled
conditions of temperature, time and air flow. Using ASTM 3302, the total moisture is
calculated from the moisture lost or gained in air drying and the residual moisture.
The residual moisture is determined by oven drying the air dried sample. Because
subsequent ASTM analyses (such as proximate and ultimate) are performed on an
air dried sample, the residual moisture value is required to convert these results to a
4-19
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dry basis. In addition, the moisture lost on air drying provides an indication of the
drying required in the handling and pulverization portions of the boiler coal feed
system.
Volatile Matter: The volatile matter is that portion which, exclusive of water
vapor, is driven off in gas or vapor form when the coal is subjected to a standardized
temperature test. It consists of hydrocarbons and other gases resulting from
distillation and decomposition. ASTM D 3175 is the standard method to determine
volatile matter in coal and coke.
The main constituents of volatile matter in all ranks of coal are hydrogen,
oxygen, carbon monoxide, methane and other hydrocarbons, and that portion of
moisture that is formed by chemical combination during thermal decomposition of the
coal substance. The composition of volatile matter varies greatly for different ranks
of coals.
Fixed Carbon: The fixed carbon is the combustible residue left after driving off
the volatile matter. It is not all carbon, and its form and hardness are an indication of
the coking (dry distillation of coal to make coke) properties of a coal, and therefore, a
guide in the choice of fuel-firing equipment. In general, the fixed carbon represents
that portion of the fuel that must be burned in solid state, either in the fuel bed on a
stoker, or as solid particles in the pulverized fuel furnace.
The fixed carbon in a proximate analysis is a calculated figure obtained by
subtracting from 100 the sum of the percentages of moisture, volatile matter and
ash.
Ash: Ash is the noncombustible residue after complete combustion of the coal.
The weight of ash is usually slightly less than that of the mineral matter originally
present before burning. The ASTM definition for coal ash is the organic residue
remaining after ignition of combustible substances, determined by definite prescribed
methods. This definition is followed by two notes, one of which states that ash may
not be identical—in composition or quantity—to inorganic substances before ignition.
The second note specifies that, in the case of coal and coke, the methods shall
be those prescribed by ASTM Standards D 3174. This method determines the ash
content by weighing the residue remaining after the coal is burned under rigidly
controlled conditions of sample weight, temperature, time and atmosphere, oxidizing
or reducing.
4-20
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Ash is usually considered the product of complete combustion of coal. It is
composed of the oxides formed from the mineral constituent of coal. However, these
minerals may be present in two forms in coal: (1) as visible impurities or (2) as
minute impurities so finely divided and so intimately mixed that they may be
considered a part of the coal structure.
The term inherent or fixed ash content is used to designate that portion of the
ash content that is structurally part of the coal and cannot be separated from it by
mechanical means. This is a relative term, however, and will have different values,
since mechanical separation is accomplished at varying levels according to the size of
the coal.
Heating Value: In the U.S., the calorific or heating value of a solid fuel is
expressed in Btu per Ib of fuel on as-received, dry, or moisture— and ash-free basis.
It is the amount of heat recovered when the product of complete combustion of a unit
quantity of a fuel are cooled to the initial temperature of the air and fuel. Heating
values as determined in calorimeters are termed high or gross heating values, and
include the latent heat of the water vapor in the products of combustion. The most
common type of calorimeter in use today is the adiabatic bomb calorimeter, and
ASTM Standards D 2015 covers this test. In actual operation of boilers, the water
vapor in the combustion gas leaving is not cooled below its dew point, and this latent
heat is not available for making steam. The latent heat can be substracted from the
high, or gross, heating value to give the low, or net, heating value. Lower heating
values are standard European practice and higher heating values are standard
American practice.
Ash-Fusion Temperature: Coal ash fusion temperatures are determined from
cones of ash prepared and heated in accordance with ASTM Standards D 1857. The
temperatures at which the cones deform to specific shapes are determined in
oxidizing and reducing atmospheres (see Chapter 29). Fusion temperatures provide
ash melting characteristics and are used for classifying slagging potentials of the ash.
Slagging is the formation of molten, partially melt or resolidified deposits on furnace
walls and other surfaces exposed predominantly to radiant heat or excessively high
gas temperatures.
Free Swelling Index: The free swelling index is used to measure the caking
(changing of a powder into a solid mass) characteristics of a coal. ASTM Standards D
720 is used for free swelling index tests. In these tests, one gram of of coal sample is
burned in a covered crucible under specific conditions of temperature and time. The
shape of the sample (button formed) is then compared to a set of standard buttons.
The larger button formed indicates higher free swelling indices.
4-21
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Grindability: This test determines the relative ease of pulverization of coal in
comparison with coals chosen as standards. The Hardgrove method has been
accepted as the standard, and ASTM Standards D 409 is the Grindability of Coal by
the Hardgrove-Machine Method. Each Hardgrove machine is calibrated by use of
standard reference samples of coal, having grindability indexes of approximately 40,
60, 80, and 100. The Hardgrove-index number reported by the laboratory is based on
an original soft coal chosen as a standard coal whose grindability index was set at
100. Therefore, the harder the coal, the lower the index number.
Since the grindability index varies, not only from seam to seam but also within
the same seam, grindability data are of utmost economic importance to the users of
commercial grinding and pulverizing equipment.
Items of Ultimate Analysis
ULTIMATE ANALYSIS
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Washability
Slide 4-15
Ultimate analysis is needed for computation of air requirements, weight of
products of combustion, and heat losses, on boiler tests. The air requirement and the
weight of products of combustion determine fan sizes. The following are items of
ultimate analysis as determined by ASTM standards D 3176,
Carbon: Total carbon includes both the carbon in the fixed carbon and in the
volatile matter, and will be proportionately greater than the fixed carbon as the
volatile content of the coal increases. All this carbon appears in the products of
combustion as CC>2 when the fuel is completely burned.
Hydrogen: When coal is burned, all hydrogen in the fuel is transformed into
water and, together with the moisture in the fuel, appears as water vapor in the
waste gas. Ultimate analysis includes moisture in the hydrogen and oxygen items.
The weight of the water vapor in the products of combustion is nine times the weight
of the hydrogen in the coal.
4-22
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Nitrogen: Nitrogen in most solid fuels is low and of no importance in
combustion calculations.
Sulfur. Sulfur is separately determined, and its amount is useful in judging the
corrosiveness of the products of combustion of a fuel. Combustion of sulfur forms an
oxide, which combines with water to form acids that may be deposited when the
combustion gas is cooled below its dew—point temperature.
Sulfur in coal occurs mainly in three forms. It can be present as the sulfide ion
in pyrites and marcasite; or it can be present as the sulfate ion. Rarely, sulfur may
occur as elemental sulfur in coal, but in amounts too insignificant to be appreciable.
ASTM Standards D 2492 gives a standard test method to determine the form of
sulfur in the coal.
Two methods are generally accepted for total sulfur determination. Eschka's
method converts all the sulfur present in the coal to the sulfate ion, which is then
precipitated as BaSC>4. The Eschka method requires a time period—including sample
preparation—of up to 24 hours, so a more rapid method of high-temperature
combustion has been adopted. Details and analytical procedures for both of these
methods may be found in ASTM standards D 3177.
Oxygen: The oxygen content of fuels is a guide to the rank of the fuel. The
amount of oxygen is high in low-rank fuels like lignite. Oxygen in fuels is in
combination with carbon and hydrogen and, therefore, represents a reduction in the
potential heat of a fuel. High-oxygen fuels have low heating values. As there is no
direct ASTM method of determining oxygen, it is calculated by subtracting from 100
the sum of the other components in the ultimate analysis.
Washability: The washability characteristic of a coal is the most important
tool available to determine the extent to which a coal may be cleaned. Examination
of washability data for a particular coal of a particular size of coal will reveal the
quality of coal which may be obtained by mechanical cleaning, as well as the quantity
of coal of particular quality. Further examination of the data will indicate the ease or
difficulty with which the coal may be cleaned or will give valuable information
concerning the type of commercial cleaner most suitable for that particular coal.
The ash, sulfur, or Btu specifications of all of the final product generally dictate
whether or not cleaning is necessary. After technical considerations are evaluated
with the help of washability characteristics and if cleaning is technically sound, the
4-23
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economic decisions are made. These considerations include the value of the final
product and the cost of obtaining it.
Float-and-sink separation is quite effective for determining the washability
characteristics of coarse coal, but the problems associated with cleaning of extremely
fine sizes dictate other methods. Froth flotation process consists of passing air
through a suspension of fine coal in water. The coal particles attach themselves to
the air bubbles and are removed in the froth on top of the pulp. The refuse particles
remain in the pulp. Chemical are added to the pulp to help produce the froth.
Example Coal Analyses
EXAMPLE COAL ANALYSES
Coal: Eastern Bituminous
Proximate Analysis (as rec'd) Ultimate Analysis (as rec'd)
Total Moisture 17.80 Moisture
Volatile Matter 34.04 Carbon
Fixed Carbon 39.38 Hydrogen
Ash 8.78 Oxygen
Nitrogen
Sulfur
Ash
Higher Heating Value 10,406 Btu/lb
17.80
57.76
3.99
7.51
1.16
3.00
8,78
Ash Analysis (as rec'd) Ash Fusion Temperatures (°
SiO2 50.65
A12O3 13.91
TiO2 0.89 Initial Deform temp.
Fe2O3 18.88 Softening temp.
CaO 6.26 Hemispherical temp.
MgO 0.85 Fluid temp.
Na2O 1.36
K2O 1.52 Slagging Index
P205 0.18 Fouling Index
SO3 5.72
Hardgrove Grindability Index 58
Reducing
1,930
2,000
2,150
2,260
Medium
High
F)
Oxidizing
2,230
2,400
2,480
2,580
Slide 4-16
Slide 4-16 shows an example coal analysis of a bituminous coal. In this
example, proximate, ultimate and ash analyses are on as received basis. Ash fusion
temperatures are given in both reducing and oxidizing environments.
4-24
-------
REFERENCES
1. Singer, J. G., Combustion: Fossil Power Systems, 3rd edition, Combustion
Engineering, Inc., 1981.
2. Steam, Its Generation and Use, 40th Edition, Babcock and Wilcox Company,
1992.
3. Elliot, C.T., Standard Handbook of Powerplant Engineering, McGraw Hill
Publishing Company, New York, 1989.
4. Annual Book of ASTM Standards, Section 0, Index, American Society for
Testing and Materials, 1987.
4-25
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CHAPTER 5. COMBUSTION PRINCIPLES
5.1 Basic Combustion Concepts
A. Combustion Processes
B. Composition of Combustion Air
5.2 Air-Fuel Mixture
5.3 Combustion Equations
A. Concept of the Mole
B. Fundamental Laws
C. Balancing Combustion Equations
5.4 Combustion Calculations
A. Molar Evaluation of Combustion
B. Calculating Theoretical Air
C. Calculating Excess Air
D. Calculating Percent Excess Air
5.5 Heat Transfer Fundamentals
A. Basic Modes of Heat Transfer
B. Heat Transfer Parameters
Slide 5-1
-------
5. COMBUSTION PRINCIPLES
5.1 Basic Combustion Concepts
Combustion Processes
SIMPLIFIED COMBUSTION PROCESSES
Reactants Products
carbon + oxygen —>
hydrogen + oxygen —>
sulfur + oxygen —>
carbon dioxide
water vapor
sulfur dioxide
+ heat
-i-heat
+ heat
Slide 5-2
As a simplification, combustion processes can be described as shown Slide 5-2.
Combustion, or burning, is a rapid combination of oxygen with a fuel, resulting in
release of heat. The principal combustible constituents of a fuel are elemental
carbon, hydrogen, and their compounds. In the combustion process, the elements and
compounds are burned to release heat. Carbon dioxide and water vapor are formed in
the process. In addition, small quantities of sulfur are present in most fuels.
Although sulfur is a combustible and contributes slightly to the heating value of the
fuel, its presence is generally detrimental because of the corrosive nature of its
compounds.
The three products of combustion listed above are called chemical compounds,
and they are made up of molecules in which elements are combined in certain fixed
proportions. For example, a molecule of carbon dioxide, written as C02, contains one
atom of carbon plus two atoms of oxygens; a molecule of water, written as H20,
contains two atoms of hydrogen plus one atom of oxygen.
Composition of Combustion Air
The oxygen needed for the combustion process comes from the air, which is
about 21 percent oxygen, 78 percent nitrogen, and 1 percent by volume of other
elements or compounds, such as argon, carbon dioxide, moisture, etc... The
composition of dry atmospheric air is given in Slide 5-3.
5-1
-------
COMPOSITION OF COMBUSTION AIR
Dry Atmospheric Air
Volume % Mole. Wt.
Nitrogen 78.09
Oxygen 20.95
Argon 0.93
Carbon dioxide 0.03
28.02
32.00
39.94
41.01
Slide 5-3
5.2
Air-Fuel Mixture
COMBUSTION TERMS
Excess Oxygen
Excess Air
Stoichiometric
Lean Mixture, Oxidizing Flame
Rich Mixture, Reducing Flame
Oxygen Supply
Time, Turbulent, Temperature
Slide 5-4
Perfect combustion is obtained by mixing and burning just exactly the right
proportions of fuel and oxygen so that nothing is left over (no excess oxygen). These
proportions are called, in theory, Stoichiometric quantities. In practice, however, it is
not possible to operate a boiler at the theoretical level of zero percent excess oxygen.
This condition is approached by providing an excess amount of oxygen in the form of
excess air from the atmosphere. The amount of excess air varies with fuel, boiler load,
and the type of firing equipment.
In practice, excess air levels are kept at a minimum for the reasons as follows:
• minimize heat loss due to heating up the extra air (see Chapter 6),
• reduce chances of tube erosion in the upper furnace,
• reduce air pollution emissions (see Chapter 6), and
• this minimum needs to be sufficient to minimize combustible losses in
the flue gas and CO and hydrocarbon emissions (See Chapter 6).
If more than the Stoichiometric amount of oxygen is supplied, the mixture is
5-2
-------
called lean and the fire is called oxidizing. This results in a flame that tends to be
shorter and clearer. If more than the stoichiometric amount of fuel is supplied, the
mixture is called rich and the fire is called reducing. This results in a flame that tends
to be longer and sometimes smoky. This situation is usually called incomplete
combustion; that is, all of the fuel particles combine with some oxygen, but they
cannot get enough oxygen to burn completely.
The oxygen supply for combustion usually comes from the air. Because air
contains a large proportion of nitrogen, the required volume of air is much larger than
the required volume of pure oxygen. Most of the nitrogen in the air does not take part
in the combustion reaction. It does, however, absorbs some of the heat. This means
that a much lower flame temperature results from using air instead of pure oxygen.
The same phenomenon occurs when large amounts of excess air are supplied.
In addition to absorbing heat, a small amount of nitrogen combines with
oxygen at high temperatures (greater than 2500°F) to form nitrogen oxides, which
become air pollutants once emitted to the atmosphere. Air pollutants from
combustion processes will be discussed in Chapter 6.
The rate and degree of completion of a combustion process are greatly
influenced by three general factors: time, turbulence and temperature. The more time
a fuel and air mixture have at the proper combustion conditions, the more likely
complete combustion will occur. Mixing of the fuel and air is important for a uniform
mixture where every particle of fuel contacts oxygen. Turbulent mixing of the fuel
and air results in a more uniform mixture, the combustion reaction will go to
completion better—turbulent. At higher a temperature, the rate of the combustion
reaction will go faster since fuel and air will be in contact more frequent due to
increases in molecular movement.
5.3 Combustion Equations
Concept of the Mole
CONCEPT OF THE MOLE
• A mole always contains the same number of
particles.
• Pound mole (mole) is molecular weight
expressed in pounds.
Example:
1 mole of CC>2 weighs 44 Ibs
1 mole of H20 weighs 18 Ibs
Slide 5-5
5-3
-------
The key to understanding the concept of the mole is that it always contains the
same number of particles, no matter what the substance. Many, many experiments
over the years have established that number as:
1 mole = 6.022045 x 1023 particles
= 602,204,500,000,000,000,000,000 particles
This number, usually rounded off to 6.022 x 1023, is known as Avogadro's
number in honor of Amadeo Avogradro, an Italian lawyer and physicist (1766-1856)
who conceived the basic idea.
A molecular weight expressed in pounds is called a pound mole, or simply a
mole. The molecular weight is the sum of the atomic masses of a substance's
constituent atoms. For example pure elemental carbon (C) has an atomic mass and
molecular weight of 12 and therefore a mole of C is equal to 12 Ibs. In the case of
carbon dioxide (COz), carbon still has an atomic mass of 12 and oxygen has an atomic
mass of 16 giving CO 2 a molecular weight and a mole equal to (1 x 12) + (2 x 16) or 44
Ibs.
In the case of a gas, the volume occupied by one mole is called the molar
volume. The volume of one mole of an ideal gas is constant regardless of its
composition for a given temperature and pressure. Therefore, one mole or a mole of
oxygen (62) at 32 Ib and one mole of C02 at 44 Ib will occupy the same volume equal
to 394 ft3 (cubic feet) at 80°F and 14.7 psi (pounds per squared inch). The volume
occupied by one mole of a gas can be corrected to other pressures and temperatures
by the ideal gas law.
Fundamental Laws
FUNDAMENTAL LAWS
Conservation of Matter
Conservation of Energy
Law of Combining Weight
Avogadro's Law
Ideal Gas Law
Slide 5-6
Combustion calculations are based on several fundamental physical laws.
Conservation of Matter: This law states that matter can not be destroyed or
created. There must be a mass balance between the sum of the components entering
a process and the sum of those leaving: X pounds of fuel combined with Y pounds of
air always results in X + Y pounds of products.
5-4
-------
Conservation of Energy: This law states that energy can not be created or
destroyed. The sum of the energies (potential, kinetic, thermal, chemical and
electrical) entering a process must equal to the sum of those leaving, although the
proportions of each may change.
Law of Combining Weight: This law states that all substances combine in
accordance with simple, definite weight relationships. These relationships are exactly
proportional to the molecular weights of the constituents. For example, carbon
(molecular weight = 12) combines with oxygen (molecular weight = 32) to form carbon
dioxide (molecular weight = 44) so that 12 Ib of C and 32 Ib of 02 combine to form 44
lbofC02.
Avogadro's Law: Avogadro determined that equal volumes of different gases at
the same pressure and temperature contain the same number of molecules. From
the concept of the mole, a pound mole of any substance contains a mass equal to the
molecular weight of the substance. Therefore, the ratio of mole weight to molecular
weight is a constant and a mole of any chemically pure substance contains the same
number of molecules. Because a mole of any ideal gas occupies the same volume at a
given pressure and temperature (ideal gas law), equal volumes of different gases at
the same pressure and temperature contain the same number of molecules.
5-5
-------
IDEAL GAS LAW
This law state that the volume of an ideal gas is directly
proportional to its absolute temperature and inversely
proportional to its absolute pressure. The proportionality
constant is the same for one mole of any ideal gas, so this law
may be expressed as:
R =
Where:
P2V2
T2
R = universal gas constant, 1545 ft Ib/mole R.
V = molar volume, ft3/mole
P = absolute pressure, lb/ft2
T = absolute temperature, R = °F + 460
Most gases involved in combustion calculations can be
approximated as ideal gases.
Slide 5-7
Balancing Combustion Equations
The law of conservation of matter requires that the mass of the substances
must be the same on each side of the reaction equation. In another word, balancing a
chemical equation ensures that the same number of atoms of each element involved
appears on each side of the equation. A partial list of the combustion equations are
given in Slide 5-8.
COMBUSTION EQUATIONS
Combustibles Reaction
Carbon
Hydrogen
Sulfur
Methane
Ethane
Propane
C + 02
H2 + V202
S + 02
CH4 + 202
C2Hs + ?/2C)2
CaHg + 502
C02
H20
S02
C02 + H2O
2C02 + 3H2O
3C02 + 4H2O
Slide 5-8
5-6
-------
Taking the combustion equation of carbon as an example and applying these
concepts, now this equation can be written in several ways:
FORMS OF COMBUSTION EQUATIONS
C + 02 C02
1 molecule C02
1 mole C02
44 Ib C02
1 ft3 C02
(i) If C were an ideal gas instead of solid, 1 ft3 of C
combines with 1 ft3 of O2 to form 1 ft3 of CO2.
Slide 5-9
1 molecule C + 1 molecule 02 =
1 mole C +1 mole O2
121bC + 321b02
+ Ift302
Each equation balances; there are the same number of atoms of each element
and the same weight of reacting substances on each side of the equal sign but not
necessarily the same number of molecules, or moles or volumes. Thus, one atom of
carbon combines with one molecule of oxygen to give only one molecule of carbon
dioxide.
BAI
C3H8 4
CaHs 4
C3H8 4
C3H8 4
ANCING COMBUSTION EQUATIONS
(unbalanced equation)
Oo •;> POn 4- FToO
\J2, — ----.^ \^v_/2 ^- n.2vy
o0 -> ^rOo -i- Wr,o
Oo ^. ^fOo J. 4Wr.O
(balanced equation)
5Oo > ^rOo 4- 4HoO
Slide 5-10
Let's take the combustion equation of propane as another example and
balance this equation step by step, see slide 5-10.
Although there are several systematic ways to balance such an equation, it is
advisable to leave the oxygen balance to the last step. Generally, it is best to balance
the C atom first, followed by H, and then 0.
5-7
-------
Step 1. Balance the C atoms. There are 3 carbon atoms in the reactants, so there
must be 3 carbon atoms in the products. Therefore, we need 3 CO2
molecules on the right side.
Step 2. Balance the H atoms. There are 8 H atoms in the reactants. Each molecule
of water gas has 2 H atoms, so 4 molecules of water will have the required 8
H atoms.
Step 3. Balance the O atoms. There are 10 O atoms on the right side (3 x 2 = 6 in
CO2 and 4 x 1 = 4 in H2O). Therefore, 5 02 molecules are needed to supply
the required 10 O atoms.
Step 4. Verify that each element is balanced. The reaction involves 3 C atoms, 8 H
atoms, and 10 O atoms on each side.
It should be noted again that the total mass of the reactants is the same as
that of the products, but not the total number of moles.
Mass of reactants: (3 x 12 + 8 x 1) + (5 x 32) = 204 Ibs
Mass of products: (3 x 44) + (4 x 18) = 204 Ibs
(Note that one atom of H weighs 1 Ib and one mole of water weighs 18 Ibs)
Moles of reactants:
Moles of products:
1 moles + 5 moles
3 moles + 4 moles
= 6 moles
= 7 moles
5.4 Combustion Calculations
Molar Evaluation of Combustion
MOLE-VOLUME RELATIONSHIP
Because a mole of every ideal gas occupies the same
volume, by Avogadro's law, the mole fraction of a
component in a mixture of ideal gases equals the
volume fraction of that component.
Moles of component Volume of component
Total moles Volume of mixture
This is a valuable concept because the volumetric
analysis of a gaseous mixture automatically gives
the mole fractions of the components.
Slide 5~] 1
5-8
-------
Molar calculations have a simple and direct application to gaseous fuels, where
the analyses usually reported on a volume percent basis. The mole fraction of a
component in a mixture is the number of moles of that component divided by the total
number of moles of all components in the mixture.
Consider the following fuel analysis:
(1)
Constituents
(2)
Vol. %
(3)
Moles
The fuel analysis may be expressed as 85.0 moles of CH4 per 100 moles of fuel,
12.5 moles of C2Hs per 100 moles of fuel, etc... as shown in Column 3.
The elemental breakdown of each constituent may also be expressed in moles
per 100 moles of fuel as follows:
C inCH4 = 85.0x1 = 85.0 moles
C in C2H6 = 12.5 x 2 = 25.0 moles
C in C02 = 0.2 x 1 = 0.2 moles
Total C per 100 moles of fuel
H2 in CH4 = 85.0 x 2
H2 in C2H6 = 12.5 x 3
Total H2 per 100 moles of fuel
02inC02 = 0.2x1
02 as O2 = 0.5 x 1
Total 02 per 100 moles of fuel
Total N2 per 100 moles of fuel
110.2 moles
170.0 moles
37.5 moles
207.5 moles
0.2 moles
0.5 moles
0.7 moles
1.8 moles
follows:
Therefore, the above fuel analysis may be written in term of elemental basis as
Element
C
H2
02
N2
moles/100 moles fuel
110.2
207.5
0.7
1.8
5-9
-------
The oxygen/air requirements and products of combustion can be calculated for
each constituent on an elemental analysis. Converting the gaseous constituents to
an elemental basis has two advantages. It provides a better understanding of the
combustion process and provides a means for determining the elemental fuel analysis
on a mass basis. This is boiler industry standard practice and is convenient for
determining a composite analysis when gaseous and solid/liquid fuels are fired in
combination.
CONVERTING FUEL ANALYSIS FROM VOLUME BASIS
TO MASS BASIS
(1)
Element
c
H2
02
N2
Total
(2)
Moles
100 Moles fuel
110.2
207.5
0.7
1.8
(3)
Jk_
Mole
12.01
2.02
32.00
28.01
(4)
ib
100 Moles fuel
1323.5
419.2
22.4
50.4
1815.5
(5)
_Jk_
lib fuel
0.73
0.23
0.12
0.28
(6)
ib
100 Ib fuel
72.9
23.1
1.2
_2£
100.0
Slide 5-12
Column 3 is the molecular weight of the elements.
Column 4 is determined by multiplying Column 2 by Column 3 to convert
moles to mass (Ib).
Column 5 is determined by dividing Ib of each element by the total Ib of fuel in
Column 4. For example for carbon C, 1323.5/1815.5 = 0.729, etc...
Column 6 is determined by simply multiplying the mass of each element in
column 5 by 100.
5-10
-------
Calculating Theoretical Air
The molar evaluation method is a useful tool in calculating air flows in
combustion processes. Assume a coal of the following analysis, calculate the
theoretical air (stoichiometric air) required to burn 100 Ibs of the coal.
THEORETICAL OXYGEN CALCULATIONS
(1)
Coal
Constit.
C
H
S
02
N2
H20
Ash
Total
(2)
%by
wt.
63.5
4.1
1.5
7.4
1.3
15.0
7.2
100.0
(3)
Mole. wt.
12
2
32
32
28
18
(4)
Moles
5.30
2.04
0.05
0.23
0.05
0.83
(5)
Comb.
Product
C02
H2O
S02
N2
H20
(6)
Moles theo.
O2 req.
5.30
1.02
0.05
-0.23
0.00
0.00
6.12
Slide 5-13
Number of moles of each element in Column 4 is determined by dividing each
mass by its respective molecular weight (Column 4 = Column 2/ Column 3).
Number of moles of theoretical 02 in Column 6 required to burn 100 Ib of fuel is
determined based on combustion equation of each element (see Slide 5-8).
The composition of dry air presented in Slide 5-3 shows that 100 moles of air
contains 20.95 moles of oxygen. Therefore, 6.12 moles of 02 correspond to 29.2 moles
of dry air (6.12*100/20.95).
Multiply the moles of air by its molecular weight to obtain mass of air required
to burn 100 Ib of fuel.
29.2 x 28.97 = 846.8 Ib dry air/100 Ib fuel.
(Note: 28.97 Ib/mole is the molecular weight of air).
5-11
-------
Calculating Excess Air
Use the above example, determine the actual air when the coal is burned with
23 percent excess air.
The actual air flow is determined by adding the excess air flow with the
theoretical air flow.
Excess air flow:
Actual air flow:
Calculating Percent Excess Air
846.8 x 0.23
846.8+ 194.8
= 194.8 Ib dry air/100 Ib fuel
= 1041.6 Ib dry air/100 Ib fuel.
In practice, the excess oxygen concentration in the flue gas is generally
monitored. The following method is applied to determine percent excess air from the
measured flue gas oxygen concentration and the elemental composition of the fuel.
CALCULATING PERCENT EXCESS AIR
O2
Excess Air, % = K x —m—yr—
ZL • \J2
Where:
O2 = Volume percent, dry oxygen in the flue gas
K =
100C + 237H + 37.5S + 9N - 29.60"
C + 3H + 3/8S - 3/80'
C = Mass fraction of carbon in the fuel
H = Mass fraction of hydrogen in the fuel
S = Mass fraction of sulfur in the fuel
0' = Mass fraction of oxygen in the fuel
N = Mass fraction of nitrogen in the fuel
(Note that these mass fractions should be given on a dry
weight percent basis; Ib/lb dry fuel.)
Slide 5-14
Using the fuel composition of Slide 5-13, and given flue gas oxygen
concentration of 3.25%, dry and applying the calculation procedure summarized in
Slide 5—14, the percent excess air can be determined as follows.
5-12
-------
Step 1: Converting fuel composition to dry basis.
(1)
Coal
Constit.
C
H
S
02
N2
H20
Ash
Total
(2)
%by
wt.
63.5
4.1
1.5
7.5
1.3
15.0
7.2
100.00
(3)
%by
Wt. dry
74.7
4.8
1.8
8.8
1.5
0.00
8.4
100.00
(4)
Ib/lbdry
coal
0.747
0.048
0.018
0.088
0.015
0.084
1.000
Column 3 is determined by each constituent composition to the total
subtracting moisture. For example, for carbon: 63.5/dOO - 15) = 74.7
Column 4 is determined by converting to 1 Ib total basis (Column 3 divided by
100).
Step 2: Calculating K
100(0.747) + 237(0.048) + 37.5(0.018) + 9(0.015) - 29.6(0.088)
K =
0.747 + 3(0.048) + 3/8(0.018) - 3/8(0.088)
= 97.5
Step 3: Calculating percent excess air
3.25
Excess air, % =97.5
(21-3.25)
= 17.9%
5-13
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5.5 Heat Transfer Fundamentals
Basic Modes of Heat Transfer
BASIC MODES OF HEAT TRANSFER
Conduction
Convection
Radiation
Slide 5-15
There are three basic modes of heat transfer: conduction, convection and
radiation. One or more of these modes controls the amount of heat transfer in all
applications.
Conduction: Conduction of heat is simply the heat transfer of energy due to a
temperature difference between adjacent molecules in a solid, liquid or gas. If one end
of a steel rod is inserted into a furnace, after a while the other end will become hot due
to heat conduction through the rod.
Convection: Heat is transferred between solids and fluids (gas or liquid) by a
process known as convection. This is really a combination of conduction and fluid
motion. For example, heat moves from the outside surface of a hot oven wall to the
adjacent air molecules by conduction, and then the air moves away carrying the heat
with it. The motion of the fluid (air in this case) may be due to the natural buoyancy
of the heated molecules (hot air rises) in which case the process is termed free or
natural convection, or the motion of the fluid may be mechanically produced (as by a
fan) in which case it is termed forced convection.
Radiation: Radiation is entirely different from the other two modes of heat
transfer. Light is a form of heat radiation, but all heat radiation is not necessarily
visible (light), for example, a person can feel the heat radiation from a furnace wall
and a hot piece of metal even though neither may be red. hot; that is, neither is
radiating light. Radiant heat travels in straight lines and may passes through a
vacuum air, some gases, some liquids, and a few solids such as glass or quartz.
5-14
-------
Heat Transfer Parameters
HEAT TRANSFER PARAMETERS
Heat Transfer Area
Temperature Difference
Conductivity
Diffusivity
Velocity and Turbulence
Relative Positions
Slide 5-16
Heat Transfer Area: The rate of heat flow from a heat source to a heat
absorber is proportional to the amount of area through which the heat may flow. For
example, the heat loss from a 20 ft2 furnace wall is twice as great as that from a 10
ft2 wall if all other factors are the same. The rate of heat transfer through a single
square foot of surface area, Btu/ ft2 hr, is called the heat flux.
Temperature Difference: In conduction and forced convection, the heat flow
rate is directly proportional to the temperature difference between the heat source
and the heat absorber. For example, the heat transfer from a bank of 150°F finned
heating coils to a 50°F air stream is only half as much as the heat transferred from
250°F coils to a 50°F air stream, if all other conditions are the same.
In cases involving radiation, temperature difference has a much greater
effect because heat flow is proportional to (Ts4 - Ta4) where Ts is the absolute
temperature of the source in degrees Rankine or Kelvin, and Ta is the absolute
temperature of the absorber, in the same units. Radiation heat transfer is intense at
high temperatures, usually overwhelming convection in the range where source or
receiving object is visibly radiant.
Conductivity: In conduction heat transfer, a property known as "thermal
conductivity" is used as a measure of a material's ability to conduct heat.
Conductivity is the rate of heat flow through a unit thickness when the temperature
difference across that thickness is one degree.
Diffusivity: The rate at which heat diffuses through a solid is called
diffusivity, which is conductivity divided by volume specific heat. Diffusivity is
expressed as n = k/cp, where k is thermal conductivity, c is specific heat and p is
density. Volume specific heat is defined as the quantity of heat required to raise a
unit mass of a material one degree in temperature at constant volume.
Velocity and Turbulence: In convection heat transfer, velocity and turbulence
have a significant effect upon the rate of heat transfer. A high velocity and a high
5-15
-------
degree of turbulence tend to scrub the heated molecules from a hot surface and
replace them with colder molecules, thus hastening the heat transfer process. The
fluid molecules closest to the solid surface are either stationary or moving very slowly
because of viscous friction; so they form a stagnant "film" or "boundary layer" across
which the heat must pass by conduction. Most fluids, especially gases and vapors
have very low conductivity; so the film constitutes the major resistance to heat flow.
The reciprocal of this resistance, called film coefficient, he, is a measure of convection
capability in convection heat flow:
Qc = he x Ax AT
Where Qc is convective heat transfer rate and A is area of the heat flow path.
Conductivity of the fluid film is a major factor—film coefficients for gases usually
range from 2 to 50 Btu/ft2 hr °F, whereas the range for liquids is often greater than
100. The next most important factor is film thickness, which is reduced by velocity
and turbulence. In turbulent flows, the film coefficient, and therefore the heat
transfer rate, varies depending on the geometry of the solid surface.
Nature of the surface affects convection heat transfer to a small degree
depending on its roughness. Radiation heat transfer; however, depends to a large
extent upon the emissiuity (ability to radiate) and absorptivity (ability to absorb
radiation) of the surfaces. Smooth shiny surfaces are poor emitters and absorbers of
radiation.; rough, corroded, dirty, and dark surfaces are good emitters and absorbers.
The best possible emitter and absorber of radiation is termed a black body (not
necessary black in color). Both the emissivity and absorptivity of black bodies are
1.0, and the emissivity and absorptivity of all other surface are less than this.
Relative Position: In radiation heat transfer, the relative positions of the
radiating and receiving surfaces affect the heat transfer rate, determining how well
one surface can "see" the other. The quantity measure of this ability is termed the
arrangement factor, Fa, which is the fraction of radiation from one of the surfaces
that falls upon the other. Thus, radiative heat flux can be expressed as:
qr = 0.1713 x 10-8 x (TS4 - Ta4) x Fe x Fa
Where Fe is the emissivity and Fa is the arrangement, and T in degrees
Rankine.
In natural convection heat transfer, the position of the surface also affects
the heat transfer rate. Generally speaking, positions which enhance the fluid motion
resulting from natural buoyancy have high heat transfer rates, whereas those
positions which tend to impair the natural fluid motion have low heat transfer rates.
5-16
-------
UNITS OF HEAT TRANSFER PARAMETERS
Parameter
Conduction heat flux rate
Conduction heat flux
Thermal Conductivity
Length of heat flow path
Area of heat flow path
Temperature difference
Diffusivity
Specific heat
Density
Film Coefficient
Symbol
Qk
qk
k
L
A
AT
T!
c
P
hc
English
Btu/hr
Btu/ft2 hr
Btu/ft hr °F
ft
ft2
°F
ft2/hr
Btu/lb °F
Ib/ft3
Btu/ft2 hr °F
SI
Watts
W/m2
W/mK
m
m2
K
m2/s
J/kgK
kg/m3
W/m2K
Slide 5-17
Slide 5-17 shows units of these heat transfer parameters in English and SI units.
5-17
-------
REFERENCES
1. North American Combustion Handbook, Vol. 1, 3rd Edition, North American
Manufacturing Company, 1986.
2. Koltz, J. C., Purcell, K. F., Chemistry and Chemical Reactivity, Saunders
College Publishing, New York, 1987.
3. Steam, Its Generation and Use, 40th Edition, Babcock and Wilcox Company,
1992.
4. Singer, J. G., Combustion: Fossil Power Systems, 3rd Edition, Combustion
Engineering, Inc., 1981.
5-18
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CHAPTER 6. AIR POLLUTION FUNDAMENTALS
6.1 Introduction
6.2 Fuel Dependent Air Pollutants
6.3 Combustion Dependent Air Pollutants
6.4 Smoke and Particulate
6.5 Gas Concentrations
A. Mole Fractions
B. Parts Per Million (ppm)
6.6 Emission Factors
A. Converting ppm to Ib/MMBtu
6.7 Correcting Concentrations
A. Correcting to 3% Oxygen
B. Correcting to 0% Oxygen
C. Correcting to 12% Carbon Dioxide
D. Converting [gr/dscf] to [mg/dscm]
6.8 Excess Air Calculation
6.9 Combustion Efficiency Calculation
6.10 Boiler Efficiency Calculations
A. Methods to Calculate Boiler Efficiency
B. Heat Loss Efficiency
C. Heat Input-Output Efficiency
D. Heat Rates
E. Heat Release Rates
Slide 6-1
-------
6. AIR POLLUTION FUNDAMENTALS
6.1
Introduction
Air pollution may be defined as any atmospheric condition in which substances
are present at concentrations which produce a measurable adverse effect on man,
animals, vegetation, or materials.7 The focus of this course is on those types of
substances which fossil-fuel fired boilers emit into the atmosphere which cause air
pollution. In this chapter, the types of pollutants emitted, and the related
measurement and performance calculations are discussed.
6.2
Fuel Dependent Air Pollutants
There are a number of different types of air pollutants which are emitted from
combustion sources. In general, their formation is dependent upon the composition of
the fuel, combustion quality, and temperature of the combustion mixture.
Fuel dependent air pollutants can be divided into three categories; acid gases,
toxics and hazardous materials, and carbon dioxide.
FUEL DEPENDENT AIR POLLUTANTS
Acid Gases
Sulfur Oxides
Nitrogen Oxides (Fuel NOX)
Toxics and Hazardous Materials
Lead
Mercury
Arsenic
Beryllium
Benzene
Radionuclides
Vinyl Chlorides
Carbon Dioxide
Slide 6-2
Fuel dependent air pollutant emissions generally can be controlled by either
changing the fuel property before combustion or by removing the pollutant from the
flue gas after combustion. For example, coal and oil typically contain sulfur in
varying amounts depending on the region of origin. During combustion, the elemental
sulfur in these fuels will form undesirable emissions of sulfur oxides (SOX). The
emission of SOX may be reduced by switching to a lower sulfur fuel or by stack gas
6-1
-------
cleaning through SOX control equipment, both of which are described in detail in
Chapter 26.
In addition, fossil fuels typically contain some nitrogenous compounds which
produce "fuel" nitrogen oxides (fuel NOX). Nitrogen oxides are also acid gases. Acid
gases create emission problems and tend to cause fire-side corrosion of the metal
heat exchanger surfaces.
Ash produced from the combustion of fossil fuels contains trace concentrations
of toxics and hazardous materials. These pollutants include arsenic, mercury,
benzene, beryllium, radionucleides and vinyl chlorides. Upon being heated during
combustion, mercury will tend to vaporize and react to form oxides or chlorides.
Other metals will vaporize, react or remain unchanged in the solid residue. By
lowering the temperature of the flue gas upstream of the APCD, many of the metal
vapors and compounds will condense on the fly ash and be removed by the APCD.
Carbon dioxide is not generally considered to be an air pollutant. It is a
naturally occurring compound which participates in the carbon cycle of organic
growth and decay. There is general agreement that carbon dioxide concentrations
have increased as a result of the combustion of fossil fuels. The global warming
theory suggests that this excess atmospheric carbon dioxide acts to decrease the
amount of heat energy radiated by the earth back to space. Therefore, it may
effectively trap radiant energy in the earth's atmosphere and potentially create
global warming.
6-2
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6.3
Combustion Dependent Air Pollutants
As discussed previously in Chapter 5, complete combustion is achieved by
mixing and burning the exact proportions of fuel and oxygen so that neither is left
over. If too much oxygen or excess air is supplied, the mixture is lean and the fire is
oxidizing. If too much fuel is supplied, the mixture is rich and the fire is reducing. This
condition is also called incomplete combustion since all of the fuel particles do not get
enough oxygen to burn completely.
A number of air pollutants, such as particulates, carbon monoxide, volatile
organic compounds, and nitrogen oxides, can be formed from incomplete combustion
of organic materials. The measurement of carbon monoxide is generally an indicator
of incomplete combustion since carbon monoxide will burn to carbon dioxide if
adequate oxygen is available. Correcting incomplete combustion may be
accomplished through providing more combustion air or by altering the mixing
characteristics between the fuel and the air.
COMBUSTION DEPENDENT AIR POLLUTANTS
Products of Incomplete Combustion (PIC)
Particulate
Carbon Monoxide
Volatile Organic Compounds (VOC)
Nitrogen Oxides
Slide 6-3
6.4
Smoke and Particulate
Air pollution is "visible" when smoke is emitted from a boiler. Smoke is a
mixture of gases, particles and droplets of liquid which have the effect of obscuring the
transmission of light (increasing opacity). The particles, which include solid and
condensed liquid materials, actually cause the opacity by scattering light. Opacity
meters are used to measure the emission of smoke. In most cases, the color of the
smoke may be an indication of the cause of the smoke.
Black smoke is flue gas which contains unburned carbon particles. Although
the major constituents of the particulate are inorganic materials, the unburned
carbon and carbonaceous materials are responsible for the black color. Improving
the combustion conditions will generally reduce the smoke emissions.
6-3
-------
SMOKE & PARTICULATE
Black Smoke
Carbon in Particulate
Particulate
Removed by APCDs
White Smoke
Condensed Hydrocarbon Gases
Ammonium Chloride
Water Droplets (Not Smoke)
Blue Smoke
Ammonium Sulfate
Brown Smoke
Nitrogen Oxides
Slide 6-4
White smoke can be formed by the condensation of unburned hydrocarbon
gases. It can also result from the reaction of ammonia with HC1 in the flue gas, which
forms ammonium chloride. Vapors often are condensed when cooled by the air,
forming small droplets which scatter light very well. Such smoke is visually detached
from the stack because a period of cooling is required for droplet formation.
Condensed water vapor, such as the emission from a scrubber stack, has the
appearance of white smoke. Such droplets will tend to re-vaporize after a fairly short
period of time in the atmosphere, unless the ambient relative humidity is very high.
Blue smoke can result from reactions of sulfur oxides with the ammonia or
urea used for NOX control. The reaction produces gaseous ammonium sulfate which
will condense in the atmosphere, so this smoke will appear as a detached plume.
Brown smoke can be caused by NOX emissions and/or particulate. Formation
and control of NOX emissions will be discussed in Chapters 21 and 25.
Particulate emissions are controlled by Air Pollution Control Devices (APCDs),
as will be discussed in Chapter 21. The very small particulates are the most difficult
to collect and are of most concern because they are able to pass into the lungs of
humans and become trapped there.
6-4
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6.5
Gas Concentrations
million.
Gas concentrations may be expressed in terms of mole fractions or parts per
GAS CONCENTRATIONS
Mole Fractions
Parts Per Million (ppm)
Slide 6-5
Mole Fractions
In Chapter 5, we considered complete combustion under stoichiometric and
excess air conditions. We now wish to consider gas concentrations, which may be
fractions of total molecules or mole fractions. The balanced chemical reaction
equation can be used to obtain ideal gas concentrations. A mole fraction for a gas can
be obtained by dividing the moles of the gas by the total moles in the mixture.
STOICHIOMETRIC
Ci.8sHs.402
Product
Gas
C02
H20
N2
S02
Total
OgN 02S.006+
1.85 CO
Wet Gas
Moles
1.85
3.92
8.15
0.01
13.93
1.22 H20+2.
2 + 3.92 H2O
Dry Gas
Moles
1.85
8.15
0.01
10.01
COMBUSTION
165O2+8.14
+ 8.15 N2 +
Dry Gas
Mole Frac.
0.185
0.814
0.001
1.000
N2-->
0.006 SO2
Dry Gas
Mole %
18.5
81.4
0.1
100.0
Slide 6-6
A complete combustion reaction equation for burning fossil fuels under
stoichiometric air conditions is presented in Slide 6-6. The product gases for this
6-5
-------
idealized condition are composed of 1.85 moles of CC>2, 3.92 moles of water vapor, 8.15
moles of N2, and 0.006 moles of 30%. If the water vapor is neglected, the product gas
analysis can be performed on a dry basis. Therefore, there will be 10.012 moles of dry
gas.
Parts Per Millions (ppm)
EQUIVALENCE OF GAS CONCENTRATIONS
Mole Fraction x 100 ~> Percentage
Mole Fraction x 1,000,000 --> ppm
Percentage x 10,000 --> ppm
Slide 6-7
Mole fractions are volume fractions. Such concentrations can be converted to
either mole percentages or parts-per-million (ppm or ppmv) by the simple
mathematics of moving the decimal point.
Literally, a percentage is a part-per-hundred, whereas a ppm is defined with
one million in the denominator instead of one hundred. A mole fraction can be
converted to a ppm basis by moving the decimal six places to the right. Conversions
from a percentage to a ppm basis involve four orders of magnitude or moving the
decimal four places to the right. Correspondingly, the 1 ppm is equivalent to 0.0001
percent, with the decimal going four places to the left.
Using the example of stoichiometric combustion shown in Slide 6-6, the dry
gas mole fraction of CC-2 is 1.85/10.012 = 0.185, which can be expressed as 18.5
percent. The mole fraction of SO2 in the dry product gases is 0.006/10.012 = 0.0006,
which can also be expressed as 0.06 percent or 600 ppm.
6-6
-------
6.6
Emission Factors
An emission factor is defined as the emission rate of pollutant per unit heat
input of fuel. NOX emission factor, NOX Ib/MMBtu, is the mass of NOX as NC>2 in
pounds divided by million gross Btu input of fuel. The NOX emission factor has been
used in the EPA's New Source Performance Standard (NSPS) (see Chapter 22) since
1971. It was selected by the EPA because it directly relates to the amount of fuel
fired, which is easier to monitor. Likewise, SO 2 emission factor is defined as the mass
of SC>2 in pounds divided by million gross Btu input of fuel.
Ibs NOx/MMbtu =
EMISSION FACTORS
Ibs of NX>2 emitted
Millions Gross Btu Fuel Input
,, o_. ,,»,»„, Ibs of SO2 emitted
Ibs S02/MMBtu =
Millions Gross Btu Fuel Input
Slide 6-8
Convertingppm to Ib/MMBtu
Since gas concentrations may be expressed in parts-per-million (ppm), a
necessary calculation to determine compliance with some regulations is to convert
ppm to Ib/MMBtu.
CONVERSION OF PPM TO LB/MMBTU
IbNOx/MMBtu = 1.19xl(HxFdxNOx(ppm@3%
O2, dry) x (21A21-3))
Ib S02/MMbtu = 1.69 x 10-7 x pd x SO2 (ppm @ 3%
O2, dry) x (217(21-3))
Where:
Fa is the dry F factor of fuel
Slide 6-9
The constants 1.194 x 10-7 and 1.69 x 10-7 are the conversion factors
from ppmv to Ib/scf (pounds per standard cubic foot) for NOX and SC>2,
respectively.
6-7
-------
NOX and SC>2 concentrations are in ppm at 3% O2, dry.
The factor (21A21-3)) is the conversion factor to correct concentration
to 0% O2 from 3% 02.
Fa is the dry F factor of fuel and varies depending on fuel types. Slide
6-10 shows average Fa value for various fuels.
AVERAGE Fd FACTOR FOR VARIOUS FUELS*
Coal:
Anthracite 10,100
Bituminous 9,780
Lignite 9,860
Oil:
(Crude, residual or distillate) 9,190
Gas:
Natural gas 8,710
Propane 8,710
Butane 8,710
Wood: 9,240
Wood Bark: 9,600
Slide 6-10
6.7
Correcting Concentrations
Gas concentration limits are expressed at standard dilutions in order to
prevent dilution from being a method for meeting the concentration requirements.
Emission standards used over the years have been referenced to different dilution
bases. The nitrogen oxide data for coal, gas and oil combustion are often presented
dry basis with 3% O2. In addition, both 0% O2 and 12% CO2 are sometimes required.
GAS CONCENTRATIONS AT STANDARD
DILUTION
3% O2, dry
or 0% O2, dry
or 12% CO2, dry
Slide 6-11
6-8
-------
Correcting to 3% Oxygen
As indicated in the slide below, gas concentrations can be corrected to 3%
oxygen by multiplying the measured concentration by (21 - 3) and dividing by (21 -
O2m). The variables with a subscript "m" are the measured dry gas concentrations.
If the available data is obtained from in-situ instruments, the values will be on a wet
basis. Corrections to a dry basis are made by dividing by (1.0 - moisture fraction).
EQUATION FOR CORRECTING TO 3% OXYGEN2
Assume: COm is the measured dry gas CO
Expressed as a ppm or %
Qzm is the measured dry gas O2
Expressed as a percentage
Converting:
CO (@ 3% O2)
= COmx(21-3)/(21-02m)
= C0mx (18)7(21-02m)
Slide 6-12
The derivation of the above gas concentration conversion equation is based on
theoretical gas mixture considerations, including the assumption that air is 21%
oxygen on a volumetric basis.
Correcting to 0% Oxygen
Similarly, gas concentrations can be corrected to 0% O2 by multiplying the
measured concentrations by 21 and dividing by 21-O2m-
EQUATION FOR CORRECTING TO 0% OXYGENi
Assume: C0m is the measured dry gas CO
Expressed as a ppm or %
O2m is the measured dry gas O2
Expressed as a percentage
Converting:
CO(@0%O2) = COmx (21 -
= COmx (21)7(21 -02m)
Slide 6-13
6-9
-------
To illustrate corrections of concentrations from the measured values to a
standard basis, let us consider the combustion of methane gas at 20% excess air as
presented in Slide 6-14. Note that for illustrative purposes, 0.001 moles of CO have
been arbitrarily added to the product gases.
PRODUCT GAS ANALYSIS,
METHANE @ 20% EXCESS AIR
Gas
C02
H20
02
N2
CO
Total
Wet Gas
Moles
1.0
2.0
0.4
9.024
0.001
12.425
Dry Gas
Moles
1.0
0.4
9.024
0.001
10.425
Dry Gas
Mole %
9.59
3.84
86.56
0.01
100.00
Slide 6-14
The flue gas analysis is illustrated above, with the oxygen content in the dry
gases being 0.4/10.425, 0.0384 or 3.84 percent on a dry gas basis. This is fairly
typical of operating numbers for commercial and industrial gas-fired equipment.
Let us now consider the incomplete combustion indicated in the above gas
analysis, with 100 ppm CO measured on a dry flue gas basis. Note that 100 ppm
corresponds to a mole fraction of 0.0001 or 0.01 percent. Therefore, the mole fraction
of CO is so small that it will not significantly change either the moles of oxygen or the
total moles in the mixture.
6-10
-------
The correction of the CO concentration to the standard dilution rate of 3% 0 2 is
a straightforward calculation. As shown below, the measured 100 ppm of carbon
monoxide became 104.9 ppm when corrected to 3% oxygen.
Let:
EXAMPLE FOR CONVERSION OF GAS
CONCENTRATIONS TO 3% OXYGEN
com
02m
100 ppm
3.84% (dry gas)
CO (@ 3% 02) =
COmx(21-3)/(21-02m)
100 x (18)7(21-3.84)
104.9 ppm
Slide 6-15
Particulate concentrations which are presented on a mass per unit volume
basis can be corrected by the same equation as before. Particulate loadings are a
case in point, regardless of whether they are measured in [gr/dscfj or [mg/dscm].
EXAMPLES FOR CONVERSION OF PARTICULATE
TO 3% OXYGEN
Let: PM
m
= 0.035 gr/dscf (Particulate Matter)
= 3.84% (Measured Dry Gas 02)
PM(@3%O2) = PMmx (21-3)7(21 -02m)
= 0.035 x( 18)7(2 1-3.84)
= 0.037 gr/dscf @ 3% O2
Slide 6-16
6-11
-------
Correcting to 12% Carbon Dioxide
EQUATION FOR CORRECTING TO 12% CO2i
Assume: C0m is the Measured Dry Gas CO
Expressed as a ppm or %
CO2m is the Measured Dry Gas CO2
Expressed as a Percentage
Converting:
CO (@ 12% CO2) = COm x (12/CO2m)
Slide 6-17
Gas concentrations (e.g., CO in the above slide) can also be corrected to 12%
C02 by multiplying the measured concentration by the ratio of 12% divided by the
measured percentage of CO2. As before, the variables with a subscript "m" are the
measured dry gas concentrations. If the gas concentration data were to be obtained
using in situ instruments, the values will be on a wet basis, so that corrections to a
dry basis would require dividing original concentrations by (1.0 - moisture fraction).
The derivation of the above conversion equation is based on theoretical mixture
considerations, including the assumption that the percentage of CO is much less than
the percentage of CO2, which is valid for most combustion product gas samples.
The logic of the equation is consistent with the fact that if the measured CO2
were less than 12%, the actual volume of mixture would be larger than that
corresponding to 12% CO2, so that the actual gas concentration would be less than
the standard concentration. Therefore, the gas concentration is adjusted by
multiplying by 12 divided by the measured percent of CO2.
6-12
-------
Consider the previous example of incomplete combustion with 100 ppm CO (or
0.01 percent) measured on a dry flue gas basis. The correction of the CO
concentration to the standard dilution of 12% CO2 yields 125 ppm of carbon monoxide
when corrected to 12% carbon dioxide.
Let:
EXAMPLE CORRECTION TO 12% CO2
COm = 100 ppm
C02m = 9.59% (dry gas)
CO(@12%CO2) =
C0mx(12/C02m)
100 x (12/9.59)
125 ppm
Slide 6-18
Converting [grldscf] to [mgldscm]
Many of the current regulations are in System International (SI) Units. For
example, the NSPS standard for metals is given in terms of particulate matter
measured in [mg/dscrn]. Other particulate standards are expressed in [gr/dscf] units,
where there are 7,000 grains in a pound. The abbreviation, dscf, refers to dry
standard cubic foot, and dscm refers to dry standard cubic meter. The term "dry"
refers to the flue gas without water vapor while the term "standard" refers to a
defined temperature and pressure (usually 60°F and 14.7 psi).
CONVERSION OF [gr/dscf] TO [mg/dscm]
Basic Identities:
1 pound [Ib] =
1 gram [g] =
1 foot [ft]
1 pound =
For Dry Gases at Standard Conditions:
1 dry standard cubic foot [dscf]
1 dry standard cubic meter [dscm]
1 dscf = 0.0283 dscm
So That:
454 grams [g]
1,000 milligrams [mg]
0.3048 meters [m]
7,000 grains [gr]
1 [gr/dscf]
Therefore:
1 [gr/dscf]
1 [gr/dscf] x (1 lb/7000 gr) x (454 g/lb)
x (1000 mg/g) x (1 dscf 0.0283 dscm)
2,290 [mg/dscm]
Slide 6-19
6-13
-------
The factor for converting expressions in units of [gr/dscf] to units of [mg/dscm]
is presented above. Conversion factors are developed using various identities and
simple multiplication and division. The theoretical basis for conversion factors
relates to the fact that the quantity obtained by dividing one side of an identity by the
other can be treated as unity. For example, an expression can be multiplied by
(1 lb/7000 gr) without changing its value.
EXAMPLE APPLICATION OF THE CONVERSION
FACTOR
Factor:
Given:
1 [gr/dscf] =
34 [mg/dscm]
2,290 [mg/dscm]
Therefore:
34 [mg/dscm] x (1 [gr/dscf]/2,290 [mg/dscm])
= 0.015 [gr/dscf]
Slide 6-20
The application of the conversion factor, 1 [gr/dscf] = 2,290 [mg/dscm], is
demonstrated in the above slide. The given particulate concentration of 34 [mg/dscm]
is shown to be equivalent to a concentration of 0.015 [gr/dscf]..
Note also, if it were desired to convert a given quanti ty expressed in [gr/dscf]
units into [mg/dscm] units, the quantity would need to be multiplied by
(2,290 [mg/dscm]/l [gr/dscf]).
6-14
-------
6.8
Excess Air Calculation
The average amount of excess air (EA) can be determined from a set of dry gas
measurements for carbon dioxide, carbon monoxide, and oxygen. The procedure
includes the assumption that the gas concentrations are expressed as a percentage
and that sulfur oxides, nitrogen oxides, and hydrogen chlorine are small enough to be
negle'cted. Therefore, the nitrogen in the dry product gas can be determined by
subtracting the measured percentages for carbon dioxide, carbon monoxide, and
oxygen from 100 percent.
DETERMINATION OF EXCESS AIR FROM DRY
GASANALYSISi
Assume:
Therefore:
And:
C0m
02m
N2m
EA
Percent Dry Gas C02
Percent Dry Gas CO
Percent Dry Gas O2
100 - (C02m + C0
m
(02m-0.5COm)/(.264N2m-02m
+ 0.5 C0m)
Slide 6-21
Next, the excess air (EA) expressed as a percentage can be found using the
equation in Slide 6-21, which is derived using theoretical considerations. 1 Note that
COm is included in the above equations. However, when CO is expressed on a
percentage basis, it generally has a trivial influence on the excess air calculation.
Let:
And:
EA
EA
EA
Therefore: N
EXAMPLE DETERMINING EXCESS AIR
9.59%
0.01%
3.84%
100-(C02m + COm + 02m)
100 -(9.59 + 0.01 + 3.84)
86.56
C0m
02m
2m
(02m - 0.5 COm)/(.264 N2m - 0^ + 0.5 COm)
(3.84 - 0.005)/(.264 x 86.56 - 3.84 + 0.005)
0.20 --> 20%
Slide 6-22
6-15
-------
The basic excess air calculation process is illustrated in Slide 6-22 using the
previous example of methane gas combustion. This calculation for excess air gives
the value of 20%. We know that this calculation is correct, since our original numbers
were based on 20% excess air.
6.9
Combustion Efficiency Calculation
EQUATION FOR COMBUSTION EFFICIENCY
(BASED ON CARBON COMBUSTION TO CO2)
= (100% x C02m) / (CO2m + COm)
or
C.E.(%)= 100%x(l-(COm/(C02m +C0m))
Slide 6-23
Many state regulations require a minimum combustion efficiency to avoid a
fine and mandatory shutdown. There are two equivalent forms of the combustion
efficiency equation, both of which are illustrated in the above slide. The equations are
often referred to as a carbon combustion efficiency, but they actually measure the
carbon monoxide combustion efficiency.
Let:
EXAMPLE COMBUSTION EFFICIENCY
CALCULATION
9.59 Percent
0.01 Percent (100 ppm)
(100% x C02m)/(CO2m + COm)
(100% x 9.59)7(9.59 + 0.01)
99.9%
Slide 6-24
C0
m
The above slide provides an example calculation of combustion efficiency.
Note that carbon monoxide is generally measured as ppm and will require conversion
to a percentage basis.
6-16
-------
6.10
Boiler Efficiency Calculations
Boiler efficiency (TJ) is defined as the ratio of energy output to input expressed
as a percentage. There are two methods to determine boiler efficiency: Heat Loss
method and Heat Input-Output method. Heat loss efficiency is determined by
subtracting all heat losses during combustion from the sum of heat in fuel and heat
credits. Heat input-output method is based upon the ratio of heat output, heat
absorbed by the working fluid or fluids, to the sum of heat in fuel and heat credits
METHODS TO DETERMINE BOILER EFFICIENCY
Heat Loss Method:
t}(%) = 100 - Net Heat Losses (%)
Heat Input-Output Method:
(%) = Output
Input
Heat absorbed by working fluid(s)
Heat in fuel + Heat credits
x 100
Slide 6-25
Heat Loss Efficiency
Net losses =
HEAT LOSS EFFICIENCY
Loss due to dry gases +
Loss due to moisture in the fuel +
Loss due to hydrogen in fuel +
Loss due to CO in flue gas +
Loss due to unburnt carbon +
Loss due to radiation +
Unaccounted losses
Efficiency = 100 - Net losses
Slide 6-26
Net heat losses during fossils fuel combustion include loss due to dry gases, loss
due to moisture in the air, loss due moisture in the fuel, loss due to hydrogen in fuel, loss
6-17
-------
due to unburnt carbon, loss due to radiation, and accounted losses. Boiler efficiency is
then determined by subtracting the net losses from 100%.
HEAT LOSS DUE TO DRY GASES
lb dry gas
HL due to dry gases =
lb fuel fired
X 0.24 (tg- ta)
Where:
0.24 = Specific heat of gas, Btu/lb °F
tg = Temperature of gas leaving unit, °F
ta = Temperature of air entering unit, °F
lb dry gas _ 11 C02 + 8 02 + 7 (N2 + CO)
lb fuel fired ~ 3(CO2 + CO)
lb C burned + g/g g
lb fuel fired
Cp2, 02, N2 and CO are in % by volume of flue gas
S is % by weight of sulfur in fuel
Slide 6-27
Heat loss due to dry gases represents the difference between the heat content
of the dry exhaust gases and the heat content that these gases would have at the
temperature of the ambient air. This loss usually is the largest loss of all.
LOSS DUE TO MOISTURE IN FUEL
HL due moisture in fuel =
Where:
H20 =
hg =
hi
100
x (hg - h,)
g
% moisture in fuel
Enthalpy of vapor at 1 psia and tg
Enthalpy of liquid at ta
Slide 6-28
Heat loss due to moisture in the fuel represents the difference in the heat
content of moisture in the exit gases and that at the ambient air.
6-18
-------
HEAT LOSS DUE TO HYDROGEN IN FUEL
9H2
HL due to H2 in fuel
100
x (hg - ha)
Where:
H2
% of hydrogen in fuel
Enthalpy of vapor at Ipsia and tg
Enthalpy of liquid at ta
Slide 6-29
Heat loss due to hydrogen in fuel represents the latent heat of moisture from
combustion of the hydrogen in the fuel.
HEAT LOSS DUE TO CO EM FLUE GAS
CO
HL due to CO in flue gas =
CO + CO2
IbC
x 10,160
Ibfuel
Where:
CO and CO2 are % by volume in flue gas
10,160 is Btu generated burning 1 Ib of CO to CO2
Slide 6-30
Heat loss due to CO in flue gas represents the loss due to incomplete
combustion of CO. This loss is usually small and dependent on the combustion
conditions in the unit.
HEAT LOSS DUE TO UNBURNED CARBON
Ib C in ash
HL due to unburned C =
Ib of fuel
x Btu per Ib of ash
Slide 6-31
Heat loss due to unburned carbon represents the thermal energy unliberated
due to the failure to completely oxidize the carbon content in the fuel. This carbon is
contained in the bottom ash and the fly ash.
6-19
-------
Calculations of each of the previously mentioned heat losses will give the
energy loss for each type of loss per pound of fuel. To determine the percent loss in
efficiency, divide each loss by the heating value of the fuel (Btu/lb).
% loss
Heat loss sum
Heating value of fuel
Heat loss due to radiation represents the heat loss to the air due to radiation.
This loss is very difficult to measure, and may be determined by using the American
Boiler Manufacturer Association's (ABMA) Standard Radiation Loss Chart, shown in
Figure 6-1.
Unaccounted losses include relatively minor losses such as sensible heat in ash
or slag, radiation to ash pit, moisture in air, heat pickup in cooling water, etc...
generally not measured because the effort is not justifiable. Typically a value of
about 1.5% is used for unaccounted losses.
Boiler efficiency is then equal to the sum of these losses subtracted from 100%.
Typical heat loss efficiency for coal-fired boilers ranges from 86 to 89%.
Heat Input-Output Efficiency
This method for calculating the boiler efficiency is based on the water-steam
side of the boiler. By using the energy content or enthalpy of the water entering the
boiler and the steam enthalpies and dividing by the total heat input from the fuel, the
efficiency is calculated as shown in Slide 6-32.
HEAT INPUT-OUTPUT EFFICIENCY
Heat I-O Efficiency =
W2(H2-h2)
x 100%
Where:
W2
Hi
H2
hi
h2
Main steam flow, Ib/hr
Reheat steam flow, Ib/hr
Enthalpy of main steam, Btu/lb
Enthalpy of reheat steam, Btu/lb
Enthalpy of feed water, Btu/lb
Enthalpy of steam entering
reheater, Btu/lb
Total heat input from fuel, Btu/hr
Slide 6-32
6-20
-------
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6-21
-------
Heat Rates
Heat rate of a utility boiler is defined as the ratio of boiler heat input from the
higher heating value of the fuel to electrical output, and is a measure of overall
generating unit efficiency including boiler combustion and steam turbine cycle. Heat
rate is an important measure of performance due to its direct relationship to the cost
of generating electricity.
HEAT RATES
Gross Heat Rate
Net Heat Rate
Slide 6-33
There are two types of heat rate: gross heat rate and net heat rate. Gross
heat rate is based on the total electrical power generated by the utility boiler. Net
heat rate is based on the total electrical power generated by the boiler subtracting
the power coming into the station and the auxiliary power used by the station.
HEAT RATE CALCULATIONS
Gross Heat Rate =
Heat input from fuel
Electrical output
Fuel flow x HHV
MW generated
= Btu/kWh
Slide 6-34
Gross heat rate is determined by multiplying fuel flow rate with the higher
heating value of the fuel and dividing by the MW generated. Heat rate is expressed as
Btu per kilowatt-hour (Btu/kWh).
EXAMPLE OF HEAT RATE CALCULATIONS
Let: Coal flow
Coal HHV =
Gross MW =
60,000 Ibs/hr
10,540 Btu/lb
55 MW
GHR =
60,000 x 10,500 1 MW
55 MW X 1000 kW
11,454 Btu/kWh
Slide 6-35
6-22
-------
Gross heat rate is calculated using the example shown in Slide 6-35. Net heat
rate can be calculated by the same method using net MW, which is equal to gross
MW subtracting power coming into the plant and auxiliary power used by the station.
Heat Release Rates
HEAT RELEASE RATES
Volumetric Heat Release rate
Burner Zone Heat Release Rate
Slide 6-36
Volumetric heat release rate is another important parameter related to boiler
calculations. It is defined as the total amount of heat introduced into the furnace by
the fuel divided by the total furnace volume. The total heat input is calculated based
upon the higher heating value of the fuel. The furnace volume is typically defined as
the furnace volume extending from the top of the hopper to the top of the furnace
section. Volumetric heat release rate is expressed as Btu/hr-ft3. Boiler
manufacturers use volumetric heat release rate in specifying boiler furnace sizes,
heat absorbing surfaces, flue gas temperatures, and selecting the fuels.
Burner zone heat release rate is another important boiler parameter. It is
defined as the total heat released by the fuel divided by surface area of the burner
zone, and is expressed as Btu/hr-ft2. This parameter has been used by boiler
manufacturers to relate to the formation and control of NOX. Figure 6-2 shows a
relationship between burner heat release rate and NOX emissions. Different boiler
manufacturers use different burner zone definitions. Some manufacturers define it
as the surface area extending from top burner row to the bottom burner row; some
extend the burner zone area four feet above and below the top and bottom burner
rows.
6-23
-------
CQ
2
1.2
1.0
0.6
0.2
50 100 150 200 250 300
Burner Zone Liberation Rate
(K^Btu/Hrft2)
350 400 450
Potter Wheeler Energy Corp
Combunion A Environmental Sytteim
Figure 6-2. Foster Wheeler boiler NOX correlation.
6-24
-------
REFERENCES
1. J. T. Beard, F. A. lachetta, and L. U. Lilleleht, APTI Course 427, Combustion
Evaluation, Student Manual, U.S. Environmental Protection Agency, EPA-
450/2-80-063, February 1980, pp. 5-4 to 5-21.
2. Babcock and Wilcox Company, Steam, Its Generation and Use, 40th Edition,
1992.
3 Singer, J. G., Combustion: Fossil Power Systems, 3rd edition, Combustion
Engineering, Inc., 1981.
4. Codes of Federal Regulations, Protection of Environment 40, Parts 53 to 60,
Office of the Federal Register National Archives and Records Administration,
July 1991, p. 1014.
5. Performance Test Codes Steam Generating Units, PTC 4.1, The American
Society of Mechanical Engineers, 1965.
6. Godish, Thad, Air Quality, Lewis Publishers, Inc., Chelsea, Michigan, 1991,
p. 123. -
7. Seinfeld, John H., Air Pollution Physical and Chemical Fundamentals,
McGraw-Hill Book Company, 1975, p. 1.
6-25
-------
7. NATURAL GAS FIRED BOILERS
7.1 Introduction
7.2 Fuel Supply System
7.3 Burner Arrangements
A. Burner Design
B. Burner Configuration
7.4 Boiler Design Parameters
7.5 Emissions
Slide 7-1
-------
7. NATURAL GAS FIRED BOILERS
7.1
Introduction
In steam generating equipment, the design of the equipment is dependent on
the type of fuel being fired in the unit. This Learning Unit is the first of seven which
address the design characteristics of steam generating units. The following discussion
will provide the fundamentals of natural gas supply systems and natural gas firing
equipment. In addition, a discussion of how the characteristics of burning natural gas
affect the boiler design and the environmental concerns during operation.
7.2
Fuel Supply System
Burning gaseous fuels is perhaps the most straightforward of all combustion
processes. No fuel preparation is necessary because gases are easily mixed with air
and the combustion reaction proceeds rapidly, once the ignition temperature is
reached. Of the many gaseous fuels, natural gas is the most important one for large-
scale stationary combustion installations. Pipeline natural gas is perhaps the closest
approach to an ideal fuel. It is virtually free of sulfur and solid residues, and it is the
cleanest burning of all fossil fuels.
For a natural gas fired boiler, the fuel system consists of supply line piping and
safety valves to provide the control and regulation of the gas supply to a boiler.
NATURAL GAS FUEL SYSTEM
Pressure regulator
Low gas-pressure switch
High gas-pressure switch
Manual plug shutoff valve
Solenoid Valve
Automatic main gas shut-off valve
Flow control valves
Slide 7-2
A pressure regulator controls the gas pressure that is delivered to the burner.
The actuator senses the pressure on the down-stream side of the regulator and
throttles the gas flow in order to maintain the downstream pressure at the desired
setting.
7-1
-------
A low gas-pressure switch is installed on the main gas line located downstream
of the main regulator. As long as the gas pressure from the main supply is
satisfactory, the switch remains closed. If the supply pressure drops, the low
pressure switch sends a signal to the actuator which closes the main fuel valve to the
burner or the burner row. The main fuel valve arrangement is a double block and
bleed valve arrangement whereby two block valves are in series and with a bleed
valve in-between which opens when the block valves are closed. This approach
provides two fuel block points and a pressure release between the two block points.
Each burner can be equipped with a double block and bleed valve arrangement, or
each row of burners. The low gas-pressure switch is also known as a vaporstat. The
location of this component is illustrated in Figure 7-3.
NATURAL GAS TRAIN CONFIGURATION
Low air
pressure switch
Automatic air control valve
Main air
Flexible connection
Vents above roof
Needle valve
for dampening
Gas
Main high
pressure-
reducing
regulator
ion
Relief
valve
Y
j
1 ^ N
( Atomizing air
N.O. vent
? valve
I/ Blocking
/5Ty shutoff
^^^ / valve
Pilot air
High Gas
Pr. Sw.
Metering orifices
3
Petcock
for leak test
of shutoff valves
Pilot high pressure- Pilot solenoid valve
Manual reducing regulator
shutoff valves
burner
Slide 7-3
7-2
-------
A high gas-pressure switch is installed in the main gas line after the pressure
regulator. If the pressure regulator should fail, which would result in high gas
pressure, the same sequence of events would occur as when the low pressure switch
actuates closure of the main fuel flow. In this case, the high gas-pressure switch
would send a signal to the actuator to close the main fuel valve. The main gas valve
is typically a manual plug shutoff cock, which is a ball valve or plug valve that may
be opened or closed by a 90° turn of a lever.
In the event of closure of the main gas line, which is usually called "high or low
fuel gas header pressure trip", there are a number of conditions that must be met
before a fire can be reintroduced into the furnace to prevent the possibility of an
explosion due to a fuel rich condition in the furnace. The main condition is that a
specified air flow is passed through the furnace to purge the furnace before
attempting light-off of the pilots and burners. The length of purge is boiler design
dependent.
Solenoid valves are used in the gas line to the pilot and are energized by a
electrical current. The automatic main gas shutoff valve is most commonly solenoid
actuated. When energized the main gas valve opens and as long as the control circuit
is energized the valve will be held open. If the circuit is opened by an interlock, such
as low water in the boiler, the power will be disconnected and the valve will shut.
The pilot ignites the main flame. A separate pressure control valve and an
automatic solenoid shutoff valve are provided for the pilot. A typical pilot is mounted
to shoot a long flame across the path of the incoming main fuel and air mixture. Once
the pilot flame has been established and the air flow through the burner has been
established, the main fuel valve is opened.
Flow control of natural gas may be based on measuring a pressure differential
across a valve or simply by the position of a butterfly valve. In many control
schemes, the fuel and air are controlled by a gas/air ratio regulator which maintains
the proper air flow based on the fuel flow. A schematic of this type of control system
is shown in Slide 7-3.
A flame scanner is used to monitor the burner flame for safety control. During
start-up, fuel explosion is a potential hazard. Thus, detection of the presence of flame
to verify ignition is a requirement for continued operation in burner safety systems.
Flame is an electromagnetic phenomenon. It contains ionized particles, components
of infrared radiation caused by heat, visible radiation, and ultraviolet radiation. By
applying these characteristics, four types of devices have been developed to detect
the presence of flame: flame rods, photoelectric sensors, infrared radiation sensors,
and ultraviolet sensors.
7-3
-------
7.3 Burner Arrangements
The function of a gas burner is to deliver fuel and air in a desired ratio to the
combustion chamber and to provide mixing and ignition of the combustible mixture.
The performance of a given boiler depends on the burner design and the number and
configuration of the burners.
Burner Design
The burner design, which determines the relative velocities of the fuel and air
streams, impacts the flame shape, flame stability, and combustion zone required. In
regards to the latter, rapid mixing, with a high degree of turbulence, is likely to create
a short "bushy" flame, while delayed mixing and low velocities result in long and more
slender flames. The shape of the flame will depend on the mixture pressure and the
amount of primary air. For a given burner, increasing mixture pressure will broaden
the flame, increased primary air will shorten it. The flame characteristics vary
among the various burner designs and are dependent primarily on gas orifice size,
design and orientation.
There are two principal mechanisms of flame combustion producing flames of
quite different appearance: blue flame and yellow flame. Blue flame results when
gaseous fuel is mixed with air prior to ignition. In this instance, hydrocarbon
molecules are oxidized gradually in stages passing through to the end products of
carbon dioxide and water. Incomplete combustion results in the emission of the
intermediate partially oxidized compounds. However, no soot is developed.
Yellow flame results when the fuel and air enter the combustion zone
separately - without having been intimately mixed prior to ignition. The hydrocarbon
molecules decompose to form solid carbon particles and hydrogen when exposed to the
high furnace temperatures before they have had an opportunity to combine with
oxygen. The carbon particles are incandescent at the elevated temperatures and give
the flame a yellowish appearance. Eventually sufficient oxygen will diffuse into the
flame to form carbon dioxide and water. Insufficient oxygen or incomplete
combustion due to flame quenching will result in soot and black smoke.
7-4
-------
Flame stability is very important for safe, reliable operation. A stable burner
maintains ignition throughout the range of pressures, input rates, and fuel/air ratios
encountered during operating conditions. Stability is achieved by maintaining
minimum ignition temperature for the given mixture of fuel and air, and holding the
flame in close proximity to the burner nose. Stability may be enhanced by the bluff
bodies (step, diffuser plate or ledge), jet tubes, or stage air entry, as illustrated in
Slide 7-4. All of these create interfaces between streams of different velocities,
producing small scale turbulence. Another mechanism for improving flame stability
is swirl, which recirculates the products of combustion into the base of the flame and
therefore broadens the range of velocities in which flame stabilization is possible.
BURNER DESIGNS FOR FLAME STABILITYi
GM
STAGED
AIR ENTRY
Air
LEDGE
/(fuel-rich)
OM—
U
JET TUBES
Slide 7-
7-5
-------
The range of input rates within which a burner will operate is specified by the
burner turndown ratio. This is the ratio of the maximum to minimum heat input
rates with which the burner will operate satisfactorily.
The burner design is critical in determining the mixing between the fuel and air.
Three common gas burner designs include the ring-type, gun-type, and spud type
burners.
The ring-type burner, illustrated in Slide 7-5, is common for high-pressure gas
burner applications. The normal gas pressure operating range is from approximately
1 to 10 psig. As the air passes through the air registers the velocity is increased and
a swirl is imparted to the air, which then is forced toward the burner centerline or
throat. The gas enters from the small holes shown on the inside of the hollow gas ring
and is injected perpendicular to the air stream. Although this burner can maintain a
stable flame at low pressures, the relatively small gas orifices tend to become plugged
with dirt or other substances. When this happens the boiler must be shut down and
the burners cleaned.
RING-TYPE GAS BURNER
Section A - A1
Lever for
opening air
registers
O
Gas inlet
Opening
for oil burner^
Gas piping
Burner
air registers
Slide 7-5
7-6
-------
A gun-type gas burner is shown in Slide 7-6. In this burner the air register is
similar to that of the ring burner, and functions to impart a swirl to the flow of
combustion air. The gas, however, is injected into the air stream from the center
instead of the outer periphery. Because space is more limited on the tip of the
smaller diameter gun, the gas orifices are large and fewer in number than on the ring
burner. An advantage of this burner over the ring burner is that the gas orifices are
large and need less cleaning. When properly adjusted, gun-type burners can be
operated at pressures in excess of 20 psig and with a minimum pressure stable flame
at approximately 1 psig.
GUN-TYPE GAS BURNER
Air registers
Opening for
oil gun
Burner gun
tip
Gas
openings
Gas inlet
Windbox
Windbox
casing
Furnace wall
Slide 7-6
7-7
-------
The third type of burner, the spud-type burner, has an external gas ring with a
number of smaller gas guns or spuds connected to the ring. This burner is a design
that obtains the benefits of both the ring and the gun type burners. The gas orifices
are greater in number and smaller for better dispersal of the gas into the gas stream.
SPUD-TYPE GAS BURNER
Gas
distribution ring
Center hole for
oil burners *
Windbox casing
Air registers
1 Air flow
Windbox
Slide 7-7
The gas burners which have been discussed to this point are categorized as
nozzle-mix or delayed mix burners in which the fuel and air do not mix until they reach
the burner chamber. Another type of gas burner, the premix burner, mixes the
primary air and fuel at some point upstream from the burner ports. The most
common premix burners are manifold burners used in low temperature processes
which require heat spread uniformly over a wide area. Processes such as drying
ovens, baking ovens use premix manifold burners.
7-8
-------
Burner Configurations
In addition to the different burner designs, the number and configuration of the
burners in the furnace will determine the overall performance of the boiler. For gas
fired boilers, there are basically three different burner locations. The first and most
straight forward is the front wall location. The second is the opposed wall firing
configuration.
WALL MOUNTED BURNER CONFIGURATIONS
Front Wall Firincr Oooosed Wall Firine
Slide 7- 8
7-9
-------
For both configurations, there are multiple patterns in which the burner
spacing and location may vary based on each boiler and burner manufacturer's
requirements.
o
MULTIPLE BURNER PATTERNS
•
0
0
o
0 x
*&
•
o
0
Qs
,*xo
0
1 \
1 •
1 o
I °
1 O
*^^Q
o
0
^
o
*%
%v
0
^
/
0
0
0*
OPPOSED FIRED
CORNER FIRED
Slide 7-9
7-10
-------
TANGENTIAL FIRING BURNER LOCATIONS*
Jj Secondary-
^ Air Damper
IL
Primary-Air
Damper
Secondary-
Air Damper
JL.
Slide 7-10
The third gas burner configuration that is in use today is corner firing or
tangentially firing. Although this configuration is more commonly used in coal and oil
firing boilers, the conversion to cleaner burning fuels has forced some utilities to
modify the boilers to gas burning only or in combination with the coal and/or oil.
7-11
-------
7.4 Boiler Design Parameters
There are numerous boiler design parameters which contribute combustion
control and efficiency. The predominant parameters include burner zone heat release
area, burner spacing, and windbox configurations.
The burner zone heat release area determines how rapidly the fuel-rich
combustion gases radiate heat to the furnace walls and the degree of combustion
product recirculation into the primary combustion zone. Data collected on numerous
utility boilers have indicated that the heat release rate per furnace volume is an
important factor in determining minimum NOX emission levels from a given boiler.
Burner spacing determines the location of combustion within the furnace, as
well as the degree of quenching of the combustion gases by cooler gases at the wall of
the boiler. If sufficient heat is lost before air from the burners mixes with the fuel-rich
combustion gases, the production of NOX, the primary pollutant of concern when
burning natural gas, will be significantly reduced due to the strong temperature
dependence of the NOX formation. With extremely close spacing the secondary
combustion takes place before the fuel-rich gases have lost sufficient heat to be near
the NOX formation threshold. The quenching effect with close spacing is also
minimized due to flame interaction. At the other extreme, with large spacing, the
NOX level may be limited by excessive CO in the combustion gases. The excessive
CO is due to poor mixing with the secondary air. More details on NOX formation and
control techniques is provided in Chapter 25.
Redistribution of combustion due to burner spacing produces variations in the
heat transfer occurring in the furnace. If there is increased heat transfer in the
convective pass, this condition can usually be controlled by existing superheat/reheat
proportioning dampers, or by spray attemperation. If the increases in temperatures
are not compatible with metal temperatures or steam turbine operation, the
situation may necessitate removal of convective heat transfer surface, or result in an
increase of the water or steam attemperation (desuperheater) capacity.
The windbox design controls the air distribution. Inadequate windbox design
may create restrictions in the air flow to one or more burners, thus limiting the extent
of overall fuel-rich burner operation because of non-uniform air distribution. To help
promote uniform air distribution, existing windbox designs may be modified by
incorporating vanes or minimizing restrictions. In some cases, air register
adjustments may drastically affect the individual burner flame holding
characteristics and consequently cannot be varied without awareness of the overall
impact on the boiler operation.
The furnace volume is an important parameter since it determines the space
available for mixing and secondary combustion as shown in Slide 7-11.
7-12
-------
FURNACE VOLUME EFFECTS
UNIT
.DESIGN
PARAMETER
HIGH
HEAT RELEASE RATE
LOW/MEDIUM
HEAT RELEASE RATE
FURNACE
ELEVATION
(SAME MW SEE UNTO
BURNERZONE
VOLUME
(3 X Bner Sfadat) X Width X Depth
1.66 X fl£«i HRR Volume)
BURNERZONE
HEAT RELEASE
RATE
88,000 BTU/Hr/Ft3
53,000 BTU/Hr/Fl3
NOx @ MCR
GAS FIRING*
- LOW EXCESS
AIR BURNER
0.55 Lb/Mfflion BTU
0.22Lb/MillionBTU
Slide 7- 11
7-13
-------
7.5
Emissions
Natural gas is the cleanest burning fossil fuel. The criteria pollutants of
concern which are emitted from natural gas fired boilers include NOX, CO, and
hydrocarbons. Sulfur oxides are not a primary concern due to the lack of sulfur
content in the natural gas. Since natural gas is usually provided via a pipeline, no
environmental concerns result from the storage of this fuel.
In a recent study completed by the EPA, the following range of emissions were
measured and documented for industrial boilers.
UNCONTROLLED EMISSION DATA FROM
NATURAL GAS-FIRED BOILERS*
Boiler Type and
Capacity
< 100 MMBtu/hr
> 100 MMBtu/hr
NOX,
Ib/MMBtua
0.03 to 0.31
0.04 to 0.45
CO,
Ib/MMBtu*
0.0 to 1.45
0.0 to 0.23
THC,
Ib/MMBtu*
0.0 to 0.02
0.0 to 0.05
To convert to ppm @ 3% 02, multiply by the following: NOX) 835; CO,
1,370; THC, 2,400
Slide 7-12
7-14
-------
REFERENCES
1. North American Combustion Handbook, Second Edition, North American
Manufacturing Company, 1978.
2. Wilson, R. Dean, Boiler Operator's Workbook, American Technical Publishers,
Inc., 1991.
3. Price, Joyce V., et al., "Low NOX Oil/Gas Burner Retrofits and Their Effects on
Overall Emissions and Boiler Performance," May, 1993 EPA/EPRI Joint
Symposium on Stationary Combustion NOX Control.
4. Singer, J. G., Combustion: Fossil Power Systems, 3rd Edition, Combustion
Engineering, Inc., 1981.
5. "Alternative Control Techniques Document -- NOX Emissions from Industrial/
Commercial/Institutional (ICI) Boilers", U.S. EPA, EPA-453 / R-94-022,
March, 1994.
6. Elliot, C.T., Standard Handbook of Power plant Engineering, McGraw-Hill
Publishing Company, New York, 1989.
7-15
-------
CHAPTER 8. OIL FIRED BOILERS
8.1 Introduction
8.2 Fuel Supply System
A. Atomization
B. Operation
8.3 Burner Arrangements
8.4 Boiler Design Parameters
8.5 Emissions
Slide 8-1
-------
8. OIL FIRED BOILERS
8.1
Introduction
As with the discussion on natural gas fired boilers presented in the previous
learning unit, the oil fired boiler system operation depends on a consistent fuel supply
system, burner design which provides flame stability over a wide range of operating
conditions, and the boiler chamber design to deliver the desired steam to the end user.
The properties of fuel oil dictate that the design of each of these subsystems vary
considerably from the simple designs used for natural gas fired boilers. The following
sections present the specific design and operating parameters for each of these
subsystems.
8.2
Fuel Supply System
In comparison to gas fired boilers, oil fired boilers have a more complicated fuel
delivery system. For efficient combustion, the fuel system needs to supply clean oil
at the required volume, pressure, and viscosity. A fuel oil system therefore conditions
the fuel oil prior to delivery to the boiler burners. The conditioning starts at the fuel oil
tank which provides storage and heating if required.
FUEL OIL SUPPLY SYSTEM COMPONENTS
Fuel Oil Tank
Oil Pressure Regulator with bypass
Oil Heater
Oil Heater Relief Valve
Fuel Oil Strainers
Pump
Pump Discharge Relief Valve
Atomizing Gun
Slide 8-2
The fuel oil tank stores fuel oil. The storage tank needs to be sized based on
method of oil delivery, rate of fuel consumption, and the frequency of oil deliveries and
contingency for delivery delays and fuel shortages. Depending on the size of the plant,
multiple tanks may be used. Fuel oil tanks are often buried to minimize space
requirements, avoid freezing, and increase safety. However, corrosion and
deterioration of buried fuel oil tanks must be monitored by using sample wells located
around the tank. For tanks installed above ground, concrete containment areas must
be constructed to prevent environmental or safety hazards in the event of a spill. A
vent line is provided to vent the tank while filling.
8-1
-------
Fuel oil heaters are required to reduce the resistance of the oil to flowing when
heavier grades of fuel oil are used. Fuel oil heaters supply heat to the oil by steam or
by electricity. A steam heater may consist of a steam chamber or shell with tubes
through which the oil flows. An electric heater consists of a chamber for the fuel oil
with one or more heating elements inserted into the chamber. Both of these types of
heating systems are shown in Slide 8-3.
FUEL OIL TANK AND TANK HEATERSi
FILL LINE
VENT LINE
MEASUREMENT WELL CONNECTION
PNEUMERICATOR CONNECTION
RETURN LINE
LOW SUCTION LINE
HIGH SUCTION LINE
TANK
HEATING
ELEMENT
FUEL OIL
OUTLET
FUEL OIL
INLET
CONDENSATE OUTLET
STEAM INLET
TEMPERATURE
ADJUSTING
SCREW
SHELL-AND-TUBE
ELECTRIC
HEATERS
Slide 8-3
8-2
-------
The National Fire Protection Association (NFPA) has prepared a standard set
of rules for the storage and handling of oils. These rules serve as a basis for many
local ordinances and form a practival guide for the safe transportation and handling of
fuel products. In some states, regulations require that a storage tank can only hold
oil to a certain tank capacity to avoid overflows. Oil tanks must be inspected
regularly to ensure no leakages.
From the fuel oil tank, the fuel oil is circulated to the burner via the fuel oil
pump. The fuel oil pumps used for supplying fuel oil to boiler burners are usually
positive displacement pumps. The fuel pump supplies more fuel oil than is used by
the burners. The excess fuel oil is returned either to the suction side of the pump or to
the storage tank by a pressure relief valve installed in the discharge piping. This
valve maintains a constant fuel oil supply pressure to the burners and prevents
excessive pressure buildup in the piping. Fuel oil strainers remove impurities such as
sand, dirt, and rust. Strainers are usually located on the suction and discharge side of
the pump.
FUEL OIL SYSTEM PIPING2
Gauge
Relief valve
To other burner zone*
Air bleed
Fill
Manual shutoff valve
Check valve Strainer
\_—
Pump—
Drain
Pressure regulator
Strainer.
-Air bleed !
Limiting valve Burner
jip
\
c
e
p
l^j i -^
Vent
"^ /Ground line
/Oil storage tan
Air/Oil ratio regulator
Auto (MR) shutoff valve
Oil train-
Slide 8-4
8-3
-------
Atomization
Once the oil is supplied to the burner, the fuel oil is dispersed into a mist of
droplets by atomization. The purpose of atomizing the fuel is to increase the fuel oil
surface area and therefore increase the exposure of the fuel to the oxygen in the
combustion air. By quickly and efficiently mixing the oxygen and fuel, complete
combustion of the fuel oil is promoted. The atomization of oil is accomplished by the
oil gun. An oil gun atomizes, or breaks up, the oil into small droplets and then
disperses the droplets. The atomization process can be achieved by three common
methods: steam, air, and mechanical atomization.
Steam and air atomization are closely related, the same gun often being
adaptable to both uses. For these types, oil droplet sizes are controlled by the
pressure differential between the atomizing fluid (steam or air) pressure and the oil
pressure. Higher pressure differential would result in smaller oil droplet sizes.
Therefore, desired droplet sizes, and hence the burner combustion characteristics,
can be controlled by controlling this pressure differential.
For large boilers, air atomization is seldom used because of the high operating
cost of pumping large quantities of air. In package boilers, however, air atomization
is popular. Air atomization of light oils produces good results. Turndown is somewhat
more limited than with steam atomization due to the relatively low compressed air
pressures usually available. There are three basic types of steam/air atomizers: T-
Jet, Y-Jet, and Rotary.
For a T- Jet design, oil flows down the central tube and turns radially outward
to impinge on the axially flowing steam through the outer tube. Steam pressure is
maintained 20 psi above oil pressure up to a maximum steam pressure of about 100
psig. The density of the oil is roughly two hundred times that of the steam. At the "T"
junction where the two streams mix the steam is moving at several hundreds of feet
per second, with the oil velocity is several tens of feet per second.
T-JET STEAM ATOMIZERi
STEAM
FUEL OIL AND
STEAM MIXTURE
.Slide S -5
8-4
-------
The Y- Jet type of steam atomizer, with the oil entering the high velocity
steam passage at an acute angle is illustrated in Slide 8- 6. Steam pressure is held
constant and the variation of oil flow is adjusted by the oil pressure. This same design
may be adapted to air atomization. The quality of atomization is consistently good
over the range of oil flow for this design.
Y-JET STEAM/AIR ATOMIZER!
SECONDARY AIR
SLOTTED
PRIMARY
ATOMIZING AIR
FUEL OIL
TIP
SPRAY
Slide 8-6
A rotary cup burner has a cone-shaped cup that mixes fuel oil with air, as
shown below. The rotating cup is mounted on the end of the hollow blower shaft. Fuel
oil is delivered to the inside of the rotary cup burner through the hollow shaft. Fuel oil
is thrown to the wall of the rotating cup by centrifugal force and air from the blower
mixes with the fuel oil as it sprays off the end of the rotary cup burner. The burning
rate is determined by the fuel feed rate.
ROTARY CUP ATOMIZERi
AIR IN
HOLLOW SHAFT
(FUEL TUBE)
ATOMIZED
FUEL OIL
IGNITES
MOTOR -I
AIR IN
PRIMARY AIR FAN
SPINNING
CUP
Slide 8-7
8-5
-------
Mechanical atomization of both light and heavy oils is available, but fuel
pressure requirements are much higher than for steam or air atomization.
Mechanical atomization is generally not recommended for single-burner applications
because of the limited turndown. Straight mechanical atomization is the simplest oil
firing system. It requires only a fuel supply line to each burner and the firing rate is
altered by adjusting the oil supply pressure. Wide-range mechanical atomization
requires both fuel supply and return lines at each burner. For the constant
differential pressure system, a separate pump maintains a constant pressure
differential between supply and return. Firing rate is adjusted using a fuel supply
valve upstream of the constant-differential pump. For the constant supply pressure
system, the supply pressure is constant over the complete operating range of the
burner and the firing rate is adjusted by throttling the return line.
MECHANICAL ATOMIZERi
FUEL OIL
RETURN
TO SUPPLY
TIP
SPRAYER
PLATE
HIGH-PRESSURE
FUEL OIL FLOWS
TO TIP
SPRAY
Slide 8-8
Operation
A few common problems to oil handling systems include air in oil lines, dripping
of oil, oil expansion, and clinker. The effect of air in the oil lines may result in poor
control, irregular burning, and limited capacity. Removal of air from a system is best
accomplished in a recirculating system where both the air and fuel return to the fuel
tank. In other systems, manual air bleed valves should be installed at high points
and opened when a problem is determined. Fuel oil dripping through the burners may
cause an accumulation of carbon sooting the burner nozzles or on the surrounding
burner surfaces. To prevent buildup, the holes in the burner tip should be cleaned out
on a regular basis. Oil expansion may cause damage to gauges, regulators and other
apparatus. After a burner is shut off, heat from the furnace causes the remaining oil
in the pipes to expand against the pipe wall. Accumulators should be installed to take
up the oil expansion and checked periodically for normal operation. In some cases,
the carbon buildup at the fuel nozzles becomes so severe that some clinkers are
formed and plug up a portion of the tips. This may result in inadequate oil
atomization and hence affecting the flame characteristics.
8-6
-------
8.3
Burner Arrangements
Burners for gas and oil firing function very much the same. In many cases, the
capability to burn both fuels is incorporated into one burner assembly. These
burners are known as dual fuel burners which introduce either fuel and the required
air into the furnace for the combustion process. The figure in Slide 8-9 shows a cross
sectional view of a typical gas and oil firing circular burner assembly manufactured
by Peabody Engineering Corporation (PEC). This particular burner has a gas ring
burner with an oil atomizing gun located in the center of the ring. The atomizing gun
is fitted with a diffuser to stabilize the oil flame. The air is supplied to the burners via
a forced draft fan. The air is metered to the burner by the air register doors. The air
register also provides the turbulence necessary to mix the fuel and air and produce
short, compact flames.
DUAL FUEL BURNER CROSS SECTION
Ul VOIOJ IN MtAIOIMO
riU HCKEOWITHHAITIC
flUUICI WTWHX) TIUCS §e«T«HOU«o'i
Peabody Engineering Corporation (Type H Forced Draft Ring Gas &/or Oil Fired)
Slide 8-9
8-7
-------
The fuel oil is introduced to the burner via the oil atomizer (oil gun), in a fairly
dense mixture in the center. The direction and velocity of the air, plus dispersion of
the fuel, provides the mixing of air and fuel required for combustion. The oil atomizer
disperses the oil fuel into the furnace as a fine mist. This exposes a large amount of
oil particle surface in contact with the combustion air to assure rapid oil vaporization,
prompt ignition and rapid combustion. If the atomizer is located too far forward in the
furnace, the flame may whip around the diffuser. If the atomizer is withdrawn too
far, spray will strike the burner throat and buildup carbon arid the flame will tend to
flutter. Once the oil gun position and the air registers are set properly no further
adjustments are normally required during operation.
Similar to the gas burners, the common oil burner configurations are front wall
fired, opposed fired, and tangential or cornered fired. Likewise, multiple and singular
burner arrangements are commonly used.
8.4 Boiler Design Parameters
Oil firing requires a larger furnace area than for natural gas firing primarily due
to higher heat absorption. The rapid burning and high radiation heat transfer rate
from oil firing results in high heat absorption rates in the active burning zone of the
furnace. The furnace size must therefore be increased for complete combustion and
to avoid excessive furnace-wall metal temperatures. However, oil does not require as
large a furnace as coal to achieve complete combustion.
The operation of a boiler on oil continuously for several weeks results in a build
up of a very thin deposit on the waterwalls. This deposit is thermally insulating. The
insulation is usually too insignificant to cause any deterioration in performance.
8.5 Emissions
The emissions of interest from fuel oil fired boilers include sulfur oxides,
nitrogen oxides, carbon monoxide, and opacity. Sulfur oxide emissions are dependent
on the sulfur content of the fuel. For most cases, almost all the sulfur in the fuel is
converted to SO2 with a small fraction converted to SOa. Until recently, limits in
maximum sulfur content in fuel oils were set by ASTM and customer specifications.
But, the maximum limit now is dictated by regulations, which vary considerably in
different localities.
Likewise, NOX emission from oil fired boilers are related to fuel nitrogen
content. Other fuel properties, such as oil atomization, carbon burnout, and excess
oxygen minimization affect NOX emissions.
Carbon monoxide (CO) is measured to provide a measurement of the
combustion process. If CO increases, the amount of combustion air usually needs to
be increased.
8-8
-------
The opacity when burning fuel oil is usually greater than when the same unit is
operated on natural gas. The visible smoke coming from the stack indicates the
efficiency of the combustion process. If the smoke from the stack is a light brown,
the oxygen level is too low. A heavy white smoke leaving the stack indicates the too
much air is available in the combustion process while black smoke indicate
incomplete combustion. Under complete combustion conditions, there will be no
visible smoke.
A survey of a wide range of oil-fired boilers burning distilled and residual fuel oils
was conducted by the EPA. A summary of the emission ranges for NOX, CO and total
hydrocarbon (THC) is given in Slide 8-10.
UNCONTROLLED EMISSIONS DATA FOR
OIL-FIRED BOILERS5
Oil Type and
Boiler Capacity
Residual Oil:
NOX>
lb/MMBTUa
Watertube Units:
10 to 100 MMBtu/hr 0.20 to 0.79
> 100 MMBtu/hr 0.31 to 0.60
Distillate Oil:
Watertube Units:
10 to 100 MMBtu/hr 0.08 to 0.16
>100 MMBtu/hr 0.18 to 0.23
CO,
Ib/MMBtu*
0.0 to 0.11
0.0 to 0.07
0.0 to 1.18
0.0 to 0.84
THC,
Ib/MMBtu*
0.0 to 0.03
0.002 to 0.02
0.0 to 0.003
0.001 to 0.009
aTo convert to ppm @ 3% 02, multiply by the following: NOX, 790;
CO, 1,300; THC, 2,270
Slide 8-10
8-9
-------
REFERENCES
1. Wilson, R. Dean, Boiler Operator's Workbook, American Technical Publishers,
Inc., 1991.
2. North American Combustion Handbook, Second Edition, North American
Manufacturing Company, 1978.
3. Singer, J. G., Combustion: Fossil Power Systems, 3rd Edition, Combustion
Engineering, Inc., 1981.
4. Price, Joyce V., et al., "Low NOT Oil/Gas Burner Retrofits and Their Effects on
Overall Emissions and Boiler Performance," May, 1993 EPA/EPRI Joint
Symposium on Stationary Combustion NOX Control.
5. "Alternative Control Techniques Document — NOx Emissions from
Industrial/Commercial/Institutional (ICI) Boilers", U.S. EPA, EPA-453 /
R-94-022, March, 1994.
8-10
-------
CHAPTER 9. PULVERIZED COAL BOILERS
9.1 Introduction
9.2 Pulverizing Properties of Coal
A. Grindability
R Moisture
C. Wear Properties
9.3 Coal Preparation
A. Coal Crushers
R Coal Feeders
9.4 Methods of Pulverizing and Conveying Coal
A. Storage System
B. Direct-Fired System
C. Semidirect System
D. Source of Heated Air
9.5 Pulverizing Air Systems
A. Indirect Coal-Storage Pulverizing Systems
B. Direct Firing Arrangements
9.6 Types of Pulverizers
A. Ball-Tube Mills
R Impact Mills
C. Attrition Mills
D. Ring-Roll and Ball-Race Mills
E. Types of Pulverizers for Various Materials
9.7 Pulverized Coal Boilers
A. Wall Fired Boilers
R Tangentially Fired Boilers
C. Vertically Fired Boilers
D. Cyclone Fired Boilers
9.8 Emissions
Slide 9-1
-------
9. PULVERIZED COAL BOILERS
9.1
Introduction
PULVERIZED COAL SYSTEMS
Pulverizing Properties of Coal
Coal Preparation
Methods of Pulverizing and Conveying Coal
Pulverizing Air Systems
Types of Pulverizers
Pulverized Coal Boilers
Slide 9-2
In a pulverized coal firing system, coal is grinded into very fine powder, called
pulverized coal, using a mechanical device called a pulverizer and fed into a boiler
furnace through a burner specially designed to burn the coal. Since pulverized coal is
so fine, it burns like a gas and its flame is easily lighted and controlled. Pulverized coal
firing systems have the ability to adapt operating conditions to all coal ranks from
anthracite to lignite. This chapter describes pulverizing properties of coal, coal
preparation, methods of pulverizing and conveying coal, pulverizing air systems,
types of pulverizers, and types of pulverized coal boilers. It also presents typical
emissions from these coal fired boilers.
9.2
Pulverizing Properties of Coal
PULVERIZING PROPERTIES OF COAL
Grindability
Moisture
Wear Properties
Slide 9-3
Grindability
The ease of pulverization of a coal is measured by its grindability index. This
index, unlike moisture, ash or heating value, is not an inherent property of coal.
Rather, it represents the relative ease of grinding coal when tested in a particular
type of apparatus.
Grindability is not the same as the hardness of coal. The same coal may have
a range of grindabilities depending on other constituents in the coal. For example,
9-1
-------
Slide 9-4 shows typical relationships between Hardgrove grindability and moisture
content for North Dakota lignites. Typically, anthracites and some lignites have at
least one point where their grindabilities are very close. Anthracite, however, is a
very hard coal whereas lignite is soft, yet they both are difficult to grind.
NORTH DAKOTA LIGNITES1
Moisture Range
in Which
Pulverizing
is Done
Peerless
Mine
X
V
-a
c
I
"E
C8
20 30 40
% Moisture Content
Slide 9-4
Moisture
As mentioned in Chapter 4, moisture of a coal is usually referred as the total
moisture, which consists of inherent moisture and surface moisture. Surface
moisture has negative effects on both the pulverization performance and combustion
process. The surface moisture produces agglomeration of fines in the pulverizing
zone, and reduces pulverizer drying capacity. Agglomeration of fines has the same
effect as coarse coal during combustion since particle surface available for reaction is
reduced.
Hot air is used to dry coal in the pulverizing system. Slide 9-5 shows curves
which indicate the air temperature required to dry coal of varied total moisture and
coal air mixture. If there is a deficiency of hot air, the mill output will be limited to the
drying capacity and not the grinding capacity. Therefore, it may be possible to obtain
more capacity with low moisture coal of lower grindability than with high moisture
coal of higher grindability.
9-2
-------
TEMPERATURE OF AIR TO MBLLi
18CTF Leaving Mixture Temperature
%HiO
^ Entering-Leaving
16-20
14-20
12-2 0
10-20
8-20
6-15
4-15
2-tO
200
12345
Lbs of Air Leaving Mill / Lb of Coal
!70°F Leaving Mixture Temperature
%H.O
Entering-Leaving
26-75
70
22-65
-60
-60
-55
50
50
45
40
6-40
2345
Lbs of Air Leaving Mill / Lb of Coal
Slide 9-5
Wear
Pulverizing typically wears down the grinding element material. Balls, rollers,
rings, races, and liners gradually erode and wear out as a result of abrasion and metal
displacement in the grinding process. Thus, the maintenance of the grinding elements
is one of the major costs of the pulverizing operation. "Pure coal" is relatively
nonabrasive; however, such foreign material as slate, sand, and pyrites, commonly
found in coal as mined, are quite abrasive. These are undesirable constituents that
produce rapid and sometimes excessive wear in pulverizing apparatus. The
economics of coal cleaning to remove such abrasive foreign materials depends on
many variables and must be determined for each individual application.
9.3
Coal Preparation
COAL PREPARATION
Coal Crushers
Swing-Hammer Crushers
Roll Crushers
Coal Feeders
Belt Feeders
Overshot Feeders
Slide 9-6
9-3
-------
Coal should be prepared properly to insure its safe, economical, and efficient
use in a pulverizing system. Coal must be crushed before it can be fed to the
pulverizers. The issues associated with coal preparation are as follows:
• Controllable continuity of flow to the pulverizer must be maintained.
• Organic foreign materials such as wood, cloth, or straw should be
removed. These materials may collect in the milling system and
obstruct the flow patterns in the mill. They may also become a fire
hazard.
• The raw coal must be crushed to a size that will promote a uniform flow
rate to the mill by the feeder. Favorable coal particle sizing minimizes
segregation of coarse and fine fractions in the bunker, and result in a
more uniform rate of feed to different pulverizers supplied from a given
bunker.
• An ideal feed is the one that is closely sized and double—screened (3/4 in. x
1/4 in.). Coal of this size will permit excess water to drain off; it will flow
freely and uniformly from bunkers.
Coal Crushers
Swing-Hammer Crushers: Swing-hammer crushers are typically used for
smaller capacities. These crushers have proven satisfactory for overall use and have
demonstrated reliability and economy. A swing-hammer crusher consists of a casing
enclosing a rotor to which pivoted hammers or rings are attached. Coal is fed through
an opening in the top of the casing and crushing is affected by impact of the revolving
hammers or rings directly on the liners or spaced grate bars in the bottom of the
casing. The degree of size reduction depends on hammer type, speed, wear, and bar
spacing. These crushers produce uniform coal sizing and break up pieces of wood and
nonmetallic foreign material.
BRADFORD BREAKER!
Casing
Perforated
Plate
Lifter
Slide 9-7
9-4
-------
Roll Crushers: Roll crushers have been used but are not always satisfactory
because of their inability to deliver a uniform sized product. The Bradford breaker,
shown in Slide 9-7, is probably the most satisfactory crusher for large capacities.
The design consists of a large diameter, slowly revolving cylinder of perforated steel
plates. The size of the perforation determines the final coal sizing. These openings
are l1^ to 1V2 inches in diameter. The breaking action of coal is accomplished as
follows: the coal is fed in at one end of the cylinder and carried upward on projecting
vanes and shelves. As the cylinder rotates, the coal cascades of the vanes and break
upon striking the perforated plate. Since the coal drops a relatively short distance,
coal crushing occurs with the production of very few fines. Broken coal passes
through the perforations in the plates to a hopper below. Rocks, wood, slate, tramp
iron, and other foreign materials are rejected. This breaker produces a relatively
uniform product and uses very little power.
Coal Feeders
A coal feeder is a device that supplies the pulverizer with an uninterrupted flow
of raw coal to meet system requirements. This is especially important in a direct
fired system.
SCHEMATIC OF BELT-TYPE GRAVIMETRIC COAL FEEDERi
Coal Inlet
Demand.
Signal
Digital
Scale Control
• Totalizer
• Feedback Signal
Slide 9-8
Belt Feeders: The belt feeder uses an endless belt running on two separated
rollers receiving coal from above at one end and discharging it at the other end. The
feed rate is controlled by varying the speed of the driving belt. A leveling plate fixes
the depth of the coal on the belt. The belt feeder can be used in either a volumetric
type and gravimetric type of application (Slide 9-8). The gravimetric type is more
9-5
-------
popular due to its ability to deliver accurate quantities of coal to each individual
pulverizer.
There are two methods of continuously weighing the coal on the feeder belt.
One method uses a series of levers or balance weights; the other uses a load cell
across a weigh span on the belt. Both are very accurate mechanisms and both are
well accepted by utilities. This same belt feeder design can also be used for
volumetric measurement.
OVERSHOT ROLL FEEDERi
Raw-Coal
Inlet
Hinged
Levelling Gate
Stationary Core
Revolving Blade
Hot-Air Slot
Slide 9-9
Overshot Feeders: Slide 9-9 shows a schematic of an overshot roll feeder. The
feeder has a multiblade rotor which turns about a fixed, hollow, cylindrical core. The
core has an opening to the feeder discharge and is provided with heated air to
minimize wet coal accumulation on surfaces and to aid in coal drying. A hinged,
spring loaded leveling gate mounted over the rotor limits the discharge from the rotor
pockets. This gate permits the passage of oversize foreign material. Feeders of this
type may be attached to the side of a pulverizer or mounted separately.
9-6
-------
9,4
Methods of Pulverizing and Conveying Coal
METHODS OF PULVERIZING AND
CONVEYING COAL
Storage System
Direct Fired System
Semidirect System
Slide 9-10
Three methods of supplying and firing pulverized coal have been developed: the
storage system, the direct fired system and the semidirect system. These methods
differ on the basis of their drying, feeding, and transport characteristics.
The Storage System
STORAGE SYSTEMi
Cyclone Collector
Raw-Coal
Bunker
Motor.
Raw-
Coal
Feeder
Vent To
Collector Atmosphere
Filter
iHoYssap svwasn9
Motor
Pulverizer
Coal
Pump
& t Pulverized-
Transporter Coal
Feeders
_ Motor
Exhauster Fan
Hot Air-
Hot Air or Flue Gas
Motor o^J
A.rP™ To Burners
Air Fan
in
Boiler Furnace
Slide 9-11
In a storage system, coal is pulverized and conveyed by air or gas to a suitable
collector from which the coal is transferred to a storage bin. The hot air or gas
introduced into the mill provides for system drying requirements and is vented from
the system with the moisture evaporated from the fuel. The pulverized coal is fed
from the bin into the furnace as required.
9-7
-------
The Direct Fired System
DIRECT-FIRED SYSTEM
Raw-Coal Bunker
To Boiler Furnace
Hot Air
Motor
Pulverizer
In a direct fired system, coal is pulverized and transported directly to the
furnace where it is burned. The hot air supplied to the mill provides the heat for
drying the coal or transporting the fuel to the furnace. This air is known as primary
air and is a portion of total combustion air.
The Semidirect System
SEMIDIRECT SYSTEM
Raw-Coal
Bunker
Raw-Coal
Feeder
Cyclone
Collector
Primary-Air
Fan
otor F
Pulverizer
Hot Air
Exhauster
Fan
Slide 9-13
In a semidirect system, a cyclone collector located between the pulverizer and
the furnace separates the conveying medium (hot air) from the coal. The coal is fed
directly from the cyclone to the furnace in a primary air stream which is different
from the air supplied to the mill. The drying medium, therefore, is the same as in a
storage system.
9-8
-------
Source of Heated Air
The hot air from either a regenerative or recuperative air heater (see Chapter
3) is the best source of heated air for mill drying. Large boiler installations usually
provide sufficient temperatures for almost any moisture condition. On small
installations, where the moisture content in the coal is not high, steam air heaters are
used to dry the fuel.
All the moisture in the coal must be removed before the fuel can be ignited.
Therefore, for rapid ignition, surface moisture must be removed before the coal is
injected into the furnace. The type of fuel and its surface moisture govern mill drying
requirements.
The drying capability of a given pulverizer depends on the following factors: (1)
the extent of circulating load within the mill, (2) the ability to mix the dry return coal
with the incoming wet coal feed, and (3) the air quantity and air temperature design
limits. Some pulverizers are designed to operate with inlet air temperatures as high
as 825°F, while others limit maximum air temperature to 600°F.
The type of fuel and the kind of system being used will determine the mill outlet
temperature. As shown in Slide 9-14, outlet temperatures for storage system mills
are lower than those of direct fired or semidirect systems. This is because most coals
will not store safely at temperatures used in direct firing. Inadequate outlet
temperature control may cause fires resulting from spontaneous combustion of coal
in the storage bins.
ALLOWABLE MILL OUTLET TEMPERATURES, °Fi
System Storage
High-rank, high volatile bituminous 130 *
Low-rank, high volatile bituminous 130 *
High-rank, low-volatile bituminous 135 *
Lignite 110
Anthracite 200
Petroleum coke (delayed) 135
Petroleum coke (fluid) 200
Direct
170
160
180
110-140
180-200
200
* 160°F permissible with inert atmosphere blanketing of storage bin and low
concentration conveying medium.
Semidirect
170
160
180
120-140
180-200
200
oxygen
Slide 9-14
9-9
-------
9.5
Pulverizing Air Systems
PULVERIZING AIR SYSTEMS
Indirect Coal-Storage Pulverizing Systems
Primary Air
Vented Air
Direct-Firing Arrangements
Suction System
Pressure Exhauster System
Cold Primary Air System
Slide 9-15
Two methods are used to supply air for drying and transporting purposes:
indirect coal storage pulverizing system and direct firing arrangements.
Indirect Coal Storage Pulverizing Systems
In an indirect pulverizing system, a cyclone collector separates the coal from
the air. The pulverized coal is conveyed either mechanically or pneumatically to
storage hoppers or bunkers. Fuel feeders at the bunker outlets deliver the required
quantity of coal to the fuel lines where the coal is mixed with air, called primary air, in
proper proportions for transport to the burners. In some installations, the primary
air is taken from the room or a preheated air duct, or both. In other installations, the
air vented from the pulverizer system is used for all or part of the primary air supply.
Primary Air: Primary air is used to carry the coal to the furnace and to
provides the required velocity of the coal air mixture in the burners. The primary air
quantity therefore depends on the type of firing system, on the type of piping system
selected (vertical, horizontal or sloped), and on the burner and furnace arrangement.
Pulverized-coal feeder and fuel piping arrangements determine the primary air
temperature, which may be as high as 600°F. A minimum amount of tempering air
(admitted to the system to achieve proper coal air mixture condition) should be used
in the primary air system since it reduces the quantity of air passing through the air
heater, reducing the overall unit efficiency.
If vented air is to be used for tempering, the temperature of delivered air will
depend on the temperature of the vent air, the position of the vent in the return air
line, and on whether preheated coal air is added to the primary air at the fan inlet.
The vented air will usually have a relative humidity of 70 to 90 percent, a
temperature of 110 to 160°F and will contain coal fines from the collectors.
Vented Air. In a storage system, some or all of the drying air is discharged from
the system by venting. This removes the moisture which has been evaporated from
the fuel. The amount of air vented will depend on the pulverizer output, the moisture
removed from the fuel, the initial temperature of the drying air, the temperature of
9-10
-------
the vented material and the efficiency of the drying system.
The vented mixture may be disposed in one of two ways: (1) by venting directly
to the atmosphere through the boiler stack, or (2) by using it as part of the air
supplied to the furnace. Since the vented air contains some extremely fine coal (up
to 2 percent of the amount being pulverized), it cannot be vented directly to the
atmosphere economically. This is because of the need to collect the coal dust in
cyclones, bag filters, air washers, or a combination of these. In the second case, the
air does not need cleaning.
Direct Firing Arrangements
There are three basic air conveying systems used for direct firing arrangement.
The first is a suction system in which a fan induces air flow through the pulverizer
and discharges the coal air mixture under pressure to the furnace. The second is a
pressurized exhauster system, in which the pulverizer is pressurized by a forced draft
fan with both hot and ambient air and discharges the coal air mixture through the
exhauster to the furnace, acting as a booster fan. Lastly a cold primary air system
uses a primary air fan that forces air through an air heater and the pulverizer and
then forces the coal air mixture to the furnace.
Suction System: The suction system has a number of advantages. It is easy
to keep the area around the pulverizer clean. It is easy to control the air flow through
the pulverizer. Control of the coal air mixture temperature is by a single hot air
damper and a barometric damper through which room temperature air is induced by
the suction in the pulverizer. With this control, the fan is designed for a constant, low
temperature mixture and has low power consumption, even though such material
handling fans have a relative low efficiency of 55 to 60 percent.
The main disadvantage of the suction system is the maintenance required on
the exhauster. However, by using proper design techniques and wear resistant
materials the maintenance on an exhauster can be minimized. Exhaust
maintenance costs are more than offset by the power and capital savings of the
system; this justifies the continued use of the suction system on smaller units.
Pressurized Exhauster System: To obtain sufficient pressure for firing a
pressurized furnace, the pressurized exhauster system was developed. This system
retains the advantages of the suction system, such as maintaining a constant low
temperature mixture and ease of airflow control. This flow varies with the amount of
fuel being fed to the pulverizer.
One advantage of the pressurized exhauster system is that the low pressure in
the pulverizers does not pose a serious problem to sealing the head of coal over the
raw fuel feeder as compared with pulverizers under direct blower pressure. The
disadvantage of the system is the high maintenance of the exhauster.
9-11
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Cold Primary Air System: In this system the primary air fan handles only
ambient air. The chief advantage of this system over the other two systems is in fan
power and maintenance. Since the fans only handle cold air, they can be smaller, run
at higher speed. They also can use highly efficient airfoil blade shapes. Inlet vanes
can control air flow and add to fan efficiency.
Some other advantages of this system are that higher pressure differentials
are possible and larger mills with longer fuel pipes become more practical. Thus,
pulverizers can be located a further from the boiler furnace. Space requirements can
be reduced since an individual fan for each pulverizer is not necessary. Moreover,
with the high fan pressure head available, the inlet airflow can be measured by
installing a venturi other metering device.
Controlling air flow to various pulverizers is still relatively simple even with
fewer pulverizer fans. The total primary air required is a function of the number of
pulverizers in operation. This permits a simple control for the air flow requirements.
Because load and coal moisture content can vary among pulverizers, it is not only
necessary to control the total air flow but also the temperature of the air to individual
pulverizers. This is accomplished with a system which uses a hot primary air duct
and a cold primary air duct with a damper in each duct to the mills. The air flow
requirement for a pulverizer is met by adjusting both dampers, while controlling
temperature by properly proportioning the flow between the hot and cold air ducts.
The cold primary air system offers savings through the elimination of
exhauster maintenance and reduction in fan power. These saving are partially offset
by the capital investment for additional ductwork, dampers, and controls. With large
units and pulverizers, the use of a cold primary air system becomes economically
favorable.
9.6
Types of Pulverizers
Speed
Type
PULVERIZER TYPESi
Low Medium High
Ball-Tube
Mm
Ring Roll or
Ball-Race Mill
Impact or
Hammer Mill
Attrition Mill
Slide 9-16
Grinding uses either one, two, or all three of the basic principles of particle size
reduction; namely, impact, attrition, and crushing. The four most commonly used
pulverizers are the ball tube, the ring-roll or ball-race, the impact or hammer mill,
and the attrition type.
9-12
-------
Ball-Tube Mills
ARRANGEMENT OF BALL-TUBE MILLS
Exhausterl
Slide 9-17
A ball-tube mill is basically a hollow horizontal cylinder, rotated on its axis,
whose length is slightly less than its diameter. Heavy wear resistant liners fit the
inside of the cylindrical shell, which is filled to a little less than one half with forged
steel or cast alloy balls varying from 1 to 4 inches in diameter. Rotating slowly at 18
to 35 rpm, the balls are carried about two thirds of the way up the periphery and
continually cascaded toward the center of the cylinder.
Mill Operation: Coal is fed to the cylinder of the ball tube mill. Pulverization,
which is accomplished through the continual cascading of the mixtures, results from
(1) impact of the falling balls on the coal, (2) attrition as the coal slides over each
other as well as over the liners, and (3) crushing as balls roll over each other and over
the liners with coal particles between them. Large pieces of coal are broken by
impact, and the fine grinding is done by attrition and crushing as the balls roll and
slide within the charge.
Hot air is passed through the mill to dry the coal and remove the fines from the
pulverizing zone. In most designs, an external classifier regulates the size of the
finished product. The oversize rejects from the classifier are returned to the grinding
zone with the raw coal.
9-13
-------
Impact Mills
DIAGRAM OF AN IMPACT MILLi
Hot Air
Pulverized Coal & Air
Raw-Coal
Feeder
Exhauster
Whizzer or Fineness
Regulator
Mill Drive
Shaft
Feeder
Drive Unit
Slide 9-18
An impact mill consists primarily of a series of hinged or fixed hammers revolving in
an enclosed chamber lined with wear resistant plates. Grinding results from the
combination of hammer impact on the larger particles and attrition of the smaller
particles on each other and across the grinding surfaces. An air system with fan
mounted either internally or externally on the shaft induces a flow through the mill.
An internal or external type of classifier can be used.
This type of mill is simple and compact and may be built in very small sizes.
Its ability to handle high inlet air temperatures, plus the return of dried classified
rejects to the raw feed, makes it an excellent dryer. However, the high speed design
results in high maintenance and high power consumption for grinding fines.
Progressive wear on the grinding elements reduces the product fineness. It is
very difficult to maintain fineness over the life of the wearing parts.
Attrition Mills
Because of the high rate of wear on parts, attrition mills are not used for coal
9-14
-------
pulverizing. A high speed mill that relies on considerable attrition grinding along with
impact grinding is, however, used for direct firing of pulverized coal. In this type of
mill, the grinding elements consist of pegs and lugs mounted on a disk rotating in a
chamber. The periphery of the chamber is lined with wear resistant plates, and its
walls contain fixed rows of lugs within which the rotating lugs mesh. The fan rotor is
mounted on the pulverizer shaft. A simple rejector which is mounted on the shaft is
used instead of an external classifier. This mill type exhibits all the characteristics of
the impact mills.
Ring-Roll and Ball-Race Mills
Ring-roll and ball-race mills are medium speed mills. They use primarily
crushing and attrition of particles, plus a small amount of impact to obtain size
reduction of the coal. The grinding action takes place between two surfaces, one
rolling over the other. The rolling element may be either a ball or a roller, while the
other member may be either a race or a ring.
DIAGRAM OF BALL-RACE MILLS
Grinding Ball
Driving Ring
Slide 9-19
9-15
-------
Ball-Race Mill: When the rolling elements are balls, they are confined between
races. In the majority of designs, the lower race is the rotary member while the upper
race is stationary. Some other designs also use a rotating upper race.
DIAGRAM OF RING-ROLL MILL JOURNAL ASSEMBLE
Spring Assembly
Trunnion Shaft
Grinding
Ring
Mam
Vertical
.Shaft
Grinding Roll Assembly
Grinding Roll
Journal
Stop Bolt
Slide 9-20
Ring-Roll Mills: Two general classes of mills use rollers as the rolling
elements. In one class, the roller assemblies are driven and the ring is stationary; in
the other class, the roller assembly is fixed and the ring rotates.
9-16
-------
Types of Pulverizers for Various Materials
TYPES OF PULVERIZERS FOR VARIOUS MATERIALSi
Type of Material
Low-volatile anthracite
High-volatile anthracite
Coke breeze
Petroleum coke (fluid)
Petroleum coke (delayed)
Low-volatile bituminous coal
Med-volatile bituminous coal
High-volatile A bituminous coal
High-volatile B bituminous coal
High-volatile C bituminous coal
Subbituminous A coal
Subbituminous B coal
Subbituminous C coal
Lignite
Lignite and coal char
Brown coal
Ball-
Tube
X
X
X
X
X
X
X
X
X
X
X
X
...
...
...
Impact and Ball
Attrition Race
...
X
• •• *• •
X
X X
X X
X X
X X
X X
X
X
X
X
X
X
X
Ring
Roll
...
X
...
X
X
X
X
X
X
X
X
X
X
X
X
...
Slide 9-21
Different types of mills are used for different types of coals, depending on the
grinding requirements and cost considerations. Slide 9—21 shows the types of
pulverizer used for various coals.
9-17
-------
9.7
Pulverized Coal Boilers
PULVERIZED-COAL BOILERS
Wall-Fired Boilers
Tangentially-Fired Boilers
Vertically-Fired Boilers
Cyclone-fired Boilers
Slide 9-22
Two representative systems of boilers to burn pulverized coal are the wall fired
systems (characterized by individual flames) and tangentially fired systems (which
have a single flame envelope). There are other types and combinations; one such is
the vertically fired system, which uses characteristics of both aforementioned
systems.
Wall-Fired Boilers
BURNER FOR HORIZONTAL FIRING OF COALi
Coal & Primary Air
Ring Dampers
Burner Throat
Coal Nozzle
Adjustable Air Vanes
Pulverized-Coal
Distribution Vanes
Windbox
Slide 9-23
9-18
-------
In wall fired boiler systems, the fuel is mixed with combustion air in individual
burner registers. Coal and primary air are introduced tangentially to the coal nozzle,
thus creating a strong rotational flow within the nozzle. An ignitor assembly is
located at the centerline of the coal nozzle and is cooled with a bleed of windbox air.
Surrounding the coal nozzle is the secondary air passage, which has adjustable vanes
to impart swirling flow of the preheated secondary air from the windbox for flame
stabilization. The degree of air swirl, coupled with the flow shaped contour of the
burner throat, establishes a recirculation pattern in front of the burner exit extending
several burner diameters into the furnace. Once the coal is ignited, the hot products
of combustion recirculate in front of the nozzle providing stable combustion.
FLOW PATTERN OF HORIZONTAL (WALL) FIRINGi
Burner B
Burner A
Air A
AirB
Slide 9-24
Burners are typically arranged on the boiler front wall only (Slide 9-24) or on
both the front and rear walls. The latter is called opposed fired.
9-19
-------
Tangentially Fired Boilers
TANGENTIAL FIRING PATTERNi
Mam Fuel
Nozzle
Secondary-
Air
Dampers
Slide 9-25
In the tangentially fired boiler systems, both fuel arid combustion air are
injected from burners in each corner of the furnace (Slide 9—25). When the streams
from the four corners meet, they create a large rotating flame, called a fireball, rather
than creating individual flames at each burner. In some units, the fuel and air exiting
the corner ignite almost immediately before passing into the swirling fireball. In
others, the ignition point is extended and occurs when the fuel/air mixture reaches the
fireball.
9-20
-------
ARRANGEMENT OF CORNER WINDBOX
FOR TANGENTIAL FIRING OF COAL*
Windbox
Secondary-Air
Dampers
Damper Drive Unit
Coal Nozzle
Secondary-Air
Nozzles
Side Ignitor
Nozzle
Coal Nozzle
Warm-UpOilGun
Slide 9-26
Fuel and air are injected from the furnace corners in vertical compartments.
Slide 9-26 shows a schematic of a burner pack used in tangentially fired boilers.
Dampers control the air quantity to each compartment, making it possible to vary
air distribution over the height of the burner pack. It is also possible to vary the air
velocity, change the mixing rate of air and fuel , and control the ignition point of the
fuel/air mixture.
The vertical arrangement of the burner pack allows flexibility in multiple fuel
firing. Gas or oil nozzles are typically located in the secondary air compartments
adjacent to the coal nozzles.
Some tangentially fired boilers have tilting burners. Tilting the burners allows
the relative heat absorption between the furnace and convective pass to be varied to
control steam temperature. When the furnace is clean, the burners are tilted upward
to increase the heat transfer to the high temperature superheat and reheat surfaces
in the upper furnace. As ash deposits build on the furnace walls, furnace heat
absorption drops resulting in an increase in heat transfer to the superheat and reheat
sections. Then, the burners are tilted downward to compensate.
9-21
-------
Vertically Fired Boilers
BURNER ARRANGEMENT OF VERTICALLY FIRED BOILERS
Oil and Secondary Air
Arch
000 000 OOO 000 000 000 OOO 000
Front Wall
Jet Air
Coal and Secondary Air
Slide 9-27
A schematic of a burner used in vertically fired boilers is shown Slide 9-27.
Pulverized coal is discharged through the fuel nozzles. Combustion air is introduced
through ports located around the fuel nozzles and through auxiliary ports. Tertiary
air ports are located on the front and rear walls in the lower furnace.
FLOW PATTERN OF VERTICAL FIRING
Upper
Front
(or Rear)
Wall
High Pressure
' Jet Air
Primary Air and
• Pulverized Coal
Secondary Air
Furnace Enclosure
(Refractory Lined)
&— Arch
I— Tertiary Air
Admission
"U"-Shaped
Vertical
Pulverized-Coal
Flame
Slide 9-28
9-22
-------
The firing system produces a long looping flame in the lower furnace, with the
combustion products discharging up the center (Slide 9-28). A portion of the
combustion air (tertiary air) is injected well downstream of the burners. This provides
needed turbulence in the flame. The flow patterns passes the hot flue gases in front
of the fuel nozzles, thus contributing energy necessary to ignite the fuel. The flow
pattern also promotes entrainment of large solid fuel particles, thus allowing long
residence times in the combustion chamber.
Cyclone Fired Boilers
CYCLONE FURNACES
Secondary Air Gas Burners
Coal Desiaggmg
Oil Burner
Primary Air
Radial Burner
Mam Oil Burner
Replaceable
Wear Liners
Slag Tap Opening
Slide 9-29
9-23
-------
Cyclone fired boilers are designed to burn relatively large coal particle sizes
(95% passing through a 4 mesh screen) than the other boiler systems. In a cyclone
furnace (Slide 9-29, crushed coal and primary air enter the front of the cyclone
through a specially designed burner. Secondary air is added tangentially to the main
cyclone, creating a swirl motion. A unique circulating combustion pattern results.
The products of combustion eventually leave the cyclone through a re-entrant throat.
A molten slag layer develops and coats the inside surface of the cyclone barrel. The
slag drains to the bottom of the cyclone and is discharged through a slag tap.
FINAL ARRANGEMENTS USED FOR CYCLONE FURNACES2
. (a)
Screened Furnace
Arrangement
Single Wall
(b)
Open Furnace
Arrangen«nt
Single Wall
(c)
Open Furnace
Arrangement
Double Wall
Slide 9-30
Several cyclone firing arrangements have been utilized. These are single wall
fired with screen, single wall fired without screen, and double wall fired. The main
furnace is relatively small and maintains high furnace temperatures over the furnace
floor slag taps and to promote slag flow on the furnace walls. The lower furnace walls
have a protective refractory lining.
9.8
Emissions
As previously discussed in Chapter 6, sulfur oxides (SOX), nitrogen oxides
(NOX), CO, CO2, particulate flyash, volatile organic compounds (VOC) and some trace
quantities of other materials are exhausted from the stack. These are primarily
byproducts of the combustion process. Fugitive dust arises from fuel handling. Solid
wastes include ash collected at boiler bottom, economizer and air heater hoppers as
well as from the ESP and fabric filters. Solid wastes also include byproducts of flue
gas desulfurization scrubbing process. Typical emissions from a 500 MW pulverized
coal fired boiler is shown in Slide 9-31.
9-24
-------
COAL FIRED BOILER EMISSIONS
(500 MW Boiler, 2.5 % sulfur, 16% ash)2
Discharge Rate (t/h)
Emissions Uncontrolled Controlled
SOX as SO2
NOX as NO2
C02
Flyash to Air*
Ash to Landfill*
Scrubber Sludge
(Gypsum plus Water)
* As flyash emissions to the
9.3
2.9
485
22.9
9.1
0
air decline,
0.9
0.7
485
0.05
32
25
ash snipped
Control Equipment
Wet Limestone Scrubber
Low-NOx Burners
Not Applicable
ESP or Baghouse
Controlled Landfill
Controlled Landfill or
Wallboard Quality Gypsum
to landfills increases.
Slide 9-31
9-25
-------
REFERENCES
1. Singer, J.G., Combustion: Fossil Power Systems, 3rd edition, Combustion
Engineering, Inc., 1981.
2. Steam, Its Generation and Use, 40th Edition, Babcock and Wilcox Company,
1992.
3. Elliot, C.T., Standard Handbook of Powerplant Engineering, McGraw-Hill
Publishing Company, New York, 1989.
4. Folsom, B.A., Coal Boiler Basics, Energy and Environmental Research
Corporation, Irvine, CA.
9-26
-------
CHAPTER 10. STOKERS
10.1 Introduction
10.2 Types of Stoker
10.3 Underfeed Stokers
A. Side ash Discharge Type
B. Rear Ash Discharge Type
C. Coal Specifications
D. Boiler Furnaces
E. Overfire Air and Combustion Air
10.4 Mass Feed Stokers
A. Chain Grate
B. Traveling Grate
C. Water-Cooled Vibrating Grate
D. Fuel Specifications
E. Furnace Design
F. Overfire Air
10.5 Spreader Stokers
A. Fuel
B. Fuel Burning
C. Fuel Feeders
D. Types of Grates
E. Overfire Air
F. Fly Carbon Reinjection
10.6 Emissions
Sbde 10-1
-------
10. STOKERS
1.0
Introduction
COMPONENTS OF A STOKER
Fuel Supply System
Burning Grate
Overfire Air System
Ash Discharge System
Slide 10-2
Stokers are mechanical devices that feed solid fuels, including coal, wood
wastes, bagasses as well as residential and commercial refuse, onto a grate at the
bottom of the furnace and remove the ash residue. Stokers are designed to permit
continuous or intermittent fuel feed, fuel ignition, air supply for combustion, free
passages for the resulting gaseous products, and disposal of non-combustible
materials. A stoker firing system typically consists of a fuel supply system, a
stationary or moving grate assembly which supports the burning mass of fuel and
admits most of the combustion air to the fuel, an overfire air system to complete
combustion, and an ash or residual discharge system.
VIBRATING GRATE STOKER
Fuel Supply
Distribution
Air
Ash Hopper
Air
Plenum
Slide 10-3
10-1
-------
10.2
Types of Stnker
TYPES OF STOKER
Underfeed System
Overfeed System
Mass Feed System
Spreader System
Slide 10-4
There are two general types of stoker underfeed and overfeed.
Underfeed Stoker: In an underfeed stoker, the fuel and air are supplied from
underneath the surface of the grate. Underfeed stokers use both stationary- and
moving-grate tuyeres (openings in a shell through which air is forced).
Overfeed Stokers: In an overfeed stoker, the fuel is fed from a hopper above the
moving grate, and combustion air is supplied from below the grate.
The overfeed stokers are divided into mass feed and spreader categories based
on the method of introducing the fuel into the furnace. A discussion of each stoker
type follows.
10.3
Underfeed Stokers
UNDERFEED STOKERS
Side Ash Discharge Type
Rear Ash Discharge Type
Coal Specifications
Boiler Furnaces
Overfire air and Combustion Air
Slide 10-5
There are two general types of underfeed stokers, the horizontal feed side ash
discharge type and the gravity feed rear ash discharge type.
10-2
-------
Side Ash Discharge Type
SINGLE RETORT UNDERFIRE STOKER WITH
HORIZONTAL FEED, SIDE ASH DISCHARGE
Dumping
Grate ,Poal
Retort
W.^Ji&%t)y&?Q*^i&/ti$?« &'Qf$l?\fi:y!\^(rj£'Q' ^5*^'-9t*^?
i'Q-'-'**' 'aia-ri'V ' 'ft ^•^•'Q*'n*'^ fS''rt' -LQ^^.'rt'.«'<&'>* lLfr*M .r
End View
Slide 10-6
In the side ash discharge type, shown in Slide 10-6, coal is fed from a hopper to
a central trough or retort, by a screw or a ram pusher. In larger units, a ram assisted
by pusher blocks or a sliding retort bottom (fuel distributors) moves the coal upward
and into the retort. As the retort is filled from the bottom coal moves upward and out
of the retort onto the grate area where it is exposed to air and radiant heat from the
furnace. As the coal moves along the grate to the sides and/or rear, the distillation of
the volatiles in the coal occurs leaving the coke which is burned out near the edges or
end of the grate. High pressure overfire air is added to produce high turbulence to
enhance mixing and reduce smoke.
Burning coal in side ash discharge underfeed stokers increases the chance of
producing large agglomerates of ash slags (clinkering) and layers of ash slag
(matting). To reduce this tendency alternate fixed and moving grate sections are
applied to the underfeed stoker design to break-up and distribute the fuel.
10-3
-------
Rear Ash Discharge Type
UNDERFEED STOKER WITH REAR ASH DISCHARGE
Coal Hopper -i
Dump Plates
r Reciprocating
Extension Grates
Distributing
Pusher Blocks
Stationary
Air Tuyeres
Feeder
Rams
Slide 10-7
The grate of this type is inclined at an angle of 20 to 25° above the horizontal,
so that gravity assists in distributing the coal over the length of the retorts. This
type of stokers uses a series of retorts installed side by side and normally extending
from front to rear of a boiler, with tuyere sections between the retorts and along the
side walls of the boiler.
Round or square rams are installed to move the coal from the coal hopper into
the upper or front end of the retorts below the point of combustion air supply.
Secondary rams or pusher plates move the coal along the retort and upward into the
burning zone immediately above the retorts, where combustion air is supplied to the
fuel bed through tuyeres located between and above the retorts. An adjustable dump
grate section is used at the rear end of the retorts to retain the ash and prevent an
avalanching of unburned coal into the ash pit.
10-4
-------
Coal Specifications
TYPICAL UNDERFEED STOKER COAL CHARACTERISTICS 2
Stationary Grate Moving Grate
Moisture % vol.
Volatile Matter % vol.
Fixed Carbon % vol.
Ash % vol.
Higher Heating Value Btu/lb
Free Swelling Index
Ash Softening Temp.* °F
Coal Size in
OtolO
10 to 40
40 to 50
5 to 10
12,500
5 max
2,500**
1 x 0.25 max
20% through 0.25
with round screen.
OtolO
30 to 40
40 to 50
5 to 10
12,500
7 max
2,500**
Equal portions: 0.25,
0.25 to 0.5, 0.5 to 1.0.
* The ash softening temperature is the temperature at which the height of a molten
globule is equal to half its width under reducing atmosphere conditions.
** Below 2500°F the moving grate is derated linearly to 70% of its rated capacity at
2300°F ash fusion temperature. Stationary grates are derated linearly to 70% at
2100°F ash fusion temperature and use steam for temperatures below about 2400°F
fusion temperature.
Slide 10-8
A relatively wide range of coals can be burned on underfeed stokers; however,
the largest size is limited to a range of 3/4 to 11/2 in, and typical specifications call for
l!/4-in particles. The amounts of fines should be limited to 50 percent passing
through a i/4-in round-hole screen.
The free swelling index (see Chapter 4 for definition) of the coal should be
limited to 5 with side discharge stokers having stationary tuyeres. A coal having free
swelling index up to 7 percent can be on side discharge stokers with moving tuyeres
and on rear discharge stokers. Underfeed stokers can burn coals at rated capacity
with an ash fusion temperature above 2,400°F. Coals having an ash fusion
temperature as low as 2,100°F can be burned at reduced burning rates.
It is normally recommended that the iron content in the ash be no more than
20 percent as Fe2Oa with an ash fusion temperature above 2,400°F and below 15
percent with coals having a lower ash fusion temperature.
10-5
-------
Boiler Furnace
Water-cooled furnaces are preferred with underfeed stokers. On the smaller
sizes of side charge stokers, however, satisfactory performance can be obtained with
refractory walls. Adequate furnace volume must be provided in accordance with the
recommendations of the manufacturer.
Overfire Air and Combustion Air
All underfeed stokers should be provided with an overfire air system designed to
provide adequate furnace turbulence to complete burnout of the hydrocarbons.
Depending on the width of the stoker, load conditions, and coal-burning
characteristics, overfire air will represent 7.5 to 12 percent of the total combustion
air (theoretical air plus excess air).
10.4
Mass Feed Stokers
MASS FEED STOKERS
Grate Types
Chain Grate
Traveling Grate
Water-Cooled Vibrating Grate
Coal Specifications
Furnace Design
Overfire Air
Slide 10-9
Mass feed stokers are the first of two categories of overfeed stokers discussed
in this chapter. Three basic types of grates utilized with overfeed stokers are chain
grate, traveling grate, and water-cooled vibrating grate.
10-6
-------
Chain Grate
CROSS SECTION OF OVERFEED MASS-BURNING
CHAIN-GRATE STOKER
i- Coal Hopper
Air Zone Seal Plates
Slide 10-10
The grate surface of the chain-grate stoker consists of narrow grates which
form links. The links are staggered and connected by rods extending across the stoker
width to form a wide-continuous-chain assembly, which is pulled or pushed through
the furnace by an electric or a hydraulic drive.
Traveling Grate
Overfire
Air Nozzle
CROSS SECTION OF OVERFEED MASS-BURNING
TRAVELING-GRATE STOKER
Coal Hopper
Fuel Feed
Grate
Grate Clips
or Grate Keys
Air Control Dampers
Pit
Slide 10-11
10-7
-------
The grate surface of the traveling grate consists of narrow grate clips mounted
on lateral carrier bars that are attached to the grate chains,, which pull or push the
grate through the furnace, using an electric or a hydraulic drive.
Water-Cooled Vibrating Grate
WATER-COOLED, VIBRATEVG-GRATE STOKER
Coal Hopper-
Rear Furnace Arch
Grate Cooling Tubes
Adjustable Ash Dam
Water-Cooled
Header
Grate
Fuel Feed
Gate
Vibrating
Generator
Grate
Support
and Flexing
Member
Slide 10-12
The grate surface of the water-cooled vibrating-grate stoker consists of
tuyere—type grates mounted on and in close-fitting contact with a grid of
water-cooled tubes, which are connected to the boiler circulation system for positive
cooling. The entire structure is supported on steel flexing plates, permitting the entire
water-cooled grid and grate surface to vibrate with a preset amplitude that moves
the fuel bed through the furnace. Vibration of the grate is intermittent, and the
vibration period and delay between vibrations are regulated by a timing device
synchronizing the fuel feeding rate with steam demand.
10-8
-------
Fuel Specifications
TYPICAL MASS STOKER COAL CHARACTERISTICS 2
Moisture % vol.
Volatile Matter % vol.
Fixed Carbon % vol.
Ash % vol.
Higher Heating Value Btu/lb
Free Swelling Index
Ash Softening Temp. * °F
Coal Size in
* See Slide 10-8 for definition.
Chain/Traveling
Grate
Oto 10
10 to 40
40 to 50
5 to 10
12,500
5 max
2,500
1 x 0.25 max
20% through 0.25
with round screen.
Water-Cooled
Grate
Oto 10
30 to 40
40 to 50
5 to 10
12,500
7 max
2,500
Equal portions: 0.25,
0.25 to 0.5, 0.5 to 1.0.
Slide 10-13
A relatively wide range of coals can be burned on mass feed stokers; however,
the top size is limited to a range of 3/4 to 11/2 in, and typical specifications call for
li/4-in particles. The amounts of fines should be typically limited to 50 percent
passing through a i/4-in round-hole screen.
Fuel Types: Almost all fuels of suitable size can be burned, including peat,
lignite, subbituminous, bituminous, anthracite, or coke. However, bituminous coals
may have a tendency to clog and prevent proper passage of air through the fuel bed,
thus causing high carbon loss to the ash hopper. The fuel bed can be made more
porous by water or steam tempering (to reduce clogging tendency) of the fuel. This is
done in the stoker coal hopper on chain— and traveling-grate units. Tempering is not
required on water-cooled vibrating-grate stokers, since the vibrating action of the
grate tends to keep the fuel bed uniform and porous.
Grate Sizing: Overfeed stokers are best suited for industrial and institutional
powerplants having steady load demands. Since all the fuel is consumed on the grate,
the stoker grate surface must be conservatively sized. The grate heat release rate
(quantity of heat released per hour divided by grate area) should be limited to a
maximum of 425 Btu/hr-ft2 of active grate area. These stokers are normally
designed for capacities up to 150,000 Ib/hr of steam.
10-9
-------
Furnace Design
Water—cooled furnaces are preferred with all moving—grate stokers to prevent
slag formation on the furnace walls. The tube spacing of the furnace walls should not
exceed twice the tube diameter. Adequate furnace volume must be provided as
recommended by the boiler and stoker manufacturers.
Overfire Air
Overfeed stokers are provided with high-pressure overfire-air system
consisting of one or two rows of closely spaced air jets located above the fuel bed in
the front wall of the furnace. The jets provide adequate furnace turbulence to
complete the burnout of the hydrocarbons. The high-pressure-air fans will be sized
to provide approximately 10 percent of total air. The static pressure of the fan is
selected to provide proper penetration of the air into the furnace.
10.5
Spreader Stokers
SPREADER STOKERS
Fuels
Fuel Burning
Fuel Feeders
Types of Grates
Overfire Air
Fly Carbon Reinjection
Slide 10-14
The second category of overfeed stokers are spreader stokers. In spreader
stokers, the fuel is spread into the furnace over the grates from feeders located across
the front of the unit. The purpose is to feed the fuel evenly over the grate surface in
order to release an equal amount of energy from each square foot of active grate
surface. The air for combustion should then be admitted evenly through the grate to
provide the oxygen for burning. Above the grates, an overfire-air system is provided
for additional oxygen and turbulence in the lower-furnace zone temperature to ensure
efficient performance. Since spreader stokers can burn a wide range of solid fuels,
and cover a wide range of boiler sizes, the arrangement and design of each of the three
basic components—fuel feeders, type of grate, and overfire-air system—depend on
the specific project.
10-10
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Fuels
The fossil fuels burned on spreader stokers include bituminous, subbituminous,
and lignite coals. It is necessary to size the fuel properly for spreader stokers. The
coals should have 95 percent less than V-/4 inch in maximum size.
Fuel Burning
As the fuel is fed to the furnace in a manner to spread it evenly over the
complete grate surface, it burns both in suspension and on the grate. The amount
burned in suspension depends on a number of factors. Fine fuel burns more in
suspension; that is, with coal the size 16 mesh is significant. High-volatile fuels
release more energy in suspension. High moisture can increase the energy release on
the grate. The burning fuel bed on the grate may be only about 1 in thick. This depth
depends on fuel characteristics and firing rate. Under the burning fuel, an ash bed is
formed, which should be about 3-in thick.
The ash-bed thickness also depends on fuel characteristics, but not on the
firing rate since the rate of ash discharge is regulated to the firing rate. The ash bed
provides an insulating barrier between the burning fuel and the metal-grate surface
additionally cooled by the combustion airflow across the grate.
Fuel Feeders
FUEL FEEDERS
Reciprocating Feeder
Chain Feeder
Drum Feeder
Slide 10-15
There are many types of fuel feeders utilized in spreader stokers: reciprocating
feeder, chain feeder, and drum feeder.
10-11
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RECIPROCATING COAL FEEDERS
Reciprocating
Feed Plate—
3
Rotor
Control Shaft
and Linkage
Adjustable
Spill Plate
Air Tuyere
Slide 10-16
Reciprocating Feeder: Coal feeders have a device which meters the coal from
the coal feeder and delivers it to the built-in rotor. This device should have a bias
means built in so that coal feed can be varied from one to another. This allows
adjustment for segregation in fuel sizing from one feeder to another. A schematic of a
reciprocating feeder is shown in Slide 10-16. The reciprocating feeder has one or
more feed plates which travel back and forth on a spill plate. On the back stroke, coal
drops from the hopper in front of the plate. On forward stroke, coal is pushed off from
the spill plate onto the rotor. The amount of coal per stroke is adjusted by (1) the
length of stroke of the feed plate through mechanical devices, (2) the number of
strokes per minute through mechanical variable-speed devices, or (3) electronic
devices such as variable—frequency power units to alternating-current (ac) motors,
or silicon controller rectifier control units to direct-current (dc) motors.
10-12
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CHAIN-TYPE COAL FEEDERS
Coal Gate
Slide 10-17
Chain Feeder: A schematic of a chain feeder is shown in Slide 10-17. A chain
feeder has a drag conveyor deliver the coal out of a hopper, off the end of the chain,
onto the rotor. The amount of coal is a function of the speed of the chain and the
depth of the coal, the depth of the coal is adjusted by the position of a gate above the
chain. The speed can be regulated by an internal mechanical variable-speed device,
or electronically, as described previously.
Drum Feeder: The drum feeder utilizes a revolving drum with semipockets to
deliver the coal out of a hopper onto the rotor. As with the chain feeder, the amount
of coal is regulated by the speed of the drum and the depth of coal coming out of the
hopper on the drum. The vibrating feeder delivers the coal to the rotor out of the coal
hopper on a vibrating conveyor. The amount of coal is adjusted by the frequency of
vibration and the depth of coal on the conveyor.
10-13
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Types of Grates
TYPES OF GRATES
Stationary and Dumping
Reciprocating
Vibrating
Traveling
Vibrating, Water-Cooled
Slide 10-18
A number of grate types are utilized for spreader-stoker firing. They are
stationary and dumping grate, reciprocating grate, vibrating grate, traveling grate,
and vibrating, water-cooled grate. They all serve the same purpose: they provide a
floor on which the fuel can burn, a means of distributing air evenly through the grates,
and a method of discharging the ashes that accumulate on the grate from the
consumed fuel. A description of each of these grate types is given below.
SPREADER STOKER WITH DUMPING GRATES
Coal Hopper
Over Fire Air Nozzles
Fuel Feeder
...•[-Power Operated X=£
Dumping Grates .
ii ii b.
MJ
Air Chamber
and
Ash Pit
Slide 10-19
10-14
-------
Stationary and Dumping: The intermittent cleaning types of grates are
stationary and dumping. The stationary grate is rarely used because of hazards to
the operator when removing ashes through the open fire door and the resultant
exposure directly to the furnace. It is extremely difficult to clean fires without
creating a smoky fire condition of high opacity.
The manual dumping type of grate (Slide 10-19) has one section for each fuel
feeder. To remove ashes, the fuel feed is stopped in front of one of the grate sections,
to allow complete burnout of combustible products. The air supply to that section is
then cut off with appropriate dampers, and the ashes can be dumped into a pit below.
While this cleaning is done it is necessary for the remaining sections to burn
additional fuel to maintain the boiler rating. After the ashes are dumped, the fuel
feeder is started again. When the fuel ignites, the undergrate damper to that section
is reopened to resume normal combustion. It is very difficult to accomplish this
cleaning process without high opacity. Consequently, the dumping grate is seldom
used for burning coal having a high percentage of volatiles and low ash content.
SPREADER STOKER WITH RECIPROCATING GRATES
Over Fire Air Nozzles
Coal Hopper^
Coal Feeder
- Reciprocating Grates
Slide 10-20
10-15
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Reciprocating: The reciprocating grate (Slide 10-20) discharges ashes by a
slow back-and-forth motion of moving grates alternating with stationary grates.
Each row of grates rests on the row in front and has a raised nose which pushes the
ashes toward and off the end of the grate into an ash hopper. It is preferable to
discharge the ashes at the front under the feeders. Since the fuel is thrown toward
the rear, best control of ash discharge with minimum combustibles in the ashes can
be achieved with front ash discharge from any type of conveying grate.
Because of the stepped nature of the reciprocating grate, it is used only for
fuels with sufficient ash quantity to provide an adequate ash depth insulation on top
of the grate. Undergrate air temperatures are ambient.
SPREADER STOKER WITH VIBRATING GRATES
Over Fire Air Nozzles
Coal Hopper^.
Coal Feeder
- Vibrating or Oscillating Grates
Slide 10-21
Vibrating: The vibrating or oscillating grate (Slide 10-21) is suspended on
flexing plates. Either an eccentric drive or rotating weights impart a vibrating action
to the grate surface, which conveys ashes to the front and discharges them into an
ash pit. The frequency of vibration is kept well below the natural frequency, to
minimize the forces on the support structure. The rate of ash discharge is regulated
by a timer system that controls the off time between vibrating cycles and the length
10-16
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of vibrating time. Since the vibrating grate is flat, it is well suited for coal.
SPREADER STOKER WITH TRAVELING GRATES
Over Fire Air Nozzles
Coal Hopper-^
Coal Feeder
/-Grate'3urface
Slide 10-22
Traveling'. The traveling-grate spreader stoker (Slide 10-22) is by far the
most popular type, and there are numerous types of construction. The most
important consideration is that the design of the grate surface should provide a high
resistance to airflow through the grate to ensure even distribution of air through the
grate. The traveling grate moves forward to discharge the ashes at the front end
under the fuel feeders. The return grate then passes underneath in the air chamber.
The traveling grate is driven either mechanically or hydraulically through appropriate
mechanical devices, electronic devices, or hydraulic flow-control valves.
When the ash content in the fuel is consistent, the speed of the grates can be
regulated by the combustion controls to maintain an even ash-bed thickness. The
grate bars can be made from cast iron with small amount of alloy for heat and wear
resistance, or from ductile iron for increased heat resistance and impact resistance.
10-17
-------
SPREADER STOKER WITH WATER-COOLED
VIBRATING GRATES
Over Fire Air Nozzles
Coal Hopper-v
Coal Feeder
Cooling
Water
Inlet
Water-Cooled Grate
Eccentric Grate Drive
r Cooling
/
Water
Outlet
—^- Sifting Hopper
Slide 10-23
Vibrating, Water-Cooled: The water-cooled vibrating grate spreader stoker
(Slide 10-23) is used for refuse burning, but could conceivably be used for coal firing
too. A water-cooled grid on which a grate surface is fastened is mounted on a frame.
The whole assembly is supported on flexing plates on an angle of 6° down toward the
ash discharge end. An eccentric drive vibrates the grate assembly through a timing
circuit that controls the amount of off and on time. The vibrating action moves the
ash to the front of the grate and into the ash pit. The vibration frequency is kept well
below the natural frequency.
The water-cooled grid is cooled by tying into the boiler water-circulation circuit
or a separate forced-cooling system. Which method selected is dictated by the needs
of the individual projects.
Overfire Air
The overfire air system on spreader-stokers has three functions: (1) to provide
oxygen and turbulence to mix the fuel and oxygen in the lower high-temperature zone
of the furnace for complete burnout, (2) to distribute fuel and assist in distribution
10-18
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when the design dictates the use of air for this purpose, and (3) to provide cooling air
for mechanical fuel feeders. The air can come from a common fan that would have
static pressure capabilities of 25 to 30 in H2O to provide the necessary energy for
turbulence or fuel distribution.
Overfire air nozzles are placed in rows in the front and rear walls of the
furnace. The design should place the air nozzles at elevations which will ensure
mixing of the furnace gases in the high—temperature zones, so that the combustion
processes can be completed in the furnace. Air—nozzle spacing in each row should be
on centers 10 to 12 inches for complete coverage of the furnace.
The size of the air nozzles in the various rows is a function of the depth of the
penetration desired and the amount of overfire air required. Bituminous-coal-fired
boilers are designed with 15 to 25 percent overfire air. Lignite-fired boilers are
designed with 20 to 25 percent overfire air. The overfire air temperature may be
either ambient or the temperature of the undergrate air. The choice of temperature
is generally a function of air heater and boiler system design.
Fly Carbon Reinjection
The participate leaving the furnace of a spreader stoker can contain
considerable combustible material and thus is termed fly carbon. It is beneficial to
return some percentage of this fly carbon to the furnace for burning to improve the
boiler efficiency. This is accomplished by the conveying system, which transfers the
fly carbon from hoppers through a pipeline to the furnace using air as the conveying
medium. By using a nozzle and venturi arrangement, air at up to 25 in H2O can
create a suction to draw the fly carbon into the pipeline and pressure-convey it to the
furnace.
The air supplied is generally from the overfire air fan; however, a separate fan
can be used. The fly carbon can be collected in hoppers under the boiler's steam
generating section, economizer, air heater, or mechanical dust collector, although
continuous evacuation of the hopper is required. The amount of reinjection sets the
increase in boiler efficiency.
The particulate collected in an electrostatic precipitator or fabric filter should
not be returned to the furnace. Since the particulate collected in an electrostatic
precipitator or fabric filter (located downstream of the mechanical dust collator)
usually contains more ash than fly carbon, it should not be returned to the furnace.
Reinjection of significant ash is undersirable because it can contribute to boiler
surface erosion and grate clinkering.
10-19
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10.6
Emissions
TYPICAL UNCONTROLLED EMISSIONS FOR
SPREADER-STOKER FIRING *
Bituminous
Subbituminous
Lignite
*% of Heat Input
NOX (as NO2)
lb/106 Btu
0.35 to 0.50
0.30 to 0.50
0.30 to 0.50
CO
lb/106 Btu
0.05 to 0.30
0.05 to 0.30
0.10 to 0.30
Unburned Carbon Loss*
with without
Reinjection Reinjection
0.5 to 2.0 3 to 6
0.5 to 1.5 3 to 5
0.5 to 1.5 3 to 5
Slide 10-24
Slide 10-24 lists typical uncontrolled emission values for spreader-stokers
firing various coals. These values will vary with fuel composition and equipment
selection.
NOX is formed from the oxidation of the nitrogen compounds in the combustion
air and in the fuel (see Chapter 4). With stoker firing it is believed that most of the
NOX is derived from fuel-bound nitrogen. NOX emissions can be effectively controlled
by staging combustion, inherent in spreader-stoker firing, and by controlling excess
air levels. For coal stoker firing, the excess air level in low NOX stoker systems is
about 25%. To control NOX to the lower end of the range shown in Slide 10-24, deeper
staging is employed, i.e., lower undergrate and higher overfire air flows. For spreader
firing, feeder are also designed to improve fuel distribution and combustion on the
grates. Other factors that reduce NOX formation include minimizing the quantity of
fines in the fuel and using ambient temperature combustion air.
For most stoker-fired units burning coals which contain sulfur, sulfur dioxide
(SO2) will be present in the flue gas (see Chapter 4). For prediction purposes and
sizing of SO2 control equipment it is assumed that all the fuel sulfur becomes SO2-
Carbon monoxide (CO) and volatile organic compound emissions are generally
a function of the efficiency of the combustion process and the quantity and control of
fines and excess air. CO will tend to increase as NOX is reduced.
10-20
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REFERENCES
1. Singer, J. G., Combustion: Fossil Power Systems, 3rd edition, Combustion
Engineering, Inc., 1981.
2. Steam, Its Generation and Use, 40th Edition, Babcock and Wilcox Company,
1992.
3. Elliot, C.T., Standard Handbook of Powerplant Engineering, McGraw-Hill
Publishing Company, New York, 1989.
4. "Alternative Control Techniques Document — NOX Emission from
Industrial/Commercial/Institutional (ICI) Boilers," US EPA, EPA-453/R-94-
022, March, 1994.
10-21
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CHAPTER 11. FLUIDIZED-BED BOILERS
11.1 Introduction
11.2 Typical Fluidized-Bed Conditions
11.3 Fluidized-Bed Combustion Advantages
A. Reduced Emissions
B. Fuel Flexibility
11.4 Atmospheric Pressure Fluidized-Bed Boilers
A Bubbling Bed
B. Circulating Bed
11.5 Fluidized-Bed Boiler Furnace Design
A. Design Information
B. Bed Material
C. Pressure Drop
D. Heat Transfer
11.6 Fluidized-Bed Boiler Arrangements
A. Boiler Subsystems
B Auxiliary Equipment
11.7 Operation
A. System Control
B. Bed Temperature Control
C. Bed Material Inventory Control
D. Overfire Air Control
11.8 Emissions
A. Sulfur Dioxide
B. Nitrogen Oxides
C. Carbon Monoxide and Hydrocarbons
D. Particulates
Slide 11-1
-------
11. FLUIDIZED-BED BOILERS
11.1
Introduction
FLUIDIZED-BED BOILERS
Typical Fluidized-Bed Conditions
Fluidized—Bed Combustion Advantages
Atmospheric Pressure Fluidized-Bed Boilers
Fluidized-Bed Boiler Furnace Design
Fluidized-Bed Boiler Arrangements
Slide 11-2
In fluidized-bed boilers, combustion of solid fuels take place in a bed containing
inert materials (typically sands). This combustion process produces high heat
transfer rates and low combustion temperatures. Key benefits of this process are
fuel flexibility and reduced emissions. This chapter provides detailed discussions of
the fluidized-bed combustion technology and its applications in electric power
generation industries. It first provides a description of typical fluidized-bed
conditions. The chapter then discusses advantages of fluidized—bed combustion.
Atmospheric pressure fluidized-bed boilers and their design and arrangements are
next described. Boiler operation and their emissions are subsequently presented.
11-1
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11.2
Typical Fluidized—Bed Conditions
TYPICAL FLUIDIZED-BED CONDITIONS*
Distributor Plate
(a)
6 «
BubbtfrtgBwi
|Air
Fixed Bed
(b)
I Air
Minimum
Fluid ization
(0
Circulating B«d
(at
Slide 11-3
Slide 11-3 shows typical fluidized-bed conditions. The upper chamber of a
fluidized-bed container is filled with sand or other granular materials. Air is supplied
11-2
-------
from a plenum located at the bottom chamber. A distributor plate provides even air
flow through the bed.
If a small amount of air flows through the distributor plate, it passes through
the immovable mass of the bed materials. If the air velocity is weak, it does not exert
much force into the sand particles and they remain in place. This condition is called a
fixed bed (Slide ll-3b).
As the air flow increases, it exerts greater force on the sand to a point where
the sand particles become suspended in the upward flowing air stream. At this point,
the bed starts to behave like a fluid. This condition is called minimum fluidization
(Slide 12-3c).
As the air flow increases further, bubbles of air start to form and the bed
becomes violent. This condition is called bubbling bed (Slide ll-3d). The volume
occupied by the air—solid mixture now increases substantially. By increasing the air
flow further, the bubbles becomes larger and begins to form large voids in the bed.
This condition is called turbulent fluidized bed.
If the solids are caught, separated from the air and returned to the bed they
will circulate around a loop. This condition is defined as a circulating fluidized bed
(CFB) (Slide ll-3e). Unlike the bubbling bed, there is no distinct transition between
the dense bed in the bottom of the container and the dilute zone above.
11.3
Fluidized—Bed Combustion Advantages
FLUIDIZED-BED COMBUSTION ADVANTAGES
Reduced Emissions
S02
NOX
Fuel Flexibility
Fuel Ash Properties
Low Btu Fuels
Fuel Preparation
Slide 11-4
One distinct advantage of fluidized-bed combustion is that the system can be
operated at low combustion temperatures. Most fluidized-bed boilers are designed to
have the bed operating temperature of about 1,500 to 1,600°F (pulverized-coal
boilers typically operate at about 2500 to 2600°F). The ability to operate at this low
temperature results in several operating advantages. Another advantage of fluidized-
bed combustion is that it achieves higher heat transfer rates from the fuel to the
water tubes.
11-3
-------
Reduced Emissions
Sulfur Dioxide: Inexpensive sorbents such as limestone or dolomite are used to
reduce SO2 emissions from fluidized-bed boilers. Because of the low bed operating
temperatures, these sorbents can be added directly to the bed to obtain good mixing
and long residence times necessary for the sulfation reaction (see Chapter 21).
Ninety percent (90%) or more SOz reduction is achieved depending on fuel sulfur
content and the amount of sorbent added.
Nitrogen Oxides: With an operating bed temperature between 1,500 to
1,600°F, the amount of NOX formed in the fluidized bed is less than in conventional
systems which operate at much higher temperatures. This is because the rate of
NOX formation drops off substantially as the gas temperature decreases. Further
NOX reduction can be achieved in fluidized-bed boilers by air staging since they can
be operated with less impacts on combustion efficiency than the conventional units.
Fuel Flexibility
Fuel Ash Properties: Due to the low combustion temperatures, fluidized—bed
boilers allow the use of high slagging fouling fuels at temperatures below their ash
fusion temperature. As a result, many of the boiler operating problems associated
with these fuels are greatly reduced.
Low Btu Fuels: The fluidized-bed combustion process can also burn fuels with
very low heating values. This capacity results from the rapid heating of the fuel
particles by the hot bed materials and from the long residence time the fuel particles
spend in the boiler, both of which offset the effects of low combustion temperatures.
Fuel Preparation: Fluidized-bed boilers can burn crushed coals with particle
size up to 0.25 in. These coals are easier and less costly to prepare than pulverized
coals.
11-4
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11.4 Atmospheric Pressure Fluidized—Bed Boilers
Bubbling Bed
TYPICAL BUBBLING FLUIDIZED-BED BOILER SCHEMATIC*
Secondary
Superheater
Primary Superheater
Economizer
Water-cooled
Walls
Top of Bed
Bubbling
Bed \
• Gas
Dust Collector
Superheater and
Boiling Surface
Air
Distributor \
Plate Windbox
Slide 11-5
Slide 11-5 shows the main features of a bubbling fluidized-bed boiler.
Normally, heat transfer surfaces are placed in the bed to achieve the desired heat
balance and bed operating temperature. Because of the vigorous mixing of gas and
solids, the bed temperature is very uniform (± 25°F).
Coal—fired bubbling-bed boilers normally use a recycle system after the
economizer to recycle the solids. This maximizes combustion efficiency and sulfur
capture. Furnace flue gas velocity is about 8 to 10 ft/a at maximum load.
11-5
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Circulating Bed
TYPICAL CIRCULATING-BED BOILER SCHEMATICi
Primary and
Secondary
Superheater
Gtt
Overfire Air
Supply Ducts
Primary
~ Air
Distributor Wlndbox
Plate
Slide 11-6
11-6
-------
Slide 11-6 shows the main features of a circulating fiuidized-bed boiler. The
bed does not contain any heat transfer surfaces. This type of boiler typically uses
division walls to provide the required heat removal. Furnace temperature remain
uniform since the mass of solids is many times the mass flow rate of the combustion
gases. Furnace walls typically provides sufficient heat absorption required to
maintain bed temperature around 1,500 to 1,600°F. Furnace flue gas velocity is
about 20 ft/s at full load.
11.5
Fluidized-Bed Boiler Furnace Design
FLUIDIZED-BED BOILER FURNACE DESIGN
Design Information
Bed Material
Pressure Loss
Heat Transfer
Slide 11-7
Design Information
Typical information used to establish design requirements for a fluidized—bed
boiler is as follows:
• Unit capacity — steam flow requirements,
• Fuel — type, ash and moisture content, pulverizing characteristics,
reactivity, and fouling characteristics,
• Limestone — type, reactivity, size and attrition characteristics,
• Sulfur removal requirements,
• NOX emission limits, and
• Load turndown range.
Bed Material
A sufficient amount of bed material with proper size distribution must be
maintained for a fluidized-bed boiler to operate properly. If the particles are too
coarse, the bed will defluidize and become fixed. If the particles are too fine, the bed
material will get blown out of the furnace, making it impossible to maintain an
adequate amount of bed material.
Pressure Drop
Pressure loss in a fluidized-bed boiler furnace is of great importance since it
defines the amount of solids in the furnace, which is a major variable that influences
heat transfer. Because the concentration of solids and the pressure profile are closely
11-7
-------
related, the determination of pressure drop is a primary task when establishing
furnace performance.
Heat Transfer
Due to the high solid content in the gas flow, heat transfer coefficients in a
fluidized—bed boiler furnace are considerably higher than those of a conventional unit.
However, due to the lower gas temperatures in fluidized-bed furnace, the overall heat
fluxes in the two systems are similar. Solid and gas convection and solid and gas
radiation are the predominant heat transfer modes in a fluidized—bed boiler.
11.6
Fluidized—Bed Boiler Arrangements
FLUIDIZED-BED BOILER ARRANGEMENTS
Boiler Subsystem
Distributor Plate
Overfire Air System
Boiler Furnace
Auxiliary Equipment
Fuel Feed System
Sorbent Feed System
Ash Removal System
Sootblowers
Slide 11-8
Boiler Subsystem
Distributor Plate: The distributor plate is located at the bottom of the furnace
and separate the windbox from the furnace. The plate typically has flow distributors
such as bubble caps to provide uniform flow distribution of combustion over the
cross-section of the furnace. Typically, 50 to 70% of the combustion air flow through
the distributor plate at full load in a circulating bed boiler. In a bubbling bed, 85 to
100% combustion air flows through the plate if staged combustion is not used.
Overfire Air: The overfire air system is used to enhance combustion and
control NOX emissions. With overfire air, a portion of combustion air that does not
flow through the distributor plate is injected into the combustion gases shortly after
the coal ignition to complete combustion. The overfire air must provide good mixing to
complete combustion and minimize CO emissions. Overfire air mixing depends on the
size of the overfire air nozzles and the air and gas velocities and densities.
Boiler Furnace: Boiler furnace is constructed of water-cooled membraned
tubes welded together to form a gas-tight furnace.
11-8
-------
Auxiliary Equipment
Fuel Feed Systems: There are three types of fuel feed system used for
fluidized-bed boilers. These are underfeed, overfeed and in-bed feed systems.
An underfeed system is usually a pneumatic transport system that moves the
fuel from the storage silo to the bed. For good fuel-air mixing, the fuel feed pipes
under the bed should be closely spaced. Typical fuel pipe spacing for a underfeed
system is about 4 feet. Underfeed systems are used in bubbling fluidized—bed boilers
burning bituminous coal. The coal used in an underfeed system should be crushed to
less than 0.25 in and fuel moisture should be less than 6% to avoid pluggage in the
transport pipes.
The overfeed system is located above the bed where the gas pressure is slightly
below atmospheric. Therefore, the fuel stream does not have to be pressurized.
Overfeed systems are also typically used in bubbling fluidized-bed boilers. The coal
should be crushed to a top size of 1.25 in, and the amount of fine coal (less than 30
mesh) is limited to prevent excessive burning in the furnace zone immediately above
the bed (called freeboard).
An in-bed system typically uses a feed screw or air assisted chute system. In
the in-bed feed system, the fuel is injected through an enclosure wall just above the
distribution plate. The fuel stream must be sealed against the bed pressure, which is
substantially higher than atmospheric. In-bed feed systems are used in CFB boilers.
Sorbent Injection System: Sorbent can be mixed and fed with the fuel into the
furnace using an underfeed or in-bed feed system. Sorbent can not be fed properly
with an overfeed system due to its fineness. Sorbent is blown into the furnace
through separate pneumatic feed points and by gravity from a silo.
Ash Removal Systems: Solids including bed ash, bed material and sorbent or
inerts can be removal from a fluidized-bed boiler at two places: a bed drain and a
baghouse or an ESP. The bed drain normally removes from 0 to 50% of total solids.
Sootblowers: Because fluidized-bed boilers are operated at temperatures
below the ash softening points, fouling and slagging on the boiler furnace are usually
not a problem. Some boilers do not need to have sootblowers. However, sootblowers
are necessary when firing fuels containing high sodium and/or potassium ash.
11-9
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11.7
Operation
OPERATION
System Control
Bed Temperature Control
Bed Material Inventory Control
Overfire Air Control
Slide 11-9
System Control
Most of the operating and control features of fluidized-bed boilers and
conventional boilers are the same, except two main areas. One is the ability to
transport and control large quantities of solids; the other is to control primary and
secondary air splits to maximize combustion efficiency and minimize emissions. By
controlling solid quantities and air flows, important parameters of fluidized-bed
boilers such as bed temperature and bed inventory can be controlled.
Bed Temperature Control
Bubbling Bed: Since the heat absorbing surfaces are located within the bed
itself, heat balance around the bed controls the bed temperature. As load varies, heat
balance around the bed must be varied to achieve the desired bed operating
temperature. The heat balance can be altered by either increasing or decreasing the
bed depth. Decreasing the bed depth will decrease the amount of heat transfer since
less heat removing surface is submerged in the bed, or vice versa.
Bed temperature can also be controlled by increasing or decreasing excess air
and air temperature. Increasing excess air will decrease the bed temperature since
more heat is required to heat up the extra air. Bed temperature increases as air
temperature increases.
Circulating Bed: Due to the more uniform distribution of the bed material
throughout the furnace, gas temperature is more uniform in CFB boilers than in
bubbling bed boilers. As mentioned previously, heat transfer is a function of solid
inventory in the furnace. Therefore, furnace temperature in CFB boilers can be
controlled by controlling bed inventory.
Bed Material Inventory Control
Bubbling Bed: Bed inventory is dependent on the balance between feed solids
and bed drain flows, plus the solids that escape the furnace to back-end collectors. In
practice, the minimum solids feed flow rate must provide enough material to maintain
the bed drain flow required to remove oversized particles plus make up the back-end
11-10
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loss. Bed inventory is controlled by measuring pressure drop across the bed and
maintaining it at a value corresponding to the desired inventory.
Circulating Bed: In CFB boilers, the amount of solids leaving the furnace and
bed inventory are interdependent. Solids leaving the furnace must be collected and
returned to the furnace to maintain bed inventory. Overall inventory is controlled in
the same way with a bubbling bed boiler.
Overfire Air Control
AIR FLOW DISTRTOUTIONi
100
90k
80 U-
i 40
Primary
Upper Secondary
10 20 30 40 SO 60 70 30 90 100
toad,'
Slide 11-10
Slide 11-10 shows a typical split between primary and secondary (overfire) air
for a bituminous coal-fired boiler. The split is established to maximize combustion
efficiency and minimize CO and NOX emissions.
11-11
-------
11.8
Emissions
FLUIDIZED-BED BOILER EMISSIONS
Sulfur Dioxide
Nitrogen Oxides
Carbon Monoxide and Hydrocarbon
Particulates
Slide 11-11
Sulfur Dioxide
Sulfur dioxide emissions from a fluidized-bed boiler depends on the sulfur
content of the fuel. A limestone injection system is usually installed on a
fluidized-bed boiler to reduce SO2 emissions. Due to the solids circulation, sulfur
capture is better in a CFB boiler than in a bubbling bed boiler. Sulfur reductions of
about 90% are typically achieved in a CFB with calcium-to-sulfur ratio (molar) of
2.0 to 2.5, depending on the fuel sulfur content and the reactivity of the sorbent.
Nitrogen Oxides
Due to low furnace operating temperatures, NOX emissions from fluidized-bed
boilers are typically much less than conventional boilers. Typical values for NOX
emissions are within the 100 to 200 ppm (0.15 to 0.30 Ib/MMBtu of heat input) range
for a CFB boiler burning coal. Overfire air systems are typically installed on a
fluidized-bed boiler to reduce NOX emissions.
Carbon Monoxide and Hydrocarbon
Carbon monoxide (CO) and hydrocarbon (HC) are the products of incomplete
combustion of the fuel. Typical values for CO and HC emissions from a CFB boiler
are 200 and 20 ppm (by volume), respectively. CO and HC emissions can be
minimized by choosing the proper number of feed points, by properly designing the
overfire air system, and by providing sufficient furnace residence time for mixing and
complete combustion.
Particulates
Ash particles larger than 140 mesh (105 microns) are typically removed by
the bed drain system. Particles smaller than 325 mesh (44 microns) are removed by
back-end particulate collectors. A fabric filter is typically used for fluidized-bed
boilers because it is less sensitive to the ash properties, such as size, concentration,
and resistivity, than an ESP.
11-12
-------
REFERENCES
1. Steam, Its Generation and Use, 40th Edition, Babcock and Wilcox Company,
1992.
11-13
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CHAPTER 12. GAS TURBINE WITH A HEAT
RECOVERY STEAM GENERATOR
12.1 Introduction
12.2 Gas Turbine Description
A. Compressor
R Combustor
C. Turbine
12.3 Design Classifications
12.4 Operating Cycles and Efficiency
A. Simple Cycle
B. Regenerative Cycle
C. Cogeneration Cycle
D. Combined Cycle
12.5 NOX Formation Mechanisms
12.6 Control Options
A. Fuel switching
R Water/Steam Injection
C. Fuel Emulsion
D. Combustion Modifications
E. Selective Catalytic Reaction
F. Oxidation Catalyst
Slide 12-1
-------
12. GAS TURBINE WITH A HEAT RECOVERY STEAM GENERATOR
12.1 Introduction
The Federal Energy Regulatory Commission (FERC) defines the term
cogeneration as the simultaneous production and use of thermal and shaft power.
Historically, utility and industrial boiler operators have long used this term to
describe a boiler which creates electricity or mechanical energy via a steam turbine.
However, FERC cogeneration is not limited to boilers or to units for electrical power
generation. More recently, the term cogeneration is used to describe an industrial
power plant consisting of a gas turbine (GT) in conjunction with a heat recovery
steam generator (HRSG). This type of unit is consistent with the FERC's definition
of cogeneration in that the gas turbine produces the shaft work and the HRSG
produces the usable thermal energy in the form of steam. This chapter will discuss
the general description of both the gas turbine and the HRSG. A description of the
emissions and viable NOX control technologies is also offered in this chapter.
12.2 Gas Turbine Description
A gas turbine is a rotary combustion engine which provides power to either
stationary or mobile applications. For stationary applications, the exit gases from
the combustor are directed to a turbine which extracts energy from the hot gases to
produce net shaft horsepower similar to a steam turbine. This shaft horsepower is
primarily used to either drive an electric generator or to transport a fluid by driving a
pump or compressor. In some applications, the hot exhaust gases from the turbine
are used for steam production or process heating. A gas turbine's power output is
based on mass throughput. To increase the output of a GT, one only needs to
increase mass throughput by increasing the overall size or increasing the density of
the inlet gas.
GAS TURBINE COMPONENTS
Compressor
Combustor
Turbine
Slide 12-2
Gas turbines are comprised of three major components: the compressor, the
combustor, and the turbine. Ambient air is drawn into the compressor, where the
pressure of the air is increased by as many as 30 atmospheres for some turbine
models. This compressed air is passed to the combustor where fuel (gaseous or liquid)
is introduced, mixed with a portion of the air, ignited, and burned. The combustion
gases can reach temperatures of 3630'F, which are too high for the present-day
turbine metals technology. To reduce this temperature to a safe
12-1
-------
SIMPLIFIED GAS TURBINE SCHEMATIC
Fuel
Air
3.
\
*
Combustor
\
Hot Exhaust Gases
Rotary Shaft Power
Compressor
Turbine
Slide 12-3
operating level below 2300T, the combustion gases are dilution cooled with additional
air from the compressor section. Energy from the gas stream is extracted by the
axial flow turbine in the form of shaft horsepower. Typically, 50 percent of the energy
extracted by the turbine is required to drive the compressor with the remainder of the
energy available to drive either a mechanical load or an electric generator. Exit gas
temperatures from the turbine are normally around 960T.
Compressor
The first of the three major components of the gas turbine is the compressor.
Two main types of compressor designs exist in the market today: axial and
centrifugal. Axial flow compressors have both higher pressure ratios and higher
efficiencies than centrifugal compressors. Centrifugal compressors are now only used
in small gas turbines (< 500 kW) where the air flow is too small to be handled
efficiently by axial blading. Axial compressors consist of several rows of blades
attached to the main shaft of the gas turbine. As the shaft rotates, the compressor
blades increase the velocity of the air by forcing the air along the length of each
compressor blade. Following each row of compressor blades is a row of stationary
stator blades. These stator blades decelerate the air, causing the kinetic energy
produced by the velocity increase to be converted to a static pressure rise. Velocity
and pressure increases in the compressor are caused by decreasing the cross-
sectional area down the length of the compressor.
12-2
-------
Compressors are generally described in terms of pressure ratio. The term
pressure ratio describes the increase in air pressure attributed to the compressor.
Pressure ratio is simply the compressor exit pressure divided by the compressor inlet
pressure (ambient pressure). Increases in pressure ratio can be obtained by either
changing the blade geometry or by adding rows of compressor and stator blades.
Combustor
Combustor designs have developed into three basic configurations: annular,
can-annular, and silo. Although these designs are physically different, each
combustor has four basic zones: the inlet transition zone, the primary combustion
zone, the secondary combustion zone, and the outlet transition zone.
SCHEMATIC OF A TYPICAL SGT COMBUSTOR
Liner
Dome
Cool in| ikx
Fuel nozzle
Snoot
Slide 12-4
The inlet transition zone reduces the incoming gas velocity in order to establish
and maintain combustion. If the flow velocity is not reduced sufficiently, residence
time in the combustor will be too short, which may result in incomplete combustion.
Ignition of the fuel and air mixture occurs in the primary combustion zone. The fuel is
injected into the combustion chamber. Air first flows through the area between the
liner and the combustor casing. This area serves the dual purpose of preheating the
air and cooling the combustor liner. Holes in the liner regulate the amount of air
entering the combustor and allow for mixing of the air and fuel while minimizing
pressure drop. Swirl vanes and/or radial jets direct the combustion air in order to
create a turbulent section in front of the fuel nozzle. This turbulent flow allows for
thorough mixing of the air and fuel so that the fuel burns evenly and completely.
12-3
-------
The materials used to construct the combustor and turbine cannot withstand
the high temperatures of combustion. As a result, the secondary combustion zone
provides air for dilution cooling and completion of combustion. The cooling air is
provided between the flame and the combustor liner to maintain a tolerable
temperature on the combustor walls.
The final zone in the combustor is the outlet transition zone. In this zone, the
combustion gases pass through an accelerator which raises the velocity of the gases
before entering the turbine. This acceleration process is accomplished primarily by
throttling the flow. Although the combustor's overall fuel to air ratio is normally
around 0.02 at full load and the combustors are small in comparison with utility
boilers, for instance, the residence time is relatively high due to the pressures to
which the combustors are subject. Gas turbine combustion process efficiency is
usually in excess of 99 percent.
Turbine
The turbine section of a gas turbine is composed of several rows of blades
attached around the circumference of the turbine shaft. Energy in the hot
combustion gases is converted to shaft work as it is expanded across the rows of
turbine blades. Similar to the compressor, there are two basic types of turbines:
radial flow and axial flow. Radial flow turbines expand the gas along the radius of the
gas turbine. Axial turbines expand the gases along the turbine axis. Radial turbines
are primarily confined to applications which require compact size such as auxiliary
power units for aircraft. In stationary mechanical and electric power generation
industries, axial flow turbines are almost exclusively used due to their more efficient
conversion of thermal energy in the combustor exhaust gases and their ability to
handle large mass flows.
12.3 Design Classifications
For the most part, the fundamental design of a gas turbine is nearly identical
over the entire spectrum of sizes and manufacturers. Each has the three major
components: a compressor, a combustor, and a turbine. Even with these basic
similarities, there are specific design criteria which can further classify stationary
gas turbines. These design criteria are the following: single shaft or multi-shaft,
aero-derivative or heavy duty, and combustor design.
DESIGN CLASSIFICATIONS
• Single-Shaft or Dual Shaft
• Aero-Derivative or Heavy Duty
• Combustor Design
Slide 12-5
12-4
-------
In gas turbine technology, the intended application of a turbine quite often
determines the characteristics of the final design. This certainly is the case with
single- and dual-shaft turbine designs. Other multi-shaft designs do exist, however,
discussion will be limited to single- and dual-shaft arrangements as shown in Figure 3.
This exclusion results from the relative scarcity of multi-shaft units in the domestic
gas turbine market.
A single-shaft gas turbine is designed precisely as the name suggests. The
compressor and turbine stages are fixed to the same continuous shaft and operate at
the same speed. Applications that do not require variable speed operation, such as
electric power generation, are ideal for single-shaft machines. The design is
straightforward and power can be increased simply by increasing the fuel input to the
combustor.
SINGLE-SHAFT GAS TURBINE
Fuel
Air
"1
•^.
^\
Combustor
1
Compressor
Hot Exhaust Gases
Load
Slide 12-6
Dual-shaft machines divide the turbine into low- and high-pressure turbines.
The high-pressure (HP) turbine is connected directly to the compressor by a single
shaft. The low-pressure (LP) turbine, also known as the "free" or "power" turbine,
has its own shaft which is connected directly to an external load. The primary
advantage of this design is the wide range of speeds at which the power turbine can
operate making it ideal for variable load applications. Part of the load efficiency of
12-5
-------
the dual-shaft unit is higher due to less flow required to drive that turbine at low
power turbine speeds. One disadvantage of the dual-shaft machine is that in order to
restore power to the power turbine at low load, the compressor must be accelerated
to maximum speed.
DOUBLE-SHAFT GAS TURBINE
Fuel
Air
•*\
Combustor
^
Compressor
High Pressure Turbine
Low Pressure Turbine
Hot Exhaust Gases
Load
Slide 12-7
Gas turbine design has evolved from two basic user industries: the airline
industry and electric power generating facilities. Gas turbines which are designed
with the basic characteristics of aircraft engines (higher temperature ratios,
increased pressure ratios) are classified as "aero-derivative" (AD) machines. Those
units which are refinements of earlier power generating machines (constant operating
speeds, extended component life) are classified as "heavy duty" (HD) machines.
However, both AD and HD engines are used as power generating sources.
Higher efficiency, smaller size, and alloys that can withstand higher
temperatures are advances made in the aircraft engine industry that have been
incorporated into the design of the AD engines. The higher efficiency is due to the
increased pressure ratios and temperature ratios across the compressor and are
indicative of AD engines in comparison to HD engines. The temperature and pressure
ratios of a gas turbine are major contributors to the engine's efficiency (MW/PPS is
megawatt/lbs exhaust flow per second and is used as a normalizing unit because gas
12-6
-------
turbine power is directly related to mass throughput). Increases in either of these
.ratios produces an increase in the efficiency of the engine. As one may expect, an AD
engine looks nearly identical to its aircraft jet engine counterpart with a power
turbine attached.
EFFECT OF TEMPERATURE AND PRESSURE
ON THERMAL EFFICIENCY
SIMPLE CYCLE
«JJ o.j« en
SPECIFIC OUTPUT (MW/PPS)
COMBINED CYCLE
». in i >t»
SPECIFIC OUTPUT (MW/PPS)
SK
-------
The annular design is most often found in aero-derivative machines. This
combustor is a carryover from the earlier aircraft engine designs. Annular
combustors are composed of a single continuous combustion chamber that "rings"
the turbine shaft in the area between the compressor and turbine sections.
Simplicity is the primary advantage to this combustor configuration. A single
combustor allows for greater fuel flexibility, simplified fuel supply system, and ease in
monitoring fuel injection.
ANNULAR COMBUSTOR
Slide 12-10
The can-annular designs have a series of individual can shaped combustors
arranged in an annular configuration that rings the turbine between the compressor
and turbine. All basic combustor components found in the large annular combustor
are found in each of these cans. The major advantage of this design is that it allows
for easy removal of cans for maintenance and repair.
12-8
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CAN-ANNULAR COMBUSTOR
Mate fun
Bfeld
Slide 12-11
Silo combustors are the only one of the three combustors that are found
outside the body of the gas turbine. Depending on the manufacturer and model, one or
two silo combustors can be found on a particular unit. Orientation of the combustors
can be either vertical or horizontal with the vertical arrangement gaining the greatest
acceptance in the gas turbine industry. Advantages of this combustor design include
ease of maintenance and emission reduction. These advantages result from the fact
that the size constraints affecting modifications to can-annular and annular designs
do not exist for external pieces of equipment such as the silo combustor.
12-9
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SILO COMBUSTOR
Slide 12-12
12.4 Operating Cycles and Efficiency
Gas turbines are very versatile machines. They are capable of burning a wide
variety of fuels and can be used to produce shaft horsepower for applications ranging
from pipeline fluid compression, to electric power generation, to aircraft and marine
propulsion. This versatility extends to operation in a variety of thermal cycle
arrangements. Thermal operating cycles compatible with the characteristics of gas
turbines are simple, regenerative, cogeneration, and combined cycle.
OPERATING CYCLE
Efficiency
Simple Cycle
Regeneration
Cogeneration
Combined Cycle
Slide 12-13
12-10
-------
As mentioned previously, gas turbine efficiency is affected by the temperature
and pressure prior to the combustor and the temperature at the turbine inlet. The
thermal efficiency of the gas turbine alone is simply the percentage of useful energy
contained in the fuel that is converted to shaft horsepower that can be used to drive
an external load. This useful horsepower is calculated by subtracting the power
required to drive the compressor from the gross power generated by the turbine itself.
If a turbine is used in the regenerative, cogeneration, or combined cycles, the
determination of cycle efficiency is not as straightforward.
Simple-cycle
The simple-cycle is the most basic operating cycle of a gas turbine. In a
simple-cycle application, the components used are the compressor, the combustor,
and the turbine. No heat recovery or inlet air preheating is performed at any point in
the cycle. Due to the lack of heat recovery, the simple-cycle exhibits the lowest
thermal efficiency of the four gas turbine operating cycles. Typical efficiencies for
simple cycle gas turbines are in the range of 28 to 38 percent, with values as high as
42 percent for a machine recently marketed by one manufacturer. From an energy
input standpoint, roughly 1 to 2 percent of the thermal energy input of the fuel can be
attributed to mechanical losses, with the remaining energy being lost in the high
temperature exhaust gases. This cycle is typically used when shaft horsepower
production is important with little need for exhaust heat recovery. Of all four cycles,
the simple-cycle offers the lowest capital investment, but provides the least efficient
use of ftiel, which increases operating costs.
Regenerative Cycle
Regenerative-cycle gas turbines differ from simple-cycle gas turbines in that
the inlet air to the combustor is heated by indirect contact with the exhaust gases.
The heat exchanger that allows this to happen is called a regenerator or recuperator.
This regenerator becomes an additional component of the gas turbine cycle and alters
various cycle parameters including thermal efficiency, air and gas temperatures, and
emissions.
12-11
-------
KE
Compressed
Recuperator — — '
Fuel
Air
V^
Compressor
IGENERATIVE CYCLE GAS TURBINE
Exhaust Gases
Air 1
:>i
. — — »• ; \ ; Hot Exhaust Gases
..j^,.,.
JPreheated Air
Combustor
*
Vs^ x-v
Turbine
Slide 12-14
The process of using the waste heat in the turbine exhaust to preheat the
combustion air reduces the amount of fuel necessary to reach the desired
temperature level. Reducing the amount of fuel consumed directly causes a reduction
in the total mass emissions of the turbine while increasing the thermal efficiency.
This increase in efficiency is directly proportional to the temperature rise between the
compressor discharge and the combustor exit. At high pressure ratios, regenerators
are not as effective in increasing cycle efficiency. As pressure ratios rise in the
compressor, the compressor exit temperature approaches the turbine exhaust
temperature. The closer these two temperatures come to each other, the lower the
amount of energy (heat) that can be transferred to the compressor exit air. This
continues to occur until a point at which the marginal gain in efficiency (reduction in
fuel consumption) does not outweigh the increased capital and maintenance costs
attributed to the regenerator.
12-12
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EFFECT OF REGENERATIVE CYCLE
ON GT THERMAL EFFICIENCY
. 36
9
s
£
J=
? 32
28
O
20
I 12
Prusurt RitM
20
Slide 12-15
Cogeneration Cycle
The cogeneration cycle is basically a simple-cycle configuration with a waste
heat boiler attached to the system which uses the turbine exhaust gases to produce
steam. The waste heat boiler is usually referred to as a heat recovery steam
generator (HRSG). As is the case with a fired boiler, an HRSG is capable of producing
steam at various temperatures and pressures in order to meet the needs of the
customer. Typical exhaust temperatures for gas turbines are on the order of 950T,
thus having limited steam production capabilities. When the exhaust heat energy is
not sufficient to meet the steam requirements of the customer, a supplementary
burner, or duct burner, can be placed in the exhaust duct upstream of the HRSG to
increase the exhaust heat energy. Duct burners can increase the exhaust gas on the
order of 500"F and, since the HRSG heat transfer works solely by convection, the
driving force is the temperature difference between the exhaust gas and evaporator
tubes. Cogeneration can reach thermal efficiencies around 80 percent, however, the
efficiency in regards to the conversion of fuel energy input to mechanical power
conversion (hp or MW output) still remains around the level of a simple cycle at 30-40
percent.
12-13
-------
STATIONARY GAS TURBINE COGENERATION UNIT
Exhaust Gases
Fuel
Heat Recovery
Steam Generator
Compressor simple Cycle Gai Turbine Turbine
Rotary Shaft Power
Slide 12-16
As mentioned above, the HRSG is similar to a fired boiler. The steam can be
used in a process on- or off-site, power a steam turbine used in a mechanical
operation, or create electrical power by a generator, or a combination of these. Often,
cogeneration units produce a low temperature and pressure steam for process units
and use the high temperature, high pressure steam to power a turbine. Due to the
variety of steam use, the efficiency in regards to the conversion of fuel energy input to
mechanical power conversion can reach as high as 45 percent for some combinations.
The highest efficiency is found when all the steam is used for electric power
generation in the combined cycle.
Combined Cycle
The combined cycle is the most complex of the gas turbine operational cycles
and is a specific form of cogeneration. This cycle consists of a simple-cycle gas
turbine to which an HRSG is added to produce steam that is then used to drive a
steam turbine to produce additional electric power. As can be expected, the primary
users of this cycle are the electric power utilities and independent power producers.
The HRSG or boiler used to produce the steam may be supplementary fired to
increase steam production and power generation capacity. Due to the imperfect
conversion of the thermal energy in steam to electrical energy produced by the
generator, typical efficiencies for the combined cycle are around 50 percent.
12-14
-------
STATIONARY GAS TURBINE
COMBINED CYCLE UNIT
ExhaintGue*
CompreMor Simple Cycle Gu Turbine Turbine
Slide 12-17
12.5
Formation Mechanisms
Nitrogen oxides (NOX) are products of all conventional combustion processes.
NOX is a collective term for nitric oxide (NO) and nitrogen dioxide (NO 2). NO is the
predominate form of NOX produced by GTs, with lesser amounts of NO2J however,
once emitted to the atmosphere, NO converts to NO2.
NOX emissions from gas turbines are generated in the primary combustion
zone of the combustor. Within the combustor, localized regions of stoichiometric and
near stoichiometric fuel/air mixtures exist at high engine power conditions, resulting in
high flame temperatures. These high flame temperatures are responsible for most of
the NOX emissions from gas turbines.
The amount of NOX formed by a gas turbine is unique to each engine model and
its operating characteristics. Gas turbines have a wide range of uncontrolled
emissions due to varying designs and operating requirements. Emission factors are
based on uncontrolled emission levels provided by manufacturers in ppmv, dry, and
corrected to 15 percent O2, corresponding to 100 percent output load and
International Standards Organization (ISO) conditions of 15°C (59°F) and one
atmosphere (14.7 psia) ambient pressure and the heat rate of the gas turbine. The
uncontrolled full load emission actors range from 0.397 to 1.72 Ib/MMBtu (99 to 430
ppmv) for natural gas fired engines and 0.551 to 2.50 Ib/MMBtu (150 to 680 ppmv)
12-15
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for DF-2. CO and UHC emissions, at full load, are usually nominal due to the
combustion efficiency and high firing temperatures. SO2 and particulate emissions
are also nominal due to the fact that GT fuels contain very little sulfur or materials
that will cause particulate formation. The primary characteristics that determine
the engine's NOX emissions are the combustor design, the type of fuel, ambient
conditions, operating cycles, and the output level as a percent of the full power output
of the gas turbine.
GAS TURBINE CHARACTERISTICS THAT
DETERMINE NOX EMISSIONS
Combustor Design
Type of Fuel
Ambient Conditions
Operating Cycle
Output Level
Slide 12-18
The combustor design has the greatest effect on the formation of NOX. One of
the functions of the combustor is to mix the fuel and air prior to and during
combustion. This mixing will have a direct effect on the local equivalence ratio of
combustion where the equivalence ratio is ratio of fuel to air based on the
stoichiometric air. An equivalence ratio of 1 indicates a stoichiometric fuel to air
ratio. If insufficient mixing occurs there can exist localized near stoichiometric
pockets of fuel and air which will burn hotter and create more NOX. Currently,
combustor design is undertaking a trend to lower the amount of NOX created in the
combustor. This technology is called low-NOx combustion and will be discussed in the
Control Option part of this section.
12-16
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THERMAL NOX PRODUCTION AS A FUNCTION OF FLAME
TEMPERATURE AND EQUIVALENCE RATIO
4500
Temperature
m
4000-
3500-
3000-
2500-
2000-
1500-
1000-
500-
0
Flame Temperature
Zone
400
300
200
100
Thermal NOx
Production Rate
(ppmv/ms)
0 0.5 1 15 !
Equivalence Ratio
Fuel Lean < > Fuel Rich
Slide 12-19
The type of fuel can affect the formation of NOX. Liquid fuels fired in GT's tend
to yield higher emission factors because of the burning properties of the fuel. Gas
fuels can be mixed completely with air and can burn in lean conditions, while liquid
fuels burn as droplets that burn at near stoichiometric air, and therefore produce
more thermal NOX.
Ambient conditions affect the emissions of gas turbines in several ways. The
temperature and pressure can affect the compressor inlet temperature, which will
affect the thermal NOX production by changing the firing temperature of the
combustor. Humidity also affects the emissions of GT*s by lowering the flame
temperature. The water in the air acts as a heat sink and lowers the flame
temperature in the combustor lowering the thermal NOX formation rate, this effect
operates on the same principal as water/steam injection for NOX control.
12-17
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EFFECT OF HUMIDITY AND
TEMPERATURE ON NOX
60'
50-1
O 4Q.
•o
c
S20H
w
110'
0% Relative Humidity
100% Relative Humidity
i I I 1 I
20 40 60 80 100
Ambient Temperature (*F)
120
Slide 12-20
Operating cycles affect NOX emissions from a gas turbine at full power.
Regenerative cycle gas turbines typically have higher NOX, typically by a factor of 2
at full power, than a similar simple cycle gas turbine. This is due to the higher
combustor inlet temperatures associated with this cycle. In addition, cogeneration
cycles and combined cycles which use duct burners to add energy to the exhaust gas
have an increased NO* emission rate on a mass basis. The operation and control of
duct burners is driven by measuring the flue gas temperature and comparing it to the
optimum temperature. The firing rate would be expected to vary with the load on the
turbine. Currently, duct burners are available which will emit approximately 0.1
pound of NOX per million Btu (Ib NO^/MMBtu) of natural gas burned.
The gas turbine power level also affects the emissions from the engine. As
power increases, firing temperature and flame temperature also increase. When the
engine is at full load, the flame temperature is hotter and therefore can support
nearly complete combustion with very low CO emissions. At the same time, the
higher temperatures increase the rate of thermal NOX production.
12-18
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12.6 Control Potions
CONTROL OPTIONS
Fuel Switching
Water/Steam Injection
Fuel Emulsion
Combustion Modifications
Selective Catalytic Reduction
Oxidation Catalyst
Slide 12-21
Fuel Switching
Fuel switching is predominately conducted to lower the sulfur and particulate
content of the fuel, and therefore the sulfur dioxide and particulate emissions from the
gas turbine. Most distillate fuels and natural gases have negligible sulfur and
particulate contents, and therefore have virtually no sulfur dioxide and particulate
emissions. However, some gas turbines may use a lower distillate fuel or a residual oil
to fire the gas turbine for short period of time such as when there is a shortage of the
preferred grade of fuel.
Water /Steam Injection
Steam or water injected into the primary combustion zone of a gas turbine
engine provides a heat sink which lowers the flame temperature and thereby reduces
thermal NOX formation. This injection is described by the water-to-fuel ratio (WFR)
evaluated on a mass basis (Ib water or steam injected per Ib fuel consumed). For
water injection, the control system would require a water purification system,
pump(s), water metering valves and instrumentation, turbine-mounted injection
nozzles, and any necessary interconnecting piping. A steam injection system would
require the same items except a steam generator would replace the pump(s).
The WFR is the most important factor affecting the performance of steam or
water injection. The injection rate is directly related to the NOX abatement potential.
The higher the WFR, the higher the possible NOX abatement. For gas-fired units,
WFR's for water and steam range from 0.33 to 2.48 to achieve controlled NOX
emission levels ranging from 25 to 75 ppmv, corrected to 15 percent O2. For oil-fired
units, WFR's for water and steam range from 0.46 to 2.28 to achieve controlled NOX
emission levels ranging from 42 to 110 ppmv, corrected to 15 percent 62- Water-
based WFR's are usually lower than the steam WFR for the same NOX abatement.
The latent heat associated with water injection increases the heat sink capability of
water injection and therefore lowers the required WFR for a given NOX reduction level.
12-19
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From available gas turbine data, steam/water injection is used to achieve NOX
removal efficiencies of 70 to over 85 percent from uncontrolled levels.
The type of fuel burned in the turbine affects the performance of steam or
water injection. In general, lower controlled NOX emission levels may be achieved
with gaseous fuels than with oil fuels. For turbines firing distillate oil fuels,
steam/water injection has the effect of increasing the conversion of fuel bound
nitrogen to NOZ. This would not be anticipated to affect the emissions from gas
turbines (GTs) which burn fuels with fuel bound nitrogen levels of typically less than
0.015 weight percent.
Water and steam injection do affect the performance and maintenance of the
gas turbine. Since gas turbine power is based on mass through-put, the power output
of the engine will increase from the use of water or steam injection. Also, the percent
overall efficiency will decrease. For water injection, the fuel energy required to
vaporize the water in the turbine combustor results in a larger loss than for steam
injection. The change in output and efficiency will change depending on the WFR and
the whether the injection fluid is steam or water. In general, a WFR of 1.0 with water
causes a 5 percent increase in power output and less than 3 percent loss of overall
efficiency. Water or steam injection can increase erosion and wear in the hot section
of the turbine, thereby increasing maintenance requirements. The impact depends on
the WFR and the model of gas turbine. Some manufactures do not recommend a
short time between inspections for water or steam, and others recommend decreased
inspection intervals for water injection only.
Maintaining the water/steam injection system is critical to GT operation and
emission control. If a WFR is too high, this can decrease flame stability. If a WFR is
too low, this can hamper NOX reduction. Also, water purity is extremely important to
combustor and turbine maintenance. If the water is not clean enough, the
contaminants can erode the combustor or turbine more quickly than normal
operation. The water purification is usually a separate on-site plant with its own
operators and support staff. Steam injection usually does not require the same level
of purification due to the distillation that occurs during steam, production.
Fuel Emulsion
The use of a water-in-fuel emulsion is a more recent NOX control technique
developed for the gas turbine industry. The process reduces NOX by lowering the
peak flame temperature in precisely the same manner as steam/water injection
discussed above. The water-in-fuel suspension allows a more ideal heat absorption to
occur due to both the homogeneous nature of the emulsion and the ideal location of
the water in close vicinity to the burning fuel droplet. Additionally, the process
creates the emulsion prior to injection and combustion. In contrast, the steam/water
injection fluid forms a heterogeneous post-combustion mixture where fuel
predominates in some areas of the flame and the steam/water predominates in
others.
12-20
-------
The fuel emulsion homogeneous mixture allows for a lower WFR than in
traditional steam/water injection. The emulsion WFR ranges from 20 to 50 percent
and is stabilized with chemical additives to maintain the emulsion at the high
temperature and pressure associated with injection. The process uses similar
hardware as in water injection, with additional equipment for the emulsification,
chemical stabilizer, storage, and injection systems (including metering valves and
instrumentation). This system can be retrofitted onto existing fuel delivery systems.
Similarly to water/steam injection, the emulsion process is more operator
intensive due to chemical addition and storage. Precise measurements of water, fuel
and chemical stabilizers are necessary to ensure proper GT operation and NOX
reduction. Again, a fuel-emulsion system would likely be a separate on-site facility
which prepares the emulsion just prior to combustion.
Combustion Modifications
The formation of NOX depends on the operating conditions of the combustor, so
it follows that altering the combustor to minimize the conditions which cause NOX
formation will lower the NOX emissions from the combustor. Several designs have
been developed to minimize the NOX formation mechanisms within the combustor:
Lean combustion and reduced residence time; lean premixed combustion; and dual
staged rich/lean combustion.
COMBUSTION MODIFICATIONS TO LOWER
NOX EMISSION RATE
Lean Combustion and Reduced Residence Time
Lean Premixed Combustion
Dual-Staged Rich/Lean Combustion
Slide 12-22
Lean combustion, coupled with reduced residence time of the fuel in the
primary combustion zone, operates with a low equivalence ratio. In conventional
combustors, the primary zone operates near equivalence ratios of 1 (near
stoichiometric fuel to air ratios) and near the maximum NOX formation rate. Lean
combustion operates with excess air, which acts similarly to water/steam injection in
that it provides a heat sink to cool the flame and reduce the NOX formation rate.
In a conventional gas turbine combustor, the fuel and air are mixed in the
combustion zone and fuel/air mixing and combustion take place simultaneously. In a
12-21
-------
lean premixed combustor, the fuel and air are premixed prior to combustion to ensure
complete mixing and the creation of a homogeneous mixture. This reduces the NOX
producing stoichiometric fuel sections. Also, the additional air acts as a heat sink to
maintain a cooler flame temperature, which limits the formation rate of NOX. The
implementation of pre-mixing a fuel lean mixture can greatly reduce the NOX
formation rates.
LOW NOm STAGING AND NOX CONCENTRATION PROFILE
NATURAL GAS FUEL
Slide 12-23
The level of NOX emissions reduction achieved by using lean premixed
combustion varies depending on the manufacturer and the type of combustor.
However, emissions at full power range from 25 ppmv, at 15 percent 0 2, to as low as
9 ppmv, at 15 percent O2. Most of the combustors designed to date are used on GT's
of 10 MW or larger. Only one of the manufacturers offers lean premixed combustors
on units smaller than 10 MW. Unfortunately, these emission reductions are capable
when firing natural gas fuel, and the reductions when firing oil fuels is not as
successful. Currently water/steam injection and water-in-fuel emulsion are the only
technologies to reduce NOX when firing oil fuels.
12-22
-------
The dual-staged rich/lean combustor configuration is a more complex system,
with the potential for a more stable flame. One configuration indicative of the basic
approach is a combustor developed for use on aircraft engines. This design
incorporates a rich burn area which incompletely burns the fuel, promoting flame
stability. The flame is then quenched and diluted with the pressurized air from the
compressor section of the engine. The combustion is then completed in the lean burn
section of the combustor. These three sections of the combustor employ variable
geometry to maintain the local stoichiometry within the design operating limits and
allow for optimization of airflow splits to each combustion zone. Currently, it is
estimated that this combustor can lower NOX emissions to one-tenth the present
level and is effective in limiting both fuel NOX and thermal NOX. However, this
technology has not been applied to gas turbines but has been designed for turbine-
based aircraft engines and is applicable to the gas turbine industry.
A GT incorporating combustion modifications would not need the vast support
of operators that the water/steam injection or fuel emulsion would require. Most
combustion modifications would operate on the same computer system with
additional software to monitor the staging operations.
Selective Catalytic Reduction
SCR is a post-combustion NOX control technology which employs a highly
reaction-specific process which reacts NO and NO2 with ammonia over a catalyst,
enabling the following reaction to occur.
SCR REACTION
NO +
NO2
1/2 O2 — »
+ 1/2 O2 —
3/2H2O
3/2 N2 + 3/2 H2O
Slide 12-24
The products of the reactions under idealized conditions are nitrogen and water.
However, under practical conditions, the reaction is not complete and results in some
unreacted ammonia (NHs slip) and NO in the exiting flue gas.
The purpose of the catalyst is to lower the temperature in which these
reactions occur. Typically these reactions will occur at 1800'F. Gas turbine exhaust
is on the order of 1000°F and would require a considerable amount of reheat fuel to
obtain the necessary temperatures for the reactions to occur. Although the catalyst
does lower the temperature at which the reactions will occur, the temperature
window is usually quite narrow, around 100 to 150 "F. There are several types of
catalysts available for use. Platinum, base metal oxides, such as titanium dioxide
12-23
-------
and vanadium pentoxide, and zeolite are all present day catalysts and each has a
specific and different temperature operating window.
The cycle and purpose of the gas turbine will determine which catalyst will be
the best for the systems. The zeolite catalyst can operate at temperatures on the
order of 1000'F and is effective for simple-cycle gas turbines because of the exhaust
temperatures of a gas turbine and the lack of an HRSG. Both the platinum and base
metal oxide catalysts have operating temperatures from about 300°F to 550*F and
would require the exhaust gas to be cooled. These catalysts are usually used when an
HRSG is present and are located in the HRSG boiler tube section at the appropriate
temperature.
The catalyst structure is placed with the exhaust structure or HRSG at the
appropriate location to ensure proper operating temperature across the catalyst.
The catalyst structure has several different designs, but each is designed to maximize
catalyst surface area and flue gas residence time over the catalyst as well as to
minimize the back pressure caused by the catalyst. Most catalysts sold today can
limit the back pressure to less than 2 inches water gauge.
POSSIBLE LOCATIONS FOR SCR UNIT IN HRSG
Clean Exhaust
Exhaust
Duct Burner Ammonia SCR Catalyst
Injection
Grid
Steam
7
forumj
rVS
INI
• Economizer
-Water
N
Superheater Evaporator
SCR Catalyst
Slide 12-25
12-24
-------
In addition to the catalyst, an SCR system has an ammonia injection grid. The
injection grid is placed upstream so that the ammonia will be thoroughly mixed with
the exhaust and a minimum amount of ammonia will escape into the atmosphere.
Ammonia is injected at a NH3/NOX molar ratio of about 1. Ammonia is stored in one
of two forms, an anhydrous gas under pressure or an aqueous solution of typically 27
percent ammonia by weight. The ammonia is vaporized and diluted, usually with air,
and added to the exhaust.
Due to the operating nature of SCR, it requires tight controls so that reduction
efficiency is maximized and ammonia slip is minimized. Most SCR systems use
CEMs to monitor outlet emissions such as NOX before and after the catalyst and
NHs after the catalyst to maintain proper operation. Due to the tightly controlled
nature of SCR, it is only applicable to steady stream operation (meaning a gas
turbine that operates at a constant load). An SCR system would also require
additional operators for the maintenance of the CEMs and the ammonia storage and
injection system.
Although the NOX reduction potential of SCR is on the order of 90 percent,
there are considerations which need to be mentioned. Some of the catalyst materials
are considered hazardous. Because the catalysts have a finite life, up to 10 years
with natural gas-fired units and as high as 6 years with oil fired units, disposal
considerations are of concern. Some catalyst manufacturers do recycle spent
catalyst, and others dispose of it. Usually, SCR is not used when firing the gas
turbine with high sulfur and high soot bearing fuels. Sulfur can react with the NHs to
form a salt which can coat the catalyst or the HRSG, decreasing the efficiency of
both. Soot can also coat the catalyst and decrease its reduction potential.
As mentioned above, SCR can reach NOX reductions of 90 percent. However,
only one facility in the U.S. uses SCR alone. All other SCR systems applied to GT's
use SCR mostly in combination with water or steam injection. Water and steam
injection can lower the NOX level to the 25 to 42 ppmv, at 15 percent C<2 range, then
SCR can lower the NOX to levels as low as 1 and 2 ppmv, at 15 percent C>2, but can
maintain NOX levels around 4 to 9 ppmv, at 15 percent 62-
Oxidation Catalyst
An oxidation catalyst can be used to lower the CO and UHC emissions. Most
oxidation catalysts are used in conjunction with water/steam injection and SCR and
are necessary due to high WFR which inhibits complete combustion. The oxidation
catalyst operates at high temperatures, on the order of 900 to 1000 °F, and is
usually located prior to duct burners, ammonia injection grid, boiler tubes, and the
SCR system. Oxidation catalysts do not use an additive and lower both CO and UHC
emissions to the 1 ppm level, at 15 percent O2, and usually do not require additional
operators.
12-25
-------
REFERENCES
1. U.S. Environmental Protection Agency. Alternative Controls, Techniques
Document — NOX Emissions from Stationary Gas Turbines. Research
Triangle Park, NC. Publication No. EPA-453/12-93-007, January 1993.
2. Report to U.S. Environmental Protection Agency. Data Analysis Report.
Prepared by Energy and Environmental Research Corporation, Durham, NC.
Contract No. 68-D1-0117. December 23, 1992.
3. U.S. Environmental Protection Agency. Standards Support and
Environmental Impact Statement, Volume 1: Proposed Standards of
Performance for Stationary Gas Turbines. Research Triangle Park, NC.
Publication No. EPA-450/2-77-017a, September, 1977.
4. Draft Report to U.S. Environmental Protection Agency. Methods to Reduce
NOX Emissions from EUAETC's. Prepared by Energy and Environmental
Research Corporation, Durham, NC. Contract No. 68-D1-0117, July 1993.
12-26
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CHAPTER 13. PACKAGE BOILERS
13.1 Introduction
13.2 Package Boiler Types
A, Fire tube
B. Watertube
C. Cast Iron Sectional
13.3 Emissions
Shde 13-1
-------
13. PACKAGE BOILERS
13.1
Introduction
In the late 1940's, the demand for industrial boilers combined with increasing
costs of field assembled equipment led to the development of the shop-assembled
package boiler.2 These boilers are used in manufacturing, refining, and mining
industries to provide steam> hot water, and electricity. Package boilers range in size
up to 600,000 Ib/hr of steam at conditions ranging from 2 psig and 215°F to 1800 psig
and 1000°F.4 In many applications, multiple package boilers are used to provide the
required steam to the process. This chapter will present the common package boiler
designs, and their pollutant emission characteristics. Normal operation and
maintenance are addressed in Chapters 14 and 19, respectively.
13.2
Package Boiler Types
There are three major package boiler designs: firetube, watertube and cast
iron. Each of these boiler types are described in the following sections.
Firetube
In a firetube boiler, the hot gases of combustion pass through tubes whose
outside surfaces contact the boiler water. An internally-fired firetube boiler is a boiler
with a furnace area surrounded by the water/steam filled pressure vessel.
FIRETUBE BOILER
-COOLED GASES
OF COMBUSTION
FIRE
TUBES
HEAT AND GASES
OF COMBUSTION
Slide 13-2
13-1
-------
The advantages of firetube boilers are that they are compact, low in initial
cost, and easy to modularize based on plant requirements. The disadvantages are
that they are slow to respond to changes in demand for steam (load) compared to
watertube boilers, and circulation is slower. Also, stresses are greater in firetube
boilers because of their rigid design and subsequent inability to expand and contract
easily. Firetube boilers usually range in size from less than 2 to 50 million Btu per
hour. Most industrial firetube boilers are either horizontal return tube (HRT), scotch
marine, or firebox.
A horizontal return tube (HRT) boiler has a separate furnace area that is built
of refractory brick. In a HRT boiler, the firetubes are horizontal. Typically, these
boilers were originally designed to burn solid fuels. The fuel firing burner assembly is
at one end, and the products of combustion are recirculated or "returned" to make
two, three, or four passes through the tubes surrounded by the boiler water. A HRT
is classified as an externally-fired firetube boiler since the furnace area is separated
from the heat transfer area. The boiler is encased with brick, and the furnace is set
on rollers or suspended on hangers to allow for expansion and contraction which
occurs when the boiler increases and decreases in temperature. These types of
boilers are found in older installation with some retrofitted to burn oil and/or gas, but
generally these boilers have been replaced with the scotch marine boiler design.
HORIZONTAL RETURN TUBE BOlLLERi
TOP ROW OF
FIRE TUBES -
FIRE DOOR
BRICK FURNACE
HORIZONTAL SHELL
SUSPENDED
BAFFLE
FIRE BRICK
COMMON BRICK
CONCRETE
GRATES
J
COMBUSTION
SPACE
Slide 13-3
13-2
-------
Scotch marine boilers are an example of internally-fired firetube boilers. The
original scotch marine boilers were used on ships and typically fire natural gas or fuel
oil to maximize the convenience of automatic operation. A scotch marine boiler has a
water cooled flue furnace within a horizontal shell. The flue furnace is composed of a
large tube or pipe, usually corrugated, that passes through the length of the shell.
The fuel burner is located at the front end of the flue so that the combustion flame
extends across most of the length of the flue. The combustion gases first pass
through the furnace tube, heating the bottom of the water basin, and then pass
through the fire tubes, heating the water in the basin. Scotch marine boilers may be
designed in two-, three-, and four pass units, as shown in Slide 13-4.
MULTIPLE PASS FIRETUBE BOILER ARRANGEMENTS 1
2-pass Dryback
3-pass Dryback
3-pass Wetback
4-pass Dryback
Slide 13-4
Typically, the scotch marine boiler is a forced draft configuration. Package
boilers typically have fully automated burner control tied to a single element of the
process (i.e. steam temperature). The burners described in Chapters 7 and 8 can be
applied in firetube boilers as well as watertube. For any application, the flame
pattern needs to be designed so that flame impingement on the internal boiler
surfaces is avoided.
13-3
-------
A firebox boiler is a firetube boiler in which the furnace is surrounded on the
sides by water leg area. The water space is extended downward so that the furnace
walls are surrounded by water. These flat, side water leg areas are supported by
staybolts to prevent them from bulging. These types of boilers are no longer built due
to the design integrity of the staybolts. Coal or other fuels (for example, wood waste
and paper waste) may also be burned depending upon the design of the furnace.
Early firebox boilers burned coal, but most firebox boilers still in operation have been
converted to burn natural gas or fuel oil for convenience.
FIREBOX BOILERi
FIRE TUBES
FURNACE WALL
WATER LEG AREA
BOILER
SHELL
STAYBOLTS
FIRE DOORS
Slide 13-5
13-4
-------
Watertube
The original design of a water tube boiler circulates the water through tubes
with the hot combustion gases passing over the outside surfaces of the tubes, as
shown in Slide 13-6. The advantages of watertube boilers are that they are rapid
steamers and respond quickly to changes in demand for steam due to improved water
circulation. They can withstand much higher operating pressures and temperatures
than firetube boilers. Their design is safer, since failure of one tube will not result in
an explosion, as is possible with firetube boilers. Additionally, they can burn a wide
variety of fuels. Also, watertube boilers expand and contract more easily than
firetube boilers. The disadvantage are that they are more expensive to install. They
also require more complicated furnaces and repair techniques.
WATERTUBE BOILERi
HEAT AND GASES
OF COMBUSTION
Slide 13-6
There are several common designs for watertube boilers. All of these
recirculating type of designs incorporate, risers, downcomers, a steam and water
drum and a mud drum as discussed in Chapter 2. The purpose of the steam and
water drum is to allow separation of the steam from the water. The purpose of the
mud drum is to collect the sediments found in the boiler water for removal during the
boiler blowdown.
13-5
-------
An "0" style boiler is a watertube boiler with a top steam and water drum and
a bottom mud drum. These are interconnected by banks of symmetrical tubes in an
"0" shape. The burner is in the center of the "0", as shown in Slide 13-7. This boiler
can be made with a waterwall furnace, which is a popular configurations for package
type boilers. An "0" style boiler commonly burns natural gas and fuel oil.
An "A" style boiler is a watertube boiler with a top steam and water drum and
two bottom mud drum. The steam and water drum is connected to the mud drums by
banks of symmetrical tubes in a "A" shape. This is a popular configuration for
package types.
A "D" style boiler is a watertube boiler similar to the "O" style except that the
steam-generating tubes on one side are extended to leave an open area close to the
center. This area is for the combustion of the fuel. The two sides are separated by a
baffle so that the gases pass to the rear on the combustion side and then turn back
toward the front for the convection side. There is either a top or side outlet for the
gases to leave the unit.
WATERTUBE BOILER CONFIGURATIONSi
STEAM AND
WATER DRUM
WATER
TUBES
STEAM ANO
WATER DRUM
OPEN AREA
FOR COMBUSTION
MUD DRUM
• MUD DRUM
•A" STYLE BOILER
OPEN AREA
FOR COMBUSTION
MUD DRUM
STEAM ANO
WATER DRUM
- STYLE BOILER
OPEN AREA
FOR COMBUSTION
•0- STYLE BOILER
Slide 13-7
13-6
-------
Cast Iron Sectional Boilers
In cast iron boilers, the hot gases pass through tube sections surrounded by
water circulating outside the tubes. These individual sections are interconnected
to form one unit. The primary advantage to sectional boilers is the ability to
assemble the boiler in locations where access is limited (i.e. building basements).
The units are constructed of cast iron rather than steel. The leading cause of
failure in cast iron boilers is the corrosion and failure of the connection of these
sections. Cast iron boilers are used to produced either low-pressure steam (15
psig) or hot water, and range in size from 30,000 to 10 million Btu per hour. Thus,
cast iron boilers are most commonly used in domestic heating or small
commercial applications.3
CAST IRON SECTIONAL BOILERi
STEAM
HEADER
WATER LEVEL
GAUGE
GLASS
DOORS
HEAT AND GASES
OF COMBUSTION
EXTERNAL
MUD DRUM
CAST IRON BASE
Slide 13-8
13-7
-------
A push-nipple cast iron section boiler contains a hollow cast iron section
joined with tapered nipples and pulled together with tie rods or bolts, as shown in
Slide 13-9. These cast iron sections are individually connected to the manifold; if a
section develops a leak, the boiler must be dismantled to replace the individual
section.
An external header cast iron sectional boiler contains cast iron sections
individually connected to external headers with screwed nipples. If a section in
the boiler develops a leak, individual section can be replaced without disturbing
the other sections.
PUSH-NIPPLE CAST IRON SECTIONi
TIE ROD INSERTED
THROUGH EYES PULLS
SECTIONS TOGETHER
PUSH NIPPLE
HOLLOW
CAST IRON
SECTION -^
STUDS FOR
BETTER HEAT
TRANSFER
PUSH
NIPPLES
EYES FOR
TIE ROD
Slide 13-9
13-8
-------
13.3 Emissions
The emissions from a package boiler depend on the fuel being burned and the
design of the boiler. The emissions from package boilers include NOX, SOX, CO, total
hydrocarbons (THC), particulate matter, and trace elements. The emissions from
watertube boilers has been given in the previous chapters dedicated exclusively to
natural gas-fired, oil-fired, and coal-fired boilers. In slide 13-10, a summary of the
emissions measured from firetube boilers during an EPA study is presented. The
results have been normalized on a pound of emission of the pollutant per million Btu
per hour thermal input (Ib/MMBtu).
FIRETUBE BOILER EMISSIONS5
NOX CO THC
Fuel (lb/MMBtu^a (Ib/MMBtu) (Ib/MMBtu)
Natural Gas 0.07 to 0.13 0.0 to 0.784 0.004 to 0.117
Distillate 0.11 to 0.39 0.0 to 0.014 0.012b
Fuel Oil
Residual 0.21 to 0.39 0.0 to 0.023 0.002 to 0.014
Fuel Oil
a To conven to ppm @ 3% (>>, multiply by the following: NOx, 790; CO 1300; THC, 2270
b Single data point
Slide 13-10
13-9
-------
REFERENCES
1. Wilson, R. Dean, Boiler Operator's Workbook, American Technical Publishers,
Inc., 1991.
2. Elliott, Thomas C., Standard Handbook ofPowerplant Engineering, McGraw-
Hill, Inc., 1989.
3. "Fossil Fuel Fired Industrial Boilers - Background Information", Volume 1:
Chapter 3, EPA-450/3-82-006a, March, 1982.
4. Steam, Its Generation and Use, 40th Edition, Babcock & Wilcox, 1992.
5. "Alternative Control Techniques Document — NOX Emission from
Industrial/Commercial/Institutional (ICI) Boilers," US EPA, EPA-453/R-94-
022, March, 1994.
13-10
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CHAPTER 14. NORMAL OPERATION
14.1 Introduction
14.2 Maintaining Suitable Combustion Conditions
A. Fuel Supply
B. Combustion Air Supply
C. Flame Appearance
14.3 Monitoring Combustion
A. Combustion Air Flow
B. Combustion Air Temperature
C. Combustion Air Pressure
D. Combustion Fuel
E. Combustion Flue Gas Monitoring
14.4 Maintaining Steam Temperature and Pressure
14.5 Maintaining Suitable Feedwater Conditions
14.6 Monitoring the Steam/Water Circuit
A. Regular Operation/Maintenance
B. Low Water Level Concerns
C. High Water Level Concerns
14.7 Controlling the Steam Temperature
A. Desuperheater
B. Burner Tilt
C. Flue Gas Recirculation
D. Soot Blowing
14.8 Startup Procedures
14.9 Shutdown Procedures
Slide 14-1
-------
14. NORMAL OPERATION
14.1
Introduction
The boiler operator's primary duties when operating a boiler furnace are
safety, fuel efficiency, and meeting emissions standards. Safety is the boiler
operator's first consideration. The boiler operator prevents fires and explosions by
keeping the flame safety system in good working order. Secondly the boiler operator
optimizes furnace efficiency by adjusting equipment to maintain the proper ratio of
air and fuel to the furnace as needed to satisfy steam demand. Finally, the boiler
operator monitors flue-gas conditions at the stack to insure compliance with the
allowable stack emissions standards. The following discussion will address the
operating parameters an operator needs to monitor for normal operating conditions,
as well as start-up and shut-down conditions.
Since there are many types of boilers and they vary in size, capacity, design,
operating procedures, etc., this course will provide a general description of boiler
operation. The specific onsite training and manufacturer/vendor recommendations
should take precedence. The purpose of this chapter is to highlight the most
important operating parameters to monitor and control.
14.2
Maintaining Suitable Combustion Conditions
As discussed in earlier chapters, combustion is accomplished by mixing fuel
and air at elevated temperatures. The air supplies oxygen which unites chemically
with the carbon and hydrogen in the fuel to produce heat. Though most boilers today
control the combustion process automatically, it is important for the operator to
know what conditions are required for proper combustion and how to use the
equipment available to maintain these conditions. Suitable combustion conditions
result from monitoring the fuel supply, combustion air supply and flame appearance.
The supply of fuel to the boiler is as important as the supply of water for
steam generation. It is the responsibility of the operator to ensure a good quality fuel
is supplied to the boiler at all times.
FUEL SUPPLY
Coal
Oil
Gas
Slide 14-2
14-1
-------
Coal
If it ia a coal burning plant, the level of the coal bunkers should be checked at
the beginning and end of the shift. The conveying equipment should be checked for
proper transport of coal and wear as coal is very abrasive. If the boiler is a stoker
type (retort, traveling grate, or vibrating grate) then the level of coal in the hopper
must be sufficient to feed the grate evenly during the combustion period. When
burning coal the ash is usually discharged into an ashpit located below the boiler. The
ashpit is usually big enough to hold the ash that is produced during one eight hour
shift, however, it must be emptied frequently as an excessive amount of ash or refuse
in the furnace ashpit will blank off the air and cause the grates to overheat.
When burning pulverized coal, the coal is supplied to the burners through
pulverizing mills. On units using pulverizer mills, the feed to the mills is controlled
automatically in response to steam demand. Most mills require very little
maintenance. However, if the mill becomes excessively noisy or the fuel supply to the
burners becomes erratic, then the mill must be taken out of service and inspected.
Oil
If burning oil, the level in the supply tanks should also be checked at the
beginning and end of a shift. If it is necessary to switch fuel oil tanks during a shift, a
sample must be taken from the tank that is to be used (prior to switching) to check
for water or other contaminants. Fuel oil comes in six grades numbered 1 to 6. No. 1
is the lowest viscosity and No.6 is the highest. When fuel oils 1,2, or 3 are used no
preheating is required. When using fuel oils 4, 5, or 6 steam or electric heating coils
are usually placed in the storage tanks to heat the fuel so the viscosity is low enough
to be atomized properly at the burner tip. Most fuel oil supply systems have duplex
strainers installed between the storage tanks and the suction side of the supply
pumps. These strainers should be switched and cleaned by the operator at least once
a shift or more often if required. The burner tips should be cleaned and inspected at
least once a day when firing 24 hours a day.
Gas
Gas fuels are available as natural, manufactured, oil gas and by-product gases
such as coke-oven, blast-furnace, and refinery gas. Gas is supplied to the boiler house
via pipelines and the pressure in these lines is either above or below that which is
required by the burner. If the pressure is above, then the gas to the burners must go
through a reducing station. If it is below, then the gas must go through a booster
compressor. The operator must ensure the supply pressure is constant and
sufficient to promote good combustion. The maintenance of gas burning equipment is
less than that for coal or oil but there are still areas which require the operators'
attention. The air-register operating mechanisms and gas regulators must be kept in
good operating condition. The burners must be kept clean and the boiler casing must
be checked to reduce air leakage to a minimum.
Slide 14-3 is a checklist summarizing the actions required to maintain fuel
supply systems.
14-2
-------
FUEL SUPPLY CHECKLIST
FUEL
Coal
Fuel Oil
Gas
EQUIPMENT
Coal Blinkers
Conveying Equipment
Coal Hopper
AshPit
Pulverizer Mills
Storage/Supply Tanks
Duplex Strainers
Burner Tips
Reducing Station or
Booster Compressor
Burner Air Register
Burner Tip
Boiler Casing
ACTION
Check level
Check for wear
Check level
Check level and empty
Visually inspect and
ensure constant supply
of fuel to burners.
Check level
Switch and clean
Clean and inspect
Ensure proper inlet and
outlet pressure
Inspect and check for
proper operation
Clean and inspect
Inspect for air leaks
FREQUENCY
Start and end of shift
Once a shift
Once an hour
Once a shift / as required
Once an hour
Start and end of shift
Once a shift / as required
Once a day
Once an hour
Once a shift
Once a day
Once a shift
Slide 14-3
14-3
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Combustion air is supplied to the furnace through natural draft or mechanical
draft. It is the operators responsibility to ensure an unrestricted flow of air through
the furnace and flue gas out of the stack.
COMBUSTION AIR SUPPLY
• Natural Draft
• Mechanical Draft
Balanced
Pressurized Furnace
Slide 14-4
Natural draft is produced by a properly sized stack which pulls air into the
furnace and discharges the products of combustion into the atmosphere. The draft is
caused because the hot gases inside the stack are lighter than the surrounding air
causing the gases to rise and exit. As the hot gases exit, air is pulled in, through the
furnace, to replace it.
There is usually a stack damper located between the base of the stack and the
outlet of the furnace. It is the operators responsibility to make sure the damper is
positioned properly to balance the flow of air with the fuel so good combustion can
take place. If the damper is fully open and draft is still low then the following
conditions could exist:
1. Boiler passes covered with soot, slag, or fly-ash,
2. Defective or shifted baffles restricting the flow of gases.
3. Air leaks.
4. The stack damper out of adjustment even though the outside arm
indicates it is full open.
5. The flowmeter is out of adjustment and the boiler is operating at higher
rates than indicated.
Boilers may operate with a furnace pressure that is positive (higher than
atmospheric) or negative (less than atmospheric). Natural draft furnaces are
negative pressure furnaces while mechanical draft furnaces may be either positive or
negative. Mechanical draft is produced by two methods. The first method is known
as Balanced draft, in which a forced draft fan delivers air to the furnace and an
induced draft fan produces the draft to remove the gases from the unit. These types
of boilers commonly operated at a negative pressure ranging form -0.1 in to -0.5 in of
14-4
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water. In very large boilers, furnace implosions can occur if the boiler I.D. fan is
providing excess suction when the boiler is at low load.
The second method is known as a Pressurized furnace, in which a forced draft
fan is used to force air into the furnace, producing a positive pressure, and cause the
hot gases to flow through the unit and out the stack. The operating pressure in a
positive pressure furnace may vary from 5 in. to 25 in of water.5 Pressurized
furnaces are associated with smaller package firetube boilers and small to medium
package water tube boilers. These package boilers can be sealed with gaskets to
prevent loss of pressurized gases.
Centrifugal fans are generally used for these purposes and are driven by either
electric motors or steam turbines. The operator must ensure that the inlet and outlet
dampers to these fans are in good operating condition.
Bearings are the most important part of any fan. It is the operators
responsibility to make sure the bearings are properly lubricated. Some fans are fitted
with water cooled bearings. The temperature of these bearings must be checked at
least four times a shift and sometimes as often as once an hour. If a rise in
temperature is noticed, check the cooling water supply to the bearing. If the
temperature exceeds recommended limits, then the fan must be taken out of service
and inspected. Induced draft fans which are located in the gas stream are subject to
fan blade erosion due to the fly ash in the gas. The blades should be periodically
inspected and repaired or replaced when necessary.
FLAME APPEARANCE
• Length
• Color
• Shape
• Stability
Slide 14-5
An operator must be aware of proper flame appearance during periods of
normal operation with good combustion. The following is a brief description of what to
look for when burning coal, oil, or gas fuel.
On a traveling grate or retort fed furnace, it is important to maintain an even
distribution of coal over the grates. The fire, then, should appear bright and even with
no dark "holes" which could indicate poor distribution or areas of wet coal. A hole in
the fire is an area on the grates where the fuel bed is very thin or an area where bare
grates are exposed. Grates which may not have adequate protection from the radiant
heat in the furnace may be damaged by overheating. In addition, holes in the fire are
the path of least resistance for the combustion air and thus other areas on the grate
become oxygen starved and may create clinker.
14-5
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When operating a pulverized coal furnace the flame length is important. It
must be long enough to allow for complete combustion of the fuel but must not be long
enough to strike the furnace walls as this will cause overheating of the area it is
striking as well as cause slag deposits. If the mixture of coal and primary air becomes
too lean, the flame will leave the burner tip and then return. This is a dangerous
condition as it could lead to loss of ignition. To correct the condition, decrease the flow
of primary air.
Fuel oil is usually atomized with air or steam and, when properly mixed with
the primary air, burns a bright lemon yellow. The flame should appear even around
the tip of the burner. If not, it could indicate a plugged orifice in the atomizer. As with
pulverized coal, fuel oil burners should be adjusted so the flame does not contact any
of the boiler heating surfaces or the furnace walls.
Gas burners require proper mixing of gas and air to work efficiently. Flame
appearance is a poor way to adjust the air to the furnace. It is best to analyze the
flue gases for oxygen and carbon monoxide and regulate the air accordingly. Improper
mixing of air and gas could result in long flame travel causing the flame to hit the
heating surfaces. This can cause soot deposits and a smoking condition. If the flame
appears to pulsate, then the furnace draft may need to be adjusted.
Loss of ignition in the furnace is a dangerous situation as the continued feeding
of fuel into a hot furnace can lead to an explosion. For this reason flame scanners are
usually installed to monitor the fire. A flame scanner is a photo-electric eye
connected to the fuel supply trip. If no fire is detected, the supply of fuel to the boiler
is automatically shut off. If there is no flame scanner then it is the operators duty to
continually monitor the fire and shut off the fuel supply if there is a loss of ignition.
Draft differential, appearance of the fire, smoke emission, and furnace slag
accumulation are all indications of proper air supply. The draft gauge readings, wind
box pressure, furnace temperature, boiler outlet pressure, etc., should be noted during
times of normal operation with good combustion. These values can be used to
establish normal conditions so the operator can quickly detect trouble and make the
necessary adjustments.
14-6
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14.3
Monitoring Combustion
Efficient combustion is dependent on monitoring combustion air, fuel, and flue
gas analysis.
COMBUSTION AIR
Flow
Temperature
Pressure
Slide 14-6
Combustion air supplies the oxygen necessary for combustion. This air is
transported to the combustion zone through ducts. These ducts are usually referred
to as air ducts. On some boilers this combustion air has additional uses. For those
fuels which are pulverized (such as pulverized coal) a part of the combustion air may
be used to transport the fuel to the burners. The transport air is usually referred to
as "primary air". The remaining air required for combustion is usually called
"secondary air" and is transported separately to the burners.
There are many other boiler applications which also split the combustion air.
These applications may have primary, secondary, and tertiary air. The operator
must know the process application and the approximate required percentages of
each combustion air stream.
Combustion Air Flow
The operator's main operating concern with combustion air is to maintain a
proper amount for adequate combustion. On some boiler applications, the controls
will indicate a combustion air flow as well as fuel flow. However, unless the operator
knows the air flow required for the applicable fuel flow, an air flow indication will be of
little use. Therefore, operational data should be recorded and saved for future
reference. Some boilers have meters that match the steam flow with the air flow.
With this arrangement steam flow is considered an indication of fuel flow. With these
boilers, the operator can adjust the air flow (by hand for manual controls or adjust a
bias for automatic controls). The air flow and steam flow meters are calibrated by
boiler technicians. When the indication for air flow equals the indication for steam
flow, the operator knows that they are matched for efficient combustion.
14-7
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Combustion Air Temperature
Some boilers have air heaters which are used to preheat the air. This hotter
air improves combustion. The air heater absorbs heat in addition to that absorbed by
the water/steam absorbing surfaces (economizer, boiler, superheater, and reheater).
If the air heater were not present, the flue gases leaving the stack would be higher in
temperature and heat losses out the stack would be higher. However, care must be
take not to lower the flue gas temperature below the dewpoint of the flue gas.
Condensation of the acid gases onto the metal surfaces would cause corrosion. The
temperature of the combustion air and the flue gas is sometimes controlled by using
air bypass around the air heater. Thus, the operator must monitor the percentage of
by-pass air, the combustion air temperature, and the flue gas exit temperature.
Combustion Air Pressure
The air flow (and gas flow) through a boiler is dependent upon the available
differential pressure and pressure drops through the system. The available pressure
differential is supplied either by natural draft of mechanical draft as discussed
previously in this chapter. The pressure drops exist due to resistance to flow across
the air heater, burner, furnace, heat traps, etc. The operators should be aware of
approximate pressure levels and pressure drops of the air-flue gas system through
the boiler. Changes to the pressure drops may indicate problems. If the burner
pressure drop changes, burner combustion efficiency may be affected. Possibly the
registers on one or more burners are in the wrong position. An increase of pressure
across a convection heat trap (superheater or economizer) may be the result of
heavy fouling from the ash in the fuel. The operator must evaluate using the soot
blowers to clean the boiler surfaces. Cleaning the surfaces will also improve the heat
transfer.
Combustion Fuel
Any material that releases heat during a combustion process can be defined as
a fuel. Some fuels, however, are easier to burn than others. Depending upon the
physical characteristics and requirements of the fuel, different attributes of the fuel
may be measured. Some of these attributes are listed below fin Slide 14-7.
14-8
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FUEL MONITORING PARAMETERS
Fuel Type
Solid
Pulverized Coal
Stoker Coal
Refuse (Garbage)
Liquid
Oil
Chem By-Product
Gaseous
Natural Gas
Gaseous By-Product
Pressure Temperature
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Slide 14-7
Pressures and temperatures are usually inputs to the instruments for
metering flow. However, pressures are also inputs for the burner permissives of
burner safety system. Pressures and temperatures are not normally monitored for
solid fuels. There are, however, instruments that monitor the flow of solids in either
weight or volumetric terms. Both liquids and gases can be monitored in pressure,
temperature and flow. Piping for liquids and gases are designed for the maximum
expected pressures and temperatures. Also, the burner(s) have maximum and
minimum flow, temperature, and pressure limits. The burner safety system is set to
trip the fuel if these limits are not maintained, for whatever reason. The operator,
however, should be knowledgeable of these minimum and maximum temperature and
pressure limits and be prepared to trip the boiler.
Combustion Flue Gas Monitoring
From the combustion of fuel and air is the creation of hot flue gases. These flue
gases contain heat released from the combustion process. These hot flue gases give
up heat as they pass through the different components of the boiler (furnace,
superheaters, etc.). Flue gases exiting the stack contain heat that was not
transferred to the boiler or superheater. The heat in these stack gases is referred to
as "heat losses". The greater the temperature of the flue gases or the greater the
quantity of flue gases exiting the stack, the greater the losses. Heat energy that is
lost and not recovered are heat losses as previously discussed in the calculation of
boiler efficiency presented in Chapter 6.
14-9
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FLUE GAS ANALYSIS
02
C02
CO
NOx
S02
Slide 14-8
Flue gases are often monitored to evaluate the combustion process and the
effectiveness of the heat transfer to the steam. Flue gases are analyzed for excess
oxygen (O2) and carbon dioxide (CO2). Other constituents that require monitoring may
include carbon monoxide (CO), sulfur dioxide (SO2), and other jx>Uutants.
O2> CO2, and CO are used to measure the efficiency of the combustion process
and the thermal heat transfer between the hot flue gases and the steam. O 2 is an
indication of the excess air in the flue gases. CO is an indication that there is a lack of
oxygen for complete combustion. A boiler can not usually show an excess O2 and a
quantity of CO at the same time. Typically, the O2 will range from 2.5 to 3.5 percent.
A boiler operating with a large quantity of excess O2 will have a large quantity of hot
gases leaving the stack. The larger the quantity of excess O2, the larger will be the
losses of heat out of the stack, as shown in Slide 14-9.
CO2 is the molecular compound resulting from the combustion of carbon (from
a fossil fuel such as coal, oil, or gas). CO2 can exist with either O2 or CO but not with
both.
Flue gases may also be analyzed for pollutants in an effort to reduce emissions
from the stack. An example may be oxides of nitrogen (NOX) and SO2.
14-10
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Boiler Efficiency Based on Flue Gas Analysis
Excess Oxygen
Slide 14-9
14.4
Maintainine Steam Temoerature and Pressure
An operating boiler producing steam is a continuous process. Fuel, air and
water are supplied while steam and waste products (ash, flue-gases, water
blow-down) are discharged. It is the responsibility of the operator to keep these
materials flowing in the right proportions and as required to produce steam.
Many of these functions are performed automatically, but an operator is still
required to oversee the equipment. Strict supervision is required since much depends
on a continuous flow of steam from the boiler.
PRESSURE/TEMPERATURE CONTROL
A. Monitor Steam Pressure
B. Maintain Proper Fuel-Air Ratio
C. Monitor Superheater Outlet Temperature
Slide 14-10
A drop in steam pressure, as indicated by a steam pressure gage, shows the
operator that fuel must be increased to the boiler. Too much pressure indicates that
fuel to the boiler must be decreased. If the boiler is equipped with automatic controls,
14-11
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then the fuel flow is adjusted automatically in response to the change in steam
pressure.
Each time the rate of fuel supply is changed, the air flow must be changed
proportionally. Normally the automatic controls change the air flow to compensate
for load changes and to maintain the proper fuel-air ratio.
When operating a boiler with no superheater, the temperature of the steam
corresponds to the operating pressure. For example, a boiler operating at 600 psi with
no superheater will have a steam temperature of 486°F. If, however, the boiler is
equipped with a superheater then the superheater temperature must be monitored so
that it does not exceed the recommended design temperature.
Operator control of final superheat steam temperature is limited. The
operating pressure and corresponding saturated steam temperature along with the
actual superheater surface have the greatest effect upon the temperature of the
steam leaving the superheater. Some superheaters have an attemperator (also
called desuperheater) to control the steam temperature over the upper load range.
These attemperators, however, are designed during the boiler engineering phase and
are operated automatically. Operators can bias the operation of the attemperators
only slightly. If the "attemperation" of the superheater is done incorrectly, damage
can be done to the superheater surface. Options available to the operator include
burner tilt (if available), flue gas recirculation (if available) and soot blower operation.
These options are discussed in section 14.7.
14.5
Maintaining Suitable Feedwater Conditions
The supply of water to the boiler is a very important part of proper boiler
operation. The water supply must be heated and conditioned with chemicals to
prevent operating difficulties. The four main problems caused from inadequate water
treatment are (1) waterside deposits or scale, (2) waterside corrosion, (3) carry-over
or priming, and (4) caustic embrittlement.
BOILER WATER PROBLEMS
Deposits or Scale
Waterside Corrosion
Carry-over or Priming
Caustic Embrittlement
Slide 14-11
Scale is the deposit of solids on the heating surfaces. The formation of scale is
caused by the dissolved solids in the feedwater. As the water enters the boiler and
becomes hot and pressurized, these solids become insoluble and adhere to the heating
surfaces. The scale deposits form an insulating layer which retards the heat flow to
the water and can cause the metal to overheat, blister, and over an extended period of
14-12
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time, fail. Feedwater containing a high level of dissolved solids is considered "hard" and
must be controlled chemically. The addition of phosphate (PO4) and caustic helps
precipitate the dissolved solids and causes them to adhere less to the heating
surfaces. These solids usually settle in the drums and headers as "sludge" or remain
suspended in the water and are removed by blow-down (surface and bottom blow).
Conductivity of boiler water helps determine when a blow-down is required. The
higher the concentration of solids, the higher the conductivity.
Waterside corrosion is caused by low alkaline or acidic water, oxygen in the
water, or both. The boiler metal is converted into red or black powder (iron oxide),
which is washed away with the water. Over a period of time the metal thickness is
reduced and the stress in those areas is increased leading to eventual failure. Low
alkaline levels can be compensated for by the use of a lime-soda softener, addition of
alkaline salts, or by treating the make-up water with acid. Oxygen can be reduced by
heating and deaerating the feedwater and adding oxygen scavenging chemicals such
as sodium sulfite or hydrazine.
Carry-over or priming is what occurs when water is carried over with the
steam into the steam header or superheater. This is a hazardous condition as it could
cause damage to both equipment and personnel. It is caused by too many impurities
in the water, too high a firing rate, or foam. Foam is caused by solids or oil in the
water which form a film on the surface of the water causing bubbles to pile up rather
than bursting. As these bubbles pile up some are carried over into the steam line
bringing with them moisture and impurities. Proper testing and chemical treating of
the boiler water along with surface blowdown can help prevent this situation.
Caustic embrittlement is the weakening of boiler metal at joints, seams and
cracks due to long-term exposure to highly alkaline water. The condition is worse on
boilers with riveted joints but is still a concern on welded boilers especially where
there may be small cracks or rolled tube ends.
Water Sampling
The operator is responsible for taking water samples from the feedwater and
condensate systems and from the boiler. The sample should be taken just before or
at the time of blowdown. Samples should be taken on a regular basis and recorded for
comparison. As mentioned in Chapter 2, the samples should be tested for pH,
hardness, suspended solids, and dissolved solids and gases. All containers for
collecting samples should be kept clean and rinsed with the water to be sampled
several times before final filling.
Water Treatment
As previously mention in Chapter 2, there are various water treatment
techniques which may be used to maintain boiler water quality. Instructions for
feedwater treatment prepared by a feedwater chemist should be followed. For
chemically treated water systems, the operators are required to add the chemicals to
the feedwater system, inject chemicals into the boiler feedwater and perform the
required blow-downs. If water softeners and deaeraters are used then the operator
14-13
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must maintain the proper level of salt in the softeners as well as perform or monitor
the regeneration cycle. The water level in the deaerator is very critical and although it
is usually maintained automatically the operator must check the level visually at
least twice during a shift or as often as required. Since the deaerator holds the
feedwater supply, a low level could result in no feedwater to the boiler.
14.6
Monitoring the Steam/Water Circuit
Boiler water tubes for generating steam from water are required to be filled
with water at all times during boiler operation. Superheater tubes that add heat to
the steam generated in the boiler circuits require dry steam to be supplied at all times
during boiler operation. Operators must use a water level gauge to monitor the
operation of these water and steam circuits.
MAINTAINING WATER LEVEL
Regular Maintenance/Operation
Low Level Problems
High Level Problems
Slide 14-12
All boilers will have a water level gauge attached to the boiler. Some boilers
will have this water level signal transmitted to the operator location, such as a
control room.
Operator maintenance is important for accuracy of the water level indication.
Because there is no flow during normal operation of the water level gauge, the water
connection of the gauge tends to plug with boiler water solids and or chemicals. The
level gauge should be blown down regularly. The frequency of the water level gauge
blowdown depends upon the boiler operation, boiler water solids, and feedwater
chemicals. Some boiler operators blow down the water level gauges as much as once
per shift. All boiler drum level gauges should be blown down once per day.
The water level of the boiler must be maintained between low level limits and
high level limits. Most boilers have a drum level control which will automatically
control the feed water flow to maintain the drum level between these two limits. This
feedwater control will also maintain the correct flow of water to operate the boiler
with the actual steam flow.
Low Water Level Concerns
Minimum drum levels are required to assure that the boiler has an adequate
supply of water. Water is required not only for the generation of steam, but also for
cooling protection of the boiler surfaces. If the actual water level decreases below this
14-14
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minimum level, some or all boiler surfaces will not have water. The surfaces without
water will be destroyed.
When the water level is found to be below the minimum water level limit, STOP
the fuel and air supplies. If the drum level gauge does not register a water level,
STOP the feedwater flow. Adding feedwater to a hot dry boiler will add additional
thermal stresses to the drum material. Take the boiler out of service for a thorough
internal check by experienced boiler engineers to determine the extent of damage and
repairs necessary.
High Water Level Concerns
Maximum drum levels should not be exceeded. Higher than permitted drum
levels may cause carry over of water droplets with the steam. Water carried over in
the steam may reduce final steam temperature and be harmful to downstream
equipment (turbines, heaters, etc.). Any slugs of water put in motion by the steam
can cause water-hammer and rupture the pipeline.
For boilers with superheaters, this carryover of water droplets presents an
additional problem. Each water droplet contains solids at the same concentration as
the boiler water in the steam drum. When the steam passes through the
superheater, these water droplets will evaporate, leaving the solids to form deposits
on the inside of the superheater tubes. These solids reduce the transfer of heat from
the combustion gases through the tube wall and into the steam. The solids act like a
layer of insulation between the hot tube wall and the cooler steam. With this layer of
"insulation", cooling of the tube wall will be reduced resulting in overheating.
Solids from carry-over may possibly pass completely through the superheater
and into downstream equipment. Solids entering a steam turbine can damage the
turbine blades. Turbine repairs are not only expensive, but can result in long outages.
High drum level conditions can usually be reduced by decreasing the firing rate.
Steam bubbles below the water level will tend to collapse causing the water level to
fall. However, if the high drum level trips the fuel, the non-return valve (steam stop
check valve) closes to prevent back flow of higher pressure steam into the boiler (if
the boiler is supplying steam to a common header), heat may not be able to readily
escape water-steam enclosure. Keep fans operating and the pressurized vessel will
slowly cool. DO NOT re-establish a fire in the furnace until proper water levels are re-
established in the drum.
14.7 Controlling the Steam Temperature
Steam is superheated by adding heat to the saturated steam produced in the
boiler circuits. The saturated steam leaves the drum (or other steam space) and
travels through the "superheater" absorbing more heat. To control the final steam
temperature leaving the boiler unit, one needs to control the input of heat to the
saturated steam. The results of any adjustments to the steam temperature are
typically delayed due to the thermal capacity of the boiler elements.
14-15
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Superheaters are designed to absorb a certain amount of heat for each
steaming rate. Many of the conditions that determine the heat absorbed include the
type of fuel, the amount and temperature of flue gases flowing across the
superheater, and the size and the arrangement of the superheater surface. Most
superheaters are also designed to slightly modulate the temperature of the steam.
SUPERHEAT STEAM TEMPERATURE CONTROL
Desuperheater
Burner Tilt
Flue Gas Recirculation
Sootblower
Slide 14-13
Desuperheater
A desuperheater dilutes the temperature in superheated steam by spraying
"cold" water into the steam circuit. The spray water absorbs heat from the
superheated steam and is evaporated into steam. Conversely, the superheated
steam loses temperature when it comes in contact with the spray water. This de-
superheater can be located either at the end of the superheater or in between two
superheater banks. The de-superheater located at the end of the superheater is
called a "Terminal" desuperheater. Those located in between two banks are referred
to as "Interstage" desuperheaters. Desuperheaters can be supplied by most boiler
manufacturers. The de-superheater control can be set to "control" the steam
temperature at a desired set point (with-in design limits). The operators can make
small adjustments to this control.
Burner Tilt
Absorption of heat into steam can also be affected by temperature. If the flue
gases can be increased in temperature, the transfer of heat to the superheater will be
greater. Some Combustion Engineering boilers have "tilting" burners. These burners
have the ability to move the fire-ball up or down in the furnace. Moving the fire ball to
a lower position will decrease the temperature of the flue gases exiting the furnace
and likewise, decrease the superheater absorption. Moving the fire-ball higher in the
furnace will increase the temperature of the flue gases leaving the furnace and
increase the absorption by the superheater. Operators of units with tilting burners
have the ability to control superheater temperature with the tilting burners.
Flue Gas Recirculation
Superheater absorption can also be affected by the amount of gases flowing
across the superheater surface. Some B&W units have flue gas recirculation (FOR).
These FOR systems remove a certain amount of flue gases from the economizer gas-
14-16
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out flues and inject it into the furnace. This effectively increases flue gas flow across
the superheater surfaces without any increased firing. Increasing the flow rate
across the superheater increases the superheater steam temperatures. Operators of
B&W units with an FGR system have the ability to control superheat temperatures
at low loads. FGR is used for several conditions. Superheater steam control is only
one use.
Soot Blowing
One other important means of maintaining superheater temperature is to
keep the superheater surfaces as clean as possible. Firing fuels that leave ash
entrained in the flue gases may cause a build-up of an ash layer on the superheater
tube surface. Any layer of ash on the tubes will probably reduce heat transfer,
causing a decrease in superheater temperature. The operators will need to monitor
the superheater temperature and develop a soot blowing schedule to minimize the
layer of ash build-up on the superheater tube surfaces.
If an operator chooses to decrease superheat temperature, for whatever
reason, he has the option to let the superheater surface foul or become dirty from the
ash in the fuel. As the coating of ash builds, heat transfer will decrease and steam
temperature will also decrease.
14.8 Startup Procedures
The start-up procedures may divided into four stages, pre-startup inspection,
establishment of water level, light-off, and warm-up.
STARTUP PROCEDURES
Pre-startup Inspection
Establishment of Water Level
Light-off
Warm-up
Slide 14-14
Pre-startup Inspection
The pre-startup inspection will be specific to each boiler system, but at a
minimum it should include the elements of the ASME Recommended Guidelines for
the Care of Power Boilers. The following is a summary of the items included in the
guidelines.
14-17
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RECOMMENDED PRE-STARTUP INSPECTION CHECKLIST
Pressure Measurement Device Accuracy
Blowoff Valves Closed and Functional
Gauge Glass and shut-off valves
Infrared Detection System
Main Steam Valve Inspection
Safety Valves Inspection
Fans Operational Condition
Pumps Operational Condition
Water Conditioning System
Slide 14-15
All instrumentation and protective devices that provide the required margins of
safe operation should be checked and operable prior to starting the boiler. At least
one recently calibrated steam pressure gage should be properly mounted on the boiler
and ready for service. Pressure transmitters should also be calibrated for accurate
transmittal of the pressure signal to the control center.
Blowoff valves, including continuous blowdown valves, water column drain
valves, gage glass drain valves, gage cocks, feedwater supply valves, and feedwater
control valve should be closed and in good working order. Valves, if any, between the
steam drum and water column and gage glass shutoff valves should be locked or
sealed open. Gage glass and furnace infrared detection gear, water level indicators,
and recorders should be ready for use. The water level in the boiler should be lowered
by draining water from the boiler to check the action of the water level in the gage
glass.
Safety valves should be inspected externally to see that they are free to
operate and that their discharge piping and drain piping are open to atmosphere and
free to expand without imposing loads on the safety valve bodies.
Manual or motor operated main steam stop valve stems can be eased up just
enough to reduce thermal expansion stresses which could result as they go from cold
to hot. If the header system is not under steam pressure, the main steam stop valve
can be actually unseated and reclosed gently.
Fans and boiler feed pumps should be checked to ensure they are ready for
service. Chemical injection equipment should be check by actually pumping a small
amount of the water into the boiler. 5
Establishment of water level
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
14-18
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temperature differentials can cause thermal stresses in the pressure parts and if
severe, will limit the life of the pressure parts. Differentials up to 100°F are generally
considered acceptable. A third precaution 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 final precaution is to establish the correct water level before firing begins.
Light-off
After the boiler operator has completed the pre-startup inspection, the next
step is to begin the light-off or ignition of the burner. Most furnace explosions occur
during startup and low load periods. 4 Therefore, the most critical step of the lighting
the burner is to eliminate the combustible gas prior to introducing a spark into the
furnace. As a minimum the boiler should be purged with a 25% of full load rated air
flow for five minutes. After the purge, the flue gas emission control equipment should
be place in service. Next, the fuel availability should be confirmed by opening the
manual valves in the fuel train and checking the level of the fuel. Finally, the burner
startup sequence should begin by activating the automatic controller. The controller
will first ignite the pilot flame and once that is confirmed by the flame scanner, the
main burner will be lit. Once the burner is lit, the burner controls should be left in the
manual setting at low fire to allow the boiler to heat slowly.
Warm-up
During the period when steam pressure is initially being raised, the boiler
should be checked carefully to see that it expands freely in the manner and direction
intended in its design. As steam pressure is increased, the water level should be
carefully controlled within normal limits. Prior to picking up load, it is desirable to
keep the water level near the lowest safe level to allow for thermal expansion of the
water as the steam generation rate increases. When raising the steam pressure on a
boiler not connected to a header system, the steam line should be warmed up along
with the boiler by the operation of drain valves to remove condensation and create
the desired flow of wanning steam.
In bringing a boiler on the line with other boilers on a header system, certain
precautions are necessary to avoid water hammer and excessive temperature
gradients in the piping. Adequate drainage and warming of the piping will eliminate
the risk of water hammer. The judicious use of bypass valves around main header
valves will avoid steep temperature gradients. Header drains should be operated.
The steam line form the boiler to the header should be brought up to temperature by
operating bypass and drain valves to create a backflow of steam from the header.
When up to temperature and line pressure, the header valve may be opened wide and
the bypass closed. The stem for the nonreturn valve should be back off to a position
corresponding to about 25% open until the boiler begins to supply steam to the
header, after which the stem should be backed off to the wide open positions. In the
absence of a nonreturn valve, the boiler stop valve should be opened slowly when the
pressure in the boiler and header are approximately equal.5
14-19
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14.9 Shutdown Procedures
In general, boiler shutdown procedures are less complicated than startup
procedures. Two shutdown situations may occur, a controlled shutdown or one
required in an emergency. During both procedures, the emphasis is on safety and
protection of the boiler materials.
During a controlled shutdown, the firing rate is gradually reduced. Once the
combustion equipment is brought to its minimum capacity, the fuel is shutoff and the
boiler is purged with fresh air. If furnace pressure is to be maintained, the fans are
shut down and the dampers are closed. The water side pressure gradually lowers as
heat is lost from the boiler. A minimal amount of air drifts out of the stack due to
natural draft when fans are not in operation. If inspection and maintenance are
required the draft fans remain on in order to cool the boiler more quickly. If a tubular
air heater is present, the air is by-passed around the air heater in order to cool the
boiler. The cool down rate should not exceed 100°F per hour of saturation
temperature change to prevent damaged due to thermal stress.s
In an emergency shutdown, the fuel is immediately shut off and the boiler is
purge of combustible gases. Additional procedures may apply to the fuel feed
equipment to insure safe conditions. The boiler may be held at reduced pressure or
may be completely cooled.
14-20
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REFERENCES
1. Woodruft, Everett B., Lammers, Herbert B. and Lammers, Thomas F.,
Steam Plant Operation, Fifth Edition, McGraw-Hill Publishing Co., 1984.
2. Boiler Technician, First and Chief, Naval Training Command, United States
Printing Office, 1972.
3. Elliott, Thomas C., Power Plant Engineering, McGraw-Hill Publishing Co.,
1989.
4. Steam, Its Generation and Use, 38th Edition, Babcock & Wilcox, 1972.
5. ASME Boiler and Pressure Vessel Code, Section VII, "Recommended
Guidelines for the Care of Power Boilers", ASME, New York, July, 1986.
14-21
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CHAPTER 15. AUTOMATIC CONTROL SYSTEMS
15.1 Introduction
15.2 Types of Analog Control Systems
A. Mechanical
R Hydraulics
C. Pneumatics
D. Discrete Electronic Components
E. Microprocessor
15.3 Types of Digital Control Systems
15.4 Automatic Control System Elements
15.5 Gas-side and Water-side Control Parameters
15.6 Single, Two, & Three Element Controllers
15.7 Microprocessor Based Control Systems
15.8 Control System Applications
Slide 15-1
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15. Automatic Control Systems
15.1
Introduction
The objective of this chapter is to give the reader a brief overview of automatic
control systems as applied to boilers. Examples are given to illustrate typical types
of hardware and applications.
When discussing controls, two distinct categories of controls must be
considered. The first is analog controls which can be described as modulating
controls. This type of control system controls flow, temperature, pressure, etc. over
the control range of the process. Examples in boiler control include feedwater control,
combustion control, and steam temperature control.
The second category is digital control which can be described as on-off controls.
This type of control system controls the starting and stopping sequence of various
pieces of hardware such as the boiler fans of the power plant. Digital systems
continuously monitor the status of the plant and can initiate actions (such as a boiler
trip) if the system determines that such action is required for safety reasons.
15.2
Tvoes of Analog Control Systems
There are many analog control technologies that can be used and many
classifications of categories of analog control systems. Some types of hardware have
or are becoming obsolete but many are in use today. In reality, most modern control
systems utilize a mixture of available technology. Unfortunately, different
manufacturers apply slightly different names to some systems but they can all be
grouped into the following categories.
Types of Analog Control Systems
Mechanical
Hydraulic
Pneumatic
Discrete Electronic Components
Slide 15-2
Mechanical
Straight mechanical control systems can be categorized as any controlled that
does not use external power (electricity, air pressure, etc.) for process variable
sensing or for motive power. Examples of straight mechanical control systems
include the Bailey Thermohydraulic Feedwater (Drum Level Control) Regulator and
the Copes Feedwater Regulator. The Bailey Thermohydraulic Regulator works on the
15-1
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principle of boiling water in a diagonal tube that is positioned near the end of the
steam drum. As the water level in the drum drops, the water in the diagonal tube is
turned to steam increasing the pressure in the tube which exerts a force on a bellows
that opens the feedwater control valve. As the water level increases, some of the
steam in the diagonal tube condenses decreasing the pressure in the tube which
allows the feedwater control valve to re-close. The Copes Feedwater regulator works
on the principle of expanding a metal rod as drum level drops which creates a force on
a linkage that opens the feedwater valve as drum level drops. The reverse happens
when drum level increases. These types of devices have the advantage of not
requiring external power for operation (continues to function on an electrical power
outage and does not require compressed air) but are not normally found in use today
except for small heating boilers.
Another example of a mechanical control system is the Fly Ball Governor used
for regulating the speed of a turbine. A flyball governor consists of two metal balls
mounted and attached on the sides of a shaft that rotates at a speed proportional to
the speed of the turbine. As the shaft rotates faster and faster, the balls are forced
away from the shaft by centrifugal force which actuates a linkage to close down on
the steam control valve to the turbine. The reverse happens as the turbine slows
down. Again, this type of speed controller operates without external power but has in
most cases been replaced with more modern and accurate technologies.
Hydraulics
The use of hydraulics (water and/or oil) for control systems has been around for
a long time. The primary benefit of hydraulics is that of being able to develop large
forces with a cylinder and precisely control the position of the cylinder without
overshoot. The use of hydraulic controls in modern power plants is primarily limited
to turbine governor controls.
Pneumatics
The use of pneumatics in controls enjoyed widespread use in the 1930's, 40's,
50's and into the 60's. Pneumatic controls can be categorized as any control system
that uses air pressure (usually 3 to 15 or 3 to 27 psi) for transmitter outputs and
control signals to drives and/or control valves. A pneumatic transmitter is a device
that converts a process variable (pressure, temperature, flow, etc.) to an air pressure
signal that is proportional to the process variable that is being measured. The
primary benefit of pneumatic controls was its immunity to electrical noise which is
interference from stray electrical currents from other control circuits and/or near-by
electrical power lines (a real problem in electric devices of that era) and its reliability.
Pneumatic devices (transmitters and controllers) are relatively immune to failures
caused by high temperature when compared to electronic devices. Another inherent
advantage is the ability to provide an emergency power back-up system in the form
of an air storage tank. A disadvantage of pneumatic controls is the relatively high
cost of clean dry compressed air and control component calibration drift and lack of
flexibility when it comes to making changes.
15-2
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Discrete Electronic Components
With the advent of relatively reliable and inexpensive diodes (a two terminal
solid state semiconductor device that permits current flow in one direction only) and
transistors (a three terminal solid state semiconductor device which may act as an
amplifier or a switch) that discrete component electronic control systems (a control
system made up from a large series of transistors and diodes) became prevalent. In
this vintage of analog control systems, the transistors were used as analog devices
(amplifiers). When used in this mode, they are subject to drift (calibration shift) due
to ambient temperature changes and aging, and do fail (usually instantaneously and
with no warning). The transistor control systems were subject to interference from
electrical noise which is very difficult to control particularly in a power plant. The
advantages of discrete component electronics is their rapid speed of response, ability
to package relatively large control systems in a small volume, and the low cost of
system power when compared to the cost of clean dry compressed air.
15.3 Types of Digital Control Systems
As is the case with analog controls, there are many types of digital controls.
Types of Digital Control Systems
Straight Mechanical
Hard Wired Interlocks
Relay Systems
Discrete Component Electronic
Microprocessor
Slide 15-3
An example of straight mechanical interlocks can be where the hand
actuating levers of two valves are oriented (perhaps by linkage or cams) so that one
valve must be opened before the hand lever on the second valve can be moved. In
other words the second valve is interlocked to the first in such a fashion as to prevent
the second valve from being manually actuated unless the first valve is open.
Hard wired interlocks are frequently used in motor control circuits. For
example, it is undesirable to start or allow a forced draft fan to operate unless the
corresponding induced draft fan is running. A contact from the I.D. fan starter or
breaker is normally wired into the starting circuit for the corresponding F. D. fan in
such a way as to not permit starting of the F. D. fan unless the starter or breaker for
the I. D. fan is closed. The same contact will open if both fans are in operation and
the I. D. fan is tripped thus causing the F. D. fan to trip.
15-3
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Relay type interlocking systems have been in use for many years and are
still common in the modern power plant. Electrical relays consist of an electrical coil
that when energized, changes the state of one or many electrical contacts from open
or closed to the opposite state when the coil is energized. The coil of the relay may be
wired so that it energizes when a certain condition exists such as a pressure greater
than a certain value or the limit switch of a certain valve indicates that the valve is
closed. It is possible to design relay interlocking systems by the use of many relays
to insure that equipment is started in a certain order and only after proper operating
conditions are proven. By the same token, equipment tripping can be initiated if
proper operating conditions are not maintained for normal operation.
The function of relay type systems can also be accomplished by the use of
discrete component electronic technology (see discussion in previous section).
Designs utilizing this technology whereby electrical relays are replaced by the use of
diodes and transistors were very prevalent during the 1960's and 1970's. In some
areas this technology is in use today.
The microprocessor is an equally powerful tool for interlocking and safety
systems. The advancement of electronic technology has lead to the development of
microprocessor based systems. A microprocessor system is basically a digital
computer. This technology is based on digital signals which are processed as ones or
zeros. One of the main advantages of using digital technology is the elimination of
signal drift which affords greater accuracy. Modern microprocessor based systems
also allow the control engineer to apply control strategies that were impractical to
implement with earlier systems. Most modern power plants utilize microprocessors
in combination with relays in boiler interlocking and safety systems.
15.4
Automatic Analog Control Svstem Elements
The elements of an automatic control system can be placed in the following
categories:
Automatic Analog Control System Elements
Process or Measured Variable
Controller
Hand/Auto Station
Operator Interface
Final Control Element
Slide 15-4
15-4
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The first component is the process variable or measured variable. For
example, drum level is the primary process variable for any feedwater control system
on a drum type boiler. The drum level is measured by a transmitter (or transmitters)
and a signal that is proportional to the drum level is sent to the drum level controller.
The second component is the controller. Depending on the type of control
system, this may be in the form of a pneumatic "black box" or in the case of a
microprocessor based system the controller may be "buried" within the processor
itself. The function of the controller is to determine what needs to be done to keep the
drum level as close to the desired level (set point) as possible. In this case this will
involve the determination of what position to place the feedwater control valve or
what speed to run the boiler feed pump.
The third component is the Hand/Auto Control Station. The purpose of this
device is to allow the operator to interrupt the desired action of the controller and
position the feedwater valve (or set the desired pump speed) where desired depending
on the operator's observation of operation.
The fourth component is the Operator Interface. The Operator Interface
can be any form of indication on the control panel that allows the operator to
determine the status of the system. This indication may be a gauge (round, vertical,
horizontal, etc.) or it may be a display on a CRT or TV Monitor. The second function
of the Operator Interface is to allow the operator to make changes to the system.
For example, set-points may be changed, the process variable may be controlled in
the "hand" mode, or start and stop signals may be initiated. All or portions of the
operator interface may be a part of the Hand/Auto Control Station.
Automatic Control System Elements
Process Variable
(Pressure, Temperature,
Level, etc.)
Controller
Hand-Auto Station
Operator Interface
(Display of Status and
Valves Plus Operator
Input Devices)
Final Control Element
(Valve, Damper Drive)
Slide 15-5
15-5
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The fifth component is the Final Control Element. This is the device that
determines what action is taken by the system to restore the process variable to the
desired value. In the case discussed above, it would be the feedwater control valve or
the feedwater pump speed controller.
15.5
Gas-side and Water-side Control Parameters
In a typical boiler application, there are many parameters that have to be
controlled to meet the desired unit output with maximum efficiency and safety.
Gas-Side and Water-Side Control Parameters
Steam Pressure
Drum Level (if applicable)
Main Steam Temperature
Reheat Steam Temperature (if applicable)
Furnace Draft (if applicable)
Desired Excess Air
Slide 15-6
Depending on the configuration of the boiler being controlled, main steam
pressure is normally controlled by adjusting the firing rate of the boiler. Drum level is
controlled by the adjustment of the feedwater flow rate to the boiler.
Main steam temperature may be controlled by means of adjusting the burner
tilts, regulation of an attemperator (normally a station where water is sprayed into
the main steam line to reduce steam temperature) or by varying the amount of flue
gas recirculation within the boiler. In some boiler designs, more or less flue gas flow
can be forced to pass over a portion of the superheater surface by modulating the
position of control dampers in the flue gas stream. Reheat steam temperature may
also be controlled by any of the above systems.
Furnace draft is normally controlled by operation of the F.D. fan and the I.D.
fans. Some I.D. fans are equipped with variable speed drive motors or variable speed
couplings between the fan motor and the fan shaft. If this is the case, the flue gas
flow is modulated by varying the fan speed. Other I.D. fans are equipped with inlet
dampers. In this case the position of the inlet damper is modulated to control the flue
gas flow through the I.D. fan.
The desired excess air is normally controlled by varying the air flow to the
boiler from the F.D. fans. The air flow is controlled in a predetermined proportion to
the fuel flow and perhaps trimmed as required and determined by the excess C>2 that
is measured in the backpass of the boiler. As with the I.D. fan, the flow of air
delivered to the boiler by the F.D. fan is varied by either varying the speed of the fan
or the position of the inlet damper on the fan.
15-6
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There are many subsystems associated with the combustion control system.
For example, in a pulverized coal fired plant, there are several control loops such as
primary air flow control, pulverizer outlet temperature control, coal feeder control,
etc. required for each pulverizer. In addition, the controls for each pulverizer must be
integrated into an overall system that controls the total fuel feed to the boiler.
15.6
Single. Two and Three Element Controllers
Control systems can be configured in many different ways to meet the
requirements of any particular system.The most common controllers are the single
element system, two element system, and three element system.
Control System Configuration
Single Element
Two Element Feed Forward
Two Element Cascade
Three Element
Slide 15-7
The single element control system is a system that has as an input one
measured variable only and the system output controls a single process variable. An
example of this is the single element drum level controller.
Single Element Feedwater Control
Drum Level
Transmitter
Controller
Feedwater
Control Valve
Slide 15-8
If the only measurement that can be made for a drum level control system is
the drum level, then the desired position of the feedwater valve for any given load (or
15-7
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for any status of load stability) would be determined from the drum level
measurement. If the drum level is high, the feedwater valve will move towards the
closed position. If the drum level is low, the feedwater valve will move towards the
open position. When the drum level is at set point, the position of the feedwater valve
will remain constant. Note that there are many times that the above may not be
desirable such as during load changes.
The two element control system has inputs from two measured variables.
In the case of a two element feedwater control system, this would normally be steam
flow and drum level. Note that it is possible to establish a correlation between the
feedwater valve position and steam flow for most "normal" operating conditions. A
two element feedwater control system would be then configured to first drive the
feedwater control valve to a particular position based on steam flow and then trim
this position (open a little more or close a little) from the position required because the
drum level is a little low or high at any given time.
Two Element Feedwater
Control (Feedforward)
Steam Flow
Transmitter
Drum Level
Transmitter
Controller
Feedwater
Control Valve
Slide 15-9
This system will operate in a superior manner over a single element system
particularly during load changes. As load increases, the feedwater valve opens a
proportional amount but the drum level transmitter may see a "swell" in drum level
and call for the feedwater control valve to close a small amount. The two signals will
cancel each other and the net effect will be to not change the feedwater valve
position. This is more desirable than to close the feedwater valve on a load increase
as would happen with the single element system. As the water level swell goes away,
the feedwater valve will go to the new desired position as determined by steam flow.
Therefore a two element feedwater control system will work in a far superior manner
when compared to a single element control system on any boiler where load swings
15-8
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are anticipated.
A second type of two element system is the cascade control system. In this
case, the second element is not used to directly determine the position of the final
control device but is used to determine the set point for a second controller.
An example of a two element cascade system is a steam temperature
control system. It is next to impossible to control the position of a spray water
attemperator valve by looking at final steam temperature only. The reason for this
is that there is such a large mass of metal in the secondary superheater that the
response time of the loop is extremely slow. That is to say, if the boiler is being
operated in a steady state mode and the spray water control valve is further opened
by some amount, it will be several minutes (perhaps as much as 10 minutes) before
the final steam temperature starts to drop. If the control system can only detect
final steam temperature and a high steam temperature is detected, the control action
will be to increase the spray water flow. Since no drop in final steam temperature is
observed within a short time period, the action of the controller will be to increase the
spray water flow some more. This cycle will be repeated until too much water is being
sprayed into the attemperator and the final steam temperature will start to drop
excessively and a new cycle will be started. This is called overshoot.
Spray Water Attemperator Water Schematic
Attemperator Water
Boiler
Drum
Attemperator Out
Temp, Transmitter
Final Steam
Temp, Transmitter
Spray Water
Attemperator
To
Turbine
Primary
Superheater
Secondary
Superheater
Slide 15-10
One method of overcoming the problem of overshoot is to measure the
attemperator outlet temperature. Note that the attemperator outlet temperature
will detect a temperature change in a very short time period if the amount of
attemperator water flow is changed. This input can be used in the following manner
by use of a cascade control system.
15-9
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The two element cascade control system utilizing final steam temperature and
attemperator outlet temperature as the two elements will be set up so that the
controller for final steam temperature will generate a set point for attemperator
outlet temperature. If final steam temperature increases, the controller will call for a
lower attemperator outlet temperature. The second controller for attemperator
outlet temperature will sense the change in set-point and open the attemperator
outlet valve until the new lower attemperator outlet temperature is reached. The
system is now essentially satisfied and eventually the final steam temperature will
drop to it's desired set-point without the overshoot experienced with the single
element system.
Two Element Steam Temperature Control (Cascade)
Final Steam
Temperature
Transmitter
I
Attemperator Outlet
Temperature
Transmitter
Steam Temperature
Controller
Attemperator
Controller
Attemperator Water
Flow Control
Valve
Slide 15-11
A three element control system utilizes three measured variables to
determine the proper action for the final control element. A three element feedwater
control system utilizes steam flow and drum level (as did the two element system)
with the third variable being feedwater flow. The two element system essentially
"assumed" that a certain feedwater flow would result from a particular feedwater
valve position. This may not always be the case. For example, if a second feedwater
pump is placed on the line at a given load, this will result in a higher pressure drop
across the feedwater control valve than with the single pump. The higher pressure
drop will result in a higher flow for the same position.
15-10
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In a three element feedwater control system, the steam flow and drum level
signals are combined as in the two element system, but now the output calls for a
particular feedwater flow and is no longer dependent on the relationship of feedwater
valve position and feedwater flow. The feedwater control valve will open or close as
required until the actual desired flow is established. With this system, when the
second feedwater pump is placed on the line, the system will immediately detect an
increase in feedwater flow when none was called for by the steam flow and drum level
signals, and the feedwater valve will close the proper amount to bring the feedwater
flow back in line.
Three Element Feedwater Control
Steam Flow
Transmitter
Drum Level
Transmitter
Feedwater Flow
Transmitter
Controller
Controller
Feedwater
Control Valve
Slide 15-12
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15.7 Microprocessor Based Control Systems
Microprocessor based control systems are applied to most new boiler control
applications and are in many cases being retrofitted to older existing units. There are
many advantages for using this technology in modern control systems.
Advantages of Microprocessor Systems
Flexibility
Improved Operator Interface
Reliability
Ability to Incorporate and Integrate Numerous
Systems in a Single Package
Slide 15-13
With the advent and development of microprocessor based control technology,
whole new vistas have been opened to control engineers. It is now possible to use
control strategies that more specifically meet the needs of particular processes
instead of a few "canned" strategies that were previously available (or at least
economical to implement). The control engineer can now experiment with different
control algorithms as a new system is brought on line and select the system that
responds in the most optimum manner. All of the above can be accomplished with a
few keystrokes instead of time consuming and costly wiring and/or pneumatic tubing
changes along with changes in control hardware.
It is also possible to bring to the operator a more useful and understandable
visual window to the process. Properly engineered screens on the CRT (Cathode Ray
Tube) can provide the operator with new understanding and instantly recognizable
status of the process at any given point in time. The screen displays are linked to an
operator keyboard for the initiation of operator inputs to the system.
Alarm systems can now monitor more points and prioritize all alarms so that
the operator can concentrate on the most important "problems" during an upset
condition and clean-up less important problems when time permits.
Data logging and event logging is another important capability of a
microprocessor based system. Selected data points can be periodically recorded for
future review of plant performance. Event logging records what happens and/or
actions taken by the operator during routine and upset conditions. These logs are
most useful to determine what happened during a plant upset.
As with any electronic component based system, instantaneous and
sometimes catastrophic failures of a non redundant system are possible. This
shortcoming has been overcome by the implementation of redundant components
and subsystems that continually monitor themselves and will continue normal
control by utilizing the back-up system prior to any process upset.
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The shear capacity and power of a microprocessor permits the integration of
the total process into a single control unit or at least what appears to be a single unit.
It is common practice to tie several microprocessor control units together by means
of data highways so that all controllers function as a single unit. In this manner it is
possible to control the entire steam-water cycle of a power plant by means of a single
system. This enables more precise control and programs can be implemented to
prevent unwanted outages due to a non-critical problem in a portion of the cycle.
15.8
Control Systems AoDlications
There are numerous applications for control systems in a power plant from the
most simple single element control loops to complex interrelated and integrated
systems which utilizes numerous measured variables and control system outputs to
achieve optimum operation.
Control Systems Applications
Boiler Combustion Controls
Boiler Feedwater Controls
Boiler Steam Temperature Controls
Boiler Draft Control
Feedwater Heater Level Controls
Hotwell Level Controls
Deaerator Pressure Controls
Air Heater Cold End Temperature Controls
Numerous Other Applications
Slide 15-14
The potential for control system applications in a power plant are numerous.
Wherever a valve exists or a control damper exists that must be positioned to control
a particular flow, temperature or level to maintain optimum operating conditions, the
potential for a control system exists. The advantage of an automatic control system
is that it is always alert (except in the case of a control system failure) and
constantly adjusting its final control element to maintain optimum conditions. By
integrating systems, it is possible to optimize overall plant operation in a manner
that is not possible with manual control.
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CHAPTER 16. INSTRUMENTATION: GENERAL
MEASUREMENTS
16.1 Introduction
16.2 Pressure Measurement
16.3 Temperature Measurement and Equivalences
16.4 Level Measurement
16.5 Flow Measurement
16.6 Weigh Scales
Slide 16-1
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16.1
16. INSTRUMENTATION: GENERAL MEASUREMENTS
Introduction
Instrumentation for measuring different properties of fluid and solid streams
are essential to all steam generating installations to ensure safe, economic and
reliable operation. Instruments can range from the simplest indicating devices to
complex automatic measuring devices. The fundamental purpose of the instrument
is to convert some physical property of the streams into useful information. The
methods used to obtain the measurement depend on available technology, economics,
and the purpose for which the information is being obtained.
There are many process variables that must be monitored in a power plant.
Pressure, temperature, level, flow, weight, voltage, current and power consumption
are a few. The degree of accuracy desired and the required readout location dictate
what type of sensors are used.
Test instrumentation, often portable, may be used to determine conditions
required to satisfy the boiler operator and to show that the design operating
conditions have been achieved. Instruments used for continuous measurement may
require compromises in accuracy for long term, dependable and reliable operation.
16.2
Pressure Measurement
Pressure and/or vacuum is a very important process variable in the power
plant cycle. At times, safety can be affected if proper pressures are not maintained
and plant efficiencies are dramatically impacted if the proper pressure levels are not
maintained. There are several devices available for measuring pressure.
Pressure Measurement
Pressure Gauges
Manometers
Pressure Transmitters
Draft Gauges
Slide 16-2
The pressure gauge is probably the most common device used to indicate
process pressure. Pressure gauges come in a wide variety of sizes and accuracies.
Most pressure gauges are of the bourdon tube type. Although improvements have
been made in construction and accuracy, its basic principle of operation remains
unchanged. A closed end oval tube in a semicircular shape straightens with internal
pressure. The movement of the closed end is converted to an indication (needle
movement). Pressure gauges can be liquid filled to aid in dampening of oscillations or
furnished with a snubber on the pressure connection to dampen high frequency
16-1
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pressure fluctuations. A disadvantage of the pressure gauge is that the operator
must be close to the point of pressure measurement in order to observe the reading.
It is possible to run a long pressure sensing line (say from the point of measurement
to the control room) but this practice is not commonly used for most applications
today because of the installation cost. Most modern control room designs do not allow
the running of high pressure sensing lines into the control room space. Most pressure
indications in the control room come from transmitted signals.
A manometer (normally a "IT tube filled with a liquid) is frequently utilized to
measure relatively low pressures in the inches of water range. Inclined manometers
can be used to accurately measure very low pressures in the 0 to 5 inch water
pressure range. Manometers are normally used for test purposes or for the
calibration of low range pressure transmitters.
A pressure transmitter is a device that senses pressure and develops an
output signal (normally pneumatic or electronic) that is linear to the input pressure.
Transmitter outputs are a relatively low level signal that can be safely brought into
the control room where the signal is directed to an operator interface (gauge or display
on the microprocessor CRT) and/or a controller.
Pressure measurement devices are most often used to indicate process
pressure. However, another use is when two pressure measurements are taken on
either side of a restricting device in a fluid stream (see section 16.5). The resulting
difference in pressure can be used to calculate flow. This is probably the simplest and
most economical method used to determine flow rates. This is an example of how one
process variable can be used to determine another.
16.3 Temperature Measurement and Equivalences
Depending on the temperature range to be measured and accuracy required,
there are a number of devices for sensing temperature and displaying the value to the
operator. These devices sense heat affected properties, such as thermal expansion,
radiation, and electrical effects, to determine the temperature of a substance.
Temperature Measurement
Human Hand
Liquid Filled Bulb & Tube
Liquid Filled Bulb & Gauge
Thermocouple with Readout Device
Resistance Temperature Detector with Readout Device
Optical Pyrometer
Slide 16-3
16-2
-------
The human hand is probably one of the best known methods for detecting
approximate temperature. If accuracy is not of prime concern, many operators "feel"
to determine whether a bearing is overheating or whether the fluid in a pipe is more or
less up to temperature. One advantage (or disadvantage) of using the hand for
temperature is the instantly recognizable high temperature alarm.
The liquid filled bulb and tube (thermometer) has been one of the most common
methods for displaying temperature providing that the temperature is somewhere
between the freezing and boiling point of the fluid in the thermometer. An advantage
of this device is its lack of requirement for external power, relative accuracy, freedom
from calibration, and ease of operator observation. A disadvantage of the
thermometer is that the operator must be close to the point of temperature
measurement in order to observe the reading.
The liquid filled bulb and gauge operates very similar to the thermometer
except the tube is replaced with a round dial (usually) gauge. This device may not
hold its accuracy quite as well as a thermometer but in other ways is very similar in
characteristics.
The thermocouple is the most common device to sense temperature in a power
plant. Temperature measurements using thermocouples are based on the discovery
that electrical current will flow in a continuous circuit of two different metallic wires if
the wire junctions are at different temperatures. An electrical voltage is generated at
the junction point of the two metals that varies according to the temperature of the
junction point. The voltage generated therefore becomes a function of temperature
and can be converted to a temperature readout. Thermocouples are available with
suitable materials and packaging to meet most power plant applications. A
thermocouple can be connected to a transmitter where it's milli-volt output is
converted to a 4 to 20 milli-amp signal or the milli-volt output can be directly
inputted to a microprocessor based system. In some applications, the thermocouple
is connected to a digital readout meter. Portable units are available where a hand
held unit is connected to a thermocouple for field checking of temperatures.
An RTD (Resistance Temperature Detector) functions similarly to the
thermocouple for many applications except instead of generating a milli-volt output,
the resistance of the RTD varies with temperature. The RTD can be connected to
transmitters, direct connected to a microprocessor, direct readout digital meters and
hand held units.
The optical pyrometer is a non-contact method for determining temperature -
that is, temperature can be sensed without direct contact of the sensor with the
process or device requiring monitoring. Optical pyrometers sense the properties of
the radiated wavelengths generated by the surface that it is aimed at and directly
correlates this to temperature. Most optical temperature sensing devices are hand
held and temperature is determined by aiming the sensor at the point where a
measurement is desired. This device is most useful for making spot checks of bearing
temperatures, motor temperatures, boiler casing temperatures, etc.
16-3
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16.4
Level Measurement
Level measurement has many applications in a power plant. Several different
methods can be utilized for detecting level in open tanks or pressure vessels.
Level Measurement
Float Type
Sight or Gauge Glass
Level Transmitter
Slide 16-4
Level of a liquid is often determined by the position of a float that moves up and
down with the level of the liquid. The motion of the float (mechanical position) can be
determined and correlated to the liquid level.
Level of a liquid in an open tank or pressure vessel can be determined in
several ways. One of the most simple is that of a sight glass or gauge glass. On open
tanks, the sight glass may only be connected near the bottom of the tank whereas,
for pressure vessels, it is necessary to connect the sight glass to both the top and
bottom of the pressure vessel.
A differential pressure transmitter, connected to a tank or closed vessel similar
to a sight glass, essentially measures the difference in pressure between the top and
bottom of a tank or pressure vessel. If the tank is open to the atmosphere, then the
transmitter need only be connected to the bottom of the vessel. This difference in
pressure can be directly correlated to the level of liquid in the tank or pressure vessel.
The transmitter measures the differential pressure and develops an output signal
(normally pneumatic or electronic) that is linear to the level. Transmitter outputs
are a relatively low level signal that can be safely brought into the control room where
the signal is directed to an operator interface (gauge or display on the microprocessor
CRT) and/or a controller.
16.5
Flow Measurement
The measurement of flow of liquids and gases is very important in a power
plant. Some of the more common methods for determining flow are discussed.
The flow of water flowing through an open channel can be determined by
measuring the height of the water in the channel. Since the water travels at a
relatively constant velocity in a particular channel, the flow is proportional to the
height of the water in the channel.
16-4
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Flow Measurement
Open Channel
Variable Area Meters
Pitot Tube
Differential Pressure
Turbine Meters
Slide 16-5
A variable area meter or a rotometer is a device usually utilized to indicate the
flow of liquids or gases. It consists of a gradually tapered tube mounted vertically
with the larger end up. The fluid flows upward through the tapered tube and suspends
a float which is submerged in the fluid. The float position is an indication of the flow
rate, and the greater the flow rate, the higher the float rides in the tube. The entire
fluid stream must flow through the annular space between the float and tube wall.
The tube is marked off" in divisions, and the reading of the meter is obtained from the
divisions at the reading edge of the float which is taken at the largest cross-section of
the float.
The pitot tube is a device that measures the "total head" (velocity head plus
static head) at one port and the static head at the other port. Head is defined as
pressure in this application. When the pitot tube is placed in a flow stream and aimed
in the upstream direction, the differential pressure measured between the two ports
can be correlated to the flow if the static pressure and temperature of the flowing
media is known. This device is used frequently for testing work but is also used in
some boiler combustion air flow measurements for on-line controls.
When a restriction such as an orifice, flow nozzle or venturi is placed in the flow
stream in an enclosed duct or pipeline, the restriction will create a pressure drop in
the line that is proportional to the square of the velocity. This principle is the most
frequent method used for the determination of flows in a power plant.
A turbine meter is a small turbine that is placed in the flow stream. As flow
increases the turbine will spin at increasing speeds. By measuring the speed of the
turbine, the flow is determined.
16.6
Weigh Scales
The most common application for weigh scales in a power plant is for
measuring coal flow although there are other applications. The coal feeder can
consist of load cells that determine the weight of coal on a section of belt in the coal
feeder. If the speed of the feeder belt is also measured, a calculation of coal flow can
be calculated.
16-5
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CHAPTER 17. ELECTRICAL THEORY
17.1 Introduction
17.2 Fundamental Parameters
A. Current
R Voltage
C. Other Parameters
D. Ohm's Law
E. DC Wattage or Power
F. AC Wattage or Power
17.3 Electrical Power Equipment
A. Motors
R Generators
C. Transformers
D. Other Equipment
17.4 Instruments and Meters
Slide 17-1
-------
17. ELECTRICAL THEORY
17.1
Introduction
A basic understanding of electrical principles is necessary for informed
operation, maintenance, and troubleshooting of boiler electrical systems and
generator systems. This learning unit will present the basic principles of electricity.
It will focus on the basic knowledge required for the understanding of transformers,
rectifiers, and electric generators.
BASIC ELECTRICITY
DC vs. AC Current
Ohms Law
Power
Electrical Phases
Motors and Generators
Transformers
Rectifiers
Slide 17-2
17.2
Fundamental Parameters
We will begin by defining electricity and some of its related properties. Initially,
we will focus on steady "direct current" (DC), such as that associated with battery
powered systems. By contrast, the other form of electricity is "alternating current"
(AC). This is the form of electricity produced by steam turbine generators.
Alternating current is the momentary flow of electrons in one direction and then in
the reversed direction at regular intervals of time. 1
17-1
-------
STEADY DC AND OSCILLATING AC ELECTRON FLOW
Slide 17-3
Current
Current is the flow of electrons. When we say, "electric current or electricity
can flow through a wire," we mean that electrons can flow through the wire. The
electrons of steady DC current flow in one direction.
Current can be thought of as the rate of electron flow, where one ampere is a
very large number of electrons per second. Current is measured in amperes or
amps. We will use the fluid flow analogy to help our understanding of electricity.2
Current is analogous to fluid flow rate, which can be expressed in gallons per minute
(gpm).
ELECTRICITY - FLUID FLOW ANALOGY
Parameter Electricity Fluids
Flow Rate
Driving Force
Electron Flow/Current
(amps)
Electrical Potential
Difference or Voltage
(volts)
Fluid Flow
(gpm)
Pressure
Difference
(psi)
Slide 17-4
17-2
-------
Voltage
We know that fluid flow is caused by a pressure difference, such as that
developed by a pump. The electrical driving force is called the electrical potential or
voltage difference. It causes current to flow through a conductor. Electrical potential
is measured in volts and is analogous to pressure, which can be measured in pounds
per square inch (psi).
The voltage of alternating current (AC) electricity periodically changes. AC is
the traditional form of commercial electricity which is produced by most steam
turbine generators and is delivered to customers through interconnecting electrical
transmissions lines (the grid). The voltages for standard AC electricity in the United
States oscillates at 60 cycles per second (60 Hz), where each cycle would correspond
to an oscillation occurring over 360 degrees.
VOLTAGE OSCILLATIONS OF ALTERNATING CURRENT
Slide 17-5
Because of the oscillations, the actual time-average AC voltages and the
corresponding AC currents have values of zero. However, conventional AC
instruments measure representative voltages and currents. The instruments are
designed to give "root-mean-square" values, which are the average of the square of
the values over time. It may be interesting to note that the oscillating features of AC
voltages and currents can be measured by osciDoscopes.
17-3
-------
Other Parameters
Conductors are materials with properties that permit the flow of electrons.
Materials are generally ranked according to their relative resistance to electrical flow.
Electrical resistance is generally measured in units of ohms.
OTHER BASIC ELECTRICAL PARAMETERS
Material Which Permits Electrons to Flow
Conductor
Resistance
Ohm
Insulator
Circuit
Measures Opposition to Flow
Unit of Electrical Resistance
Material with High Resistance
The Path of Electrical Current From
a Source Through Various
Conductors and Devices
Slide 17-6
The resistances of conductors depend upon chemical composition, size
(diameter), and length. Glass objects generally have enough electrical resistance to
be called insulators, whereas metal wires are called conductors. Large diameter
(small gauge) copper wires have much lower electrical resistance than thin copper
wires. Electrical conductors must be properly selected so that they will not overheat
and fail (melt) under high current conditions. The current carrying capacity of wire
conductors is dependent upon size (gauge) and electrical insulation design.
An electrical circuit is composed of at least one electrical source, various
conductors (or resistors) and/or other electrical devices (e.g., motors) which are
connected together. A battery or some other electrical source is required to provide
the voltage which will cause electricity to flow through a circuit.
Ohm's Law
Ohm's law establishes the basic relationship of steady electrical flow
[Steingress and Frost, 1991]. The electrical potential (measured in volts) is equal to
the current (measured in amps) times the resistance (measured in ohms). Ohm's law
uses "V" as the standard symbol for the voltage or electrical potential. The symbol
for current is "I", and the symbol for resistance is "R".
17-4
-------
OHM'S LAW
VOLTAGE-CURRENT RELATIONSHIP
Voltage = Current x Resistance
V= I x R
I = V/ R
Slide 17-7
If any two of these variables are known, the third can be found from Ohms law
by using simple algebra.
GRAPHICAL RELATIONSHIP OF VOLTAGE AND CURRENT BY OHM'S
LAW
V = Voltage (volts)
I = Amperage (amps)
R = Resistance (ohms)
= IxR
= V/R
Slide 17-8
Ohm's law can be conveniently used in steady applications which involve both
large and small electrical quantities. Many power applications involve high voltages,
measured in kilovolts (thousand volts) or megavolts (million volts). By contrast,
instruments often produce small voltage signals which are measured in millivolts
(one-thousandth of a volt) or current signals which are measured in milliamperes
(one-thousandth of an amp). It is recommended that conversions be made to the
standard units of volts, amps, and ohms before Ohm's law is used for calculations.
17-5
-------
DC Wattage or Power
The basic unit of electrical power is a watt. In power generation, we often are
concerned with large quantities of power which can be measured in kilowatts (kW,
thousand watts) or megawatts (MW, million watts). As described later, the
alternative units often used in AC electric generation applications are volt-amps
(VA), kilovolt-amps (kVA), and megavolt-amps (MVA).
Electrical power is generally defined as the product of the voltage times
current. The electrical power unit is a "watt" which has dimensions equivalent to a
volt-amp (VA). Other formulas are obtained using Ohm's law substitutions.
DC POWER RELATIONSHIPS
Power = Voltage x Current
P = V x I
P = (I x R) x I
P = (1)2 x R
or
P = (V / R)2 x R
P = (V)2 / R
Slide 17-9
The power relationships can be applied to the example of the resistance
heating of a conductor. If the resistance of the conductor and the voltage across it
can be calculated or measured, the rate of resistance heating can be determined.
17-6
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GRAPHICAL RELATIONSHIP OF POWER
p = Power (watts)
I = Amperage (amps)
V = Voltage (volts)
= IxV
= P/V
Slide 17-10
AC Wattage or Power
Alternating current or AC power is commonly encountered whenever power
must be conveyed over a distance. The previously developed DC power equations
require modification for AC power, as indicated in Slide 17-11.
17-7
-------
AC POWER RELATIONSHIPS
Power = Voltage x Current x Power Factor
P=VxIxcos0
P a (I x R) x I x cos 0
P = (1)2 x R x cos 0
or
P = Vx(V/R)xcos0
P = (V)2 / R x cos 0
Slide 17-11
For AC, power is expressed as voltage times current times the power factor.
The "power factor" is the correction factor required because the current and voltage
generally are slightly out of phase with each other, as shown in Slide 17-12. If the
current and voltage reach their maximum value at the same point in the cycle, they
are said to be "in phase". Since the voltage reaches its peak at a point earlier in the
cycle than the current in the figure below, the current is said to be lagging.
AC VOLTAGE AND CURRENT RELATIONSHIPS
(EXAMPLE OF CURRENT LAGGING)
90
180 270 380 450 540 630 720
Slide 17-12
17-8
-------
If steady current and voltage readings are obtained across a component of an
AC circuit, they may be multiplied together to yield the "apparent power." This is the
power which is available to "do work".3 In electric power generation, the apparent
power is often expressed in MVA units, as it represents an upper production limit.
The power factor is defined as the ratio of the "real power" divided by the "apparent
power." The conventional representation of a power factor is "cos 0" where " 0 "
represents the phase angle difference between the voltage and current. For the
example where the phase angle difference was 15 degrees, the power factor would be
0.96 (cos 15°).
AC ELECTRICAL POWER
Apparent Power is Current times Voltage
Papparent = I % V, [KVA]
Power Factor
Power Factor = cos 0 = P/Papparent
Slide 17-13
17.3
Motors
Electrical Power Equipment
Motors convert electrical energy into mechanical energy used to drive various
types of machinery. The development of the electric motor has had a profound effect
on modern industry. Low operating costs and ease of operation of electric motors has
resulted in motors replacing steam engines and turbines to drive auxiliary equipment.
Motors commonly used in industrial applications are single-phase and multi-
phase. Single phase consists of two wires (which power the motor). Multi-phase
motors have either three or four wires with 3-phase (3 wires) being the most common.
Single phase motors are induction motors. A magnetic field is induced by the flow of
current through wiring arranged around a rotor. The wiring is referred to as the stator
because it remains stationary. The magnetic field oscillates with the input AC
current and voltage (usually at 60 cycles/second). The rotor spins as it attempts to
magnetically align with the field which creates mechanical motion.
Single-phase motors are primarily used in fractional horsepower applications
(1/4, 1/3, 1/2, 3/4 horsepower) and where three-phase power is not available. Single-
phase motors differ slightly depending upon the method of starting: split-phase,
capacitor-start, capacitor start-and-run, and shaded-pole.
17-9
-------
Multi-phase motors are typically used in large horsepower applications due to
their higher torque capacity. The three most commonly used three-phase induction
motors are squirrel-cage, wound-rotor, and synchronous motors. Squirrel-cage and
wound-rotor motors have three separator stator windings. There is one stator
winding for each phase distributed at 120° angles. This produces a rotating magnetic
field which causes the rotor to turn. Synchronous motors uses two magnetic fields
which are synchronized. The rotor is excited with AC power to create a rotating
magnetic field while the stator is powered with DC to create a stationary field. The
effect of the magnetic fields attempting to stay "in synch" causes the rotor to turn.i
Generators
Generators are essentially motors operated in reverse. They convert
mechanical energy into electrical energy. Both DC and AC generators are commonly
used. DC generators were first developed to produce electricity from steam engines.
This creates low voltage with high amperage, which requires large wiring and results
in significant line losses. AC generators are almost exclusively used presently to
produce electricity at high voltage and low amperage. This makes it possible to
transmit power over extended distances. Substations (with transformers) are used to
"step-down" the power at the point of use.
Transformers
Transformers are designed to increase or decrease voltage in AC circuits. A
step-up transformer delivers a higher voltage from the secondary coil than is received
by the primary coil, and a step-down transformer will deliver a reduced voltage.
TRANSFORMER WINDING SCHEMATIC
Cote
Primary Coil
Secondary Coil
Step-down Transformer
Slide 17-14
17-10
-------
The fractional increase or decrease in voltage of a transformer is proportional
to the ratio of the windings of wire in the primary and secondary coils. If there are
twice as many windings on the primary coil as on the secondary coil, the transformer
will function as a step-down transformer with the resulting voltage at one-half that of
the supply voltage. Transformers are essential elements in the connection between
the utility grid, the electric generator, and in-plant distribution system.5
Operators should be aware that the utilities transport 3-phase, high voltage,
AC power. Three-phase generation uses three primary conductors which carry AC
currents whose cycles are timed in a regular offset pattern. Many circuit designs will
use four conductors in order to accommodate a ground requirement.
SCHEMATIC OF 3-PHASE ELECTRIC CURRENT
Slide 17-15
Other Equipment
Special electrical power equipment such as circuit breakers, rectifiers, and
inverters are commonly used in utility and industrial boiler units.5
17-11
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ELECTRICAL POWER EQUIPMENT
COMPONENT FUNCTION
Voltage Regulator Maintains constant voltage from AC source
Circuit Breaker Controls the flow of electricity
Rectifier Converts AC electricity to DC
Inverter Converts DC electricity to AC
Slide 17-16
Voltage regulators are used to maintain a constant voltage on an AC
generator. Constant terminal voltage is maintained by increasing or decreasing the
field current to the generator.
Circuit breakers are designed to provide the switching required in electrical
generation and electrical service. Some circuit breakers are provided primarily to
protect the utility grid, whereas others function as a local safety device. The utility
can trip the main circuit breaker as part of the normal and correct functioning of the
network protective system.
Circuit breakers are switches that are mechanically closed after a heavy
spring is compressed and held in place by a latch. Circuit breakers are designed to
open automatically when an external tripping signal is received. The signal may
signify that the current flow on the circuit is too high, the voltage is too high or too
low, or that some fault condition has occurred. The signals are often actuated by the
action of a relay. For example, a directional relay is designed to prevent the reversed
flow of electricity, such as the case when a generator receives grid power (which
causes it to act as a motor).
A rectifier is an electronic device which receives an AC electrical supply and
produces DC electricity. Rectifiers are used to produce the DC electricity which is
used to produce the electrical fields required for particle collection in electrostatic
precipitators. Rectifiers can also be used for charging the batteries which store
energy for emergency power supply systems.
Inverters are used to convert the DC electricity into AC electricity.
Emergency power supply systems are generally designed around storage batteries
and inverters. These are required because AC power is generally required to drive
almost all the electric motors and controls used in utility and industrial units.
17-12
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17.4
Instruments and Meters
Instruments and meters are used to monitor and control electrical operations
in a plant. Instruments and meters commonly used include voltmeters, ammeters,
ohmmeters, synchroscopes, and frequency meters. 1
INSTRUMENTS AND METERS
Voltmeters
Ammeters
Ohmmeters
Synchroscopes
Frequency meters
Slide 17-17
Voltmeters measure the difference in voltage between two points in a circuit.
Voltmeters are commonly used to check the voltage, fuses, and for breaks in circuits.
Ammeters measure the current in any part of a circuit. Ammeters are
commonly used to check for excessively high current in a circuit. Ammeter reading
must be carefully monitored as plant load is increased to ensure that the generator
windings do not overheat.
Ohmmeters measure the amount of resistance in a part of a circuit or in a
complete circuit. Continuity can also be checked using an ohmmeter.
Synchroscopes measure the phase relationship between two voltages.
Synchroscopes are used when two AC generators are paralleled or synchronized.
Frequency meters indicate the frequency of oscillation in a system. Electrical
equipment is designed to operate at a specific frequency. Any variation in frequency
affects all electric motors, electric clocks, and other inductive electrical devices.
17-13
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REFERENCES
1. Frederick M. Steingress and Harold J. Frost, Stationary Engineering.
American Technical Publishers, Inc., Homewood, EL, 1991, pp. 301-328.
2. Basic Electricity. Field Manual, FM 55-506-1, Department of the Army,
Washington, DC, 22 April 1977.
3. Electricity. Theory an.d Fundamentals• Student Workbook 52C10, US Army
Engineer School, Fort Belvoir, VA, June 1979.
4. W. A. La Pierre and B. M. Jones, "Electrical and Electronics Engineering,"
Mark's Standard Handbook for Mechanical Engineers. Eighth Edition, Edited
by T. Baumeister, et al., McGraw Hill Book Company, NY, 1978, pp. 15-1 to
15-6.
5. John Reason, "Electrical Interconnections," Standard Handbook of Power
Plant Engineering. Thomas C. Elliott, editor, McGraw Hill Book Co., NY, 1989,
pp. 5.3-5.24.
17-14
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CHAPTER 18. TURBINE GENERATOR
18.1. Introduction
18.2. Steam Turbine Generator Description
18.3. Steam Turbine Designs
18.4. Steam Turbine Generator Operation
18.5. Generator Synchronization With Utility Grid
18.6. Turbine Generator Off-Nominal Conditions
Slide 18-1
-------
18. TURBINE GENERATOR
18.1
Introduction
This unit addresses the design and operation of turbine generators. Most of
the electric power produced in the U.S. is via fossil fuel burning steam plants in
combination with turbines. Such systems allow either a portion or all of the thermal
energy generated in the boiler to be converted to electrical power. Steam turbines are
also used to drive many different types of mechanical devices such as electric
generators, pumps, and compressors.
18.2
Steam Turbine Generator Description
STEAM GENERATOR EQUIPMENT & FLOW SCHEMATIC*
Slide 18-2
A turbine generator set will consist of a variety of major components and
system ancillary components. The above slide illustrates the typical arrangement
for the steam side of a boiler and turbine generator set and its auxiliary components.
18-1
-------
TURBINE GENERATOR SYSTEM
COMPONENTS
Steam Turbine
Condenser, Hotwell, & Air Ejector
Condensate Pump & Heater
Deaerator
Feedwater Pumps & Heaters
Electrical Generator
Slide 18-3
Steam turbines convert stored thermal energy to mechanical work by
controlled expansion of steam through a series of stationary blades or nozzles, and
rotating blades. The combination of a stationary vane and a rotating blade is called a
turbine stage. Steam enters the turbine through the relatively small nozzles and as
it expands it attains a high velocity and exerts a force against the rotating blade
causing it to turn.
In the flow schematic shown in slide 18-2, the steam from the boiler first
passes through a throttle valve which modulates the flow rate and pressure of steam
being delivered into the steam turbine. The amount of power generated by the
turbine is proportional to the flow rate of steam through the turbine and the steam
pressure drop across the turbine. By modulating the main throttle valve, the total
flow of steam and the steam pressure at the first stage nozzle can be adjusted to
provide the required rotor speed at the desired power output level.
Outlet flow from the turbine is directed into a condenser, which is basically a
series of water cooled tubes that cause the steam to condense. Water then drips
from the condenser tubes into a lower chamber known as a hotwell. A minimum level
of water must be maintained in the hotwell at all times to prevent cavitation in the
condensate pump.
The condensate pump extracts the water from the hotwell and directs it to a
device known as a deaerator. The purpose of the deaerator is to remove dissolved
gases from the water before it is pumped to the boiler. To accomplish that objective,
the condensate is heated to its saturation point where dissolved gases will boil off.
Released gases are then vented to atmosphere. The deaerator operates at a pressure
ranging from around 5 to 75 psig, depending on the particular design of the plant.
18-2
-------
STEAM CONDENSER SCHEMATICi
L
Exhaust Steam Inlet
Condenser
Tubes /- Cooling Water
/- ooonnc
/ Outlet"
Baffle
Slide 18-4
The boiler feedwater pump increases the pressure of deaerated water to the
full boiler operating pressure. Also at this stage, the feedwater is preheated before it
enters the boiler economizer. Heat for operation of the deaerator and the feedwater
heaters is often supplied by extracting steam from various stages of the turbine.
Because the functions of the feedwater pump are so critical to boiler
operations, a parallel set of pumps is generally installed. This allows switching
between the pumps to provide for maintenance, without having to take the boiler off-
line.
In addition to the steam cycle described above, other key ancillary components
of the turbine/generator are the oil heating and cooling systems and the turning gear.
The shaft in the turbine and generator rotates on bearings which are bathed in oil.
The oil is provided at a pressure (by a lift pump) high enough to maintain an oil film
which carries the load of the rotor. To avoid serious bearing friction, the oil must
continually flow through the system at a proper viscosity. Under no load or cold start
conditions, the viscosity considerations require oil heating. Under full load operation,
oil coolers are used to maintain viscosity by rejecting heat. Because of the critical
nature of the oil flow, turbine generators will be supplied with a redundant set of oil
pumps and will generally have an emergency system operated by an alternate power
supply, such as DC powered pumps with a battery pack.
18-3
-------
Once the turbine generator set is placed into operation, the shafts should be
kept in continual rotation, even when the unit is down and no power is being
generated, to maintain the turbine and generator shaft alignment and to minimize
vibrations in the shaft. The turning gear is a motor driver which provides rotation of
the main shaft, generally less than 10 rpm. Typically, a centrifugal clutch
mechanism disengages the turning gear whenever steam flow through the turbine
causes the rotor to turn at higher speeds.
The final component of the turbine generator system is the electrical
generator. The primary purpose of the generator is to convert mechanical energy
into electrical energy. The mechanical energy is supplied by the rotating shaft in the
turbine. The purpose of the slip rings, shown in Slide 18-5, is to transmit DC electric
energy as excitation current to the rotor. The stator leads are connected to switching
devices which transmit the three-phase AC energy from the coils on the stator to the
utility grid.
AC GENERATOR!
Frame
Rotor
Stator
Fan
Slip Rings
Stator Leads
Slide 18-5
18-4
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18.3
Steam Turbine Designs
Three types of turbines are commonly used: the impulse, reaction and
impulse-reaction turbines. Their designs have many similarities, as described below.
STEAM TURBINE TYPES & FEATURES
TYPES
Impulse Steam Turbine
Reaction Steam Turbine
Impulse-Reaction Steam Turbine
FEATURES
Multiple Stages
Conversion of Thermal Energy
Production of Mechanical Energy
Slide 18-6
Steam turbines consist of many stages of airfoil blades which convert energy
in the steam to rotating shaft power. Steam pressure and temperature decrease
from stage to stage in a steam turbine.
As the pressure is decreased, the density drops which causes the steam to
expand and occupy more volume. This results in the progressive increases in turbine
wheel diameter and blade length as steam moves through each successive stage.
18-5
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IMPULSE TURBINE BLADE CONFIGURATION & FLOW PARAMETERSi
Fixed Blades (3
Revolving Blades (?
Initial
Steam Pressure
6; Second-stage
Revolving
Bades
y-® Revolving BtodM
Exit
Steam Pressure
Initial
Steam Velocity
Exit
Steam Velocity
Time
Slide 18-7
Impulse steam turbines use the impact of high velocity steam to create a force
acting on a blade mounted on a wheel. As illustrated in the above slide, impulse
turbines have multiple stages consisting of a nozzle, two rows of rotating airfoil blades
and one row of stationary blades. The system is designed so that most of the
pressure drops occur through the nozzles rather than the blades. Although the
pressure within a blade section is nearly constant, the velocity drops-off considerably.
The rotating blades are attached to disk wheels which are mated to the rotor
shaft while the fixed blades, or stators, are attached to the turbine casing. Expansion
of the steam through the turbine causes the shaft to rotate and converts the high
pressure thermal energy of steam into mechanical energy (shaft work). The
stationary blades act mainly to change the direction of the steam flow, so the
optimum angle of steam flow exists as the steam enters the second set of rotating
blades.
18-6
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REACTION TURBINE CONFIGURATION & FLOW PARAMETERS!
Revolving Blades (2
Fixed Blades (7
Initial
Steam Pressure
3) Fixed Blades
7) Revolving Blades
Exit
Steam Pressure
Initial
Steam Velocity
II4K I!
Time
Slide 18-8
Reaction steam turbines make use of reaction forces produced by a flow of
steam through the turbine blades. The difference in the momentum of the flow
entering and leaving the rotating blades causes a mechanical force on the blades
which is transferred to the shaft. The high velocity steam gives up its kinetic energy
(velocity) as it flows through the revolving blades.
The reaction turbine uses fixed blades to act as nozzles. As illustrated above,
steam enters the first set of fixed blades and has its velocity increased as its pressure
drops. The fixed blades also change the direction of the steam flow so it enters the
rotating blades at the optimum angle. The process then repeats itself at succeeding
stages.
Impulse-reaction turbines combine impulse and reaction binding. There are
several stages of impulse blades in the high pressure end of the steam turbine and
reaction blades in the low pressure end of the turbine.
18-7
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18.4
Steam Turbine Generator Operation
TURBINE GENERATOR OPERATION
Cold Start
Synchronization
Shut-Down
Slide 18-9
Each turbine generator set will be provided with a detailed set of operating
instructions developed by the vendor.
In large installations, there will typically be an area operator at the turbine
generator as well as remote control from the main control room. In the main control
room, the operator will usually have a major panel devoted to instrumentation and
control of the turbine generator set. Redundant measurements and controls may be
provided for the area operator.
It is critically important that the control room and area operators remain in
close contact especially during system start-up and shut-down.
During start-up, the generator will provide no load to the turbine and the
turbine will be relatively cool (or cold). Bringing the system from that state to full
operational status is a critical responsibility of the operator.
All system components such as condensate pumps, deaerator, feedwater
pumps, feedwater heaters, control valves, recirculation valves, vent valves, and
emergency systems must be sequentially brought to operational status or standby
status. All liquid supply system components must also be at their proper level and
automatic control systems operational.
A key responsibility of the operator is to bring the turbine generator to its
operational state at a rate specified by the manufacturer. During the start-up cycle,
the turbine metal temperature will rise to the temperature of the steam supplied by
the boiler. That process can cause severe thermal stress to build within the turbine
and will cause a differential expansion of the casing and internal components. From a
cool start, manufacturers generally require that the casing be warmed at a rate of
about 100 °F per hour and at all times the temperature difference across any metal
wall should not exceed about 150 °F. Procedures associated with preheating of the
steam supply lines and assuring proper operation of emergency and auxiliary
systems may cause the time required for the start-up process to extend over more
than a single operating shift.
In addition to metal temperature concerns, care must be exercised to prevent
the turbine rotor from accelerating too rapidly. After coming off the turning gear, the
rotor is often limited to an acceleration of about 100 rpm/minute until a mid-range
18-8
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speed is reached. Then a hold period is often required to prewarm the rotor and
casing. Typical mid-range rotor speed will be on the order of 1000 rpm, and a hold
time on the order of a half hour or more is not unusual. The manufacturer will also
specify the acceleration rate for the turbine rotor which will assure safe operation
through the rotor's critical speed points. Critical speed points are speed at which the
rotor shaft becomes dynamically unstable with large lateral amplitudes, due to
resonance with the natural frequency of lateral vibration of the shaft. Operation at
the critical speed can cause excessive vibration of the turbine shaft resulting in
catostrophic damage. Compliance with the start-up cycle is vitally important.
The generator rotor will begin to turn as the turbine rotor begins to turn. Fine
adjustments of the rotor speed and excitation will be required to match the generator
electrical voltage and phase characteristics with those of the utility grid. The proper
rotational speed will typically be 3600 rpm to provide 60 Hz, three phase power
output, although some generators are designed to operate at 1800 and 1200 rpm.
Generation of electricity by the system requires that an array of electrical
subsystems be in operation. Provisions will be made for an excitation system and for
adjusting the generator side voltage. During start-up, careful adjustment of generator
side voltage may be required to prevent possible feedback to the generator end when
the generator is synchronized.3
Picking up load on the generator must be accomplished in a gradual fashion
and coordinated with adjustments on the steam flow side of the turbine generator.
The rate at which load can be added will depend upon the turbine starting conditions.
For colder starts, the load should be added at a very gradual rate (about 0.5% of rated
capacity per minute). For hot starts, load can be added at a much faster rate (about
2 to 3 % of rated capacity per minute is typical).
Unit shut-down must rigorously follow a schedule of events which will basically
be a reverse of the start-up procedures. The operator is responsible for assuring that
the sequencing of events in the shut-down schedule are appropriately fulfilled.
The preceding material only addresses the broad general features of that
operation. It is the responsibility of the operator to become familiar with the detailed
instructions provided by the turbine generator manufacturer. These instructions
should also be incorporated into a detailed operating procedures manual which is
specific to the overall facility configuration and characteristics.
18-9
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18.5
Generator Synchronization With Utility Grid
The synchronizing process requires that the three phases of electricity
generated exactly match with the three phases of the AC buses of the utility grid
before the breaker switch is closed.
TURBINE GENERATOR SYNCHRONIZATION
Synchroscope: Phase Angle Meter
Clockwise Rotation
Counterclockwise Rotation
Indicator Pointing Upward
Slide 18-10
A synchroscope is a phase angle meter which is provided to indicate any
frequency mismatch and the difference in the phase angle between that of one leg of
the generated power and the corresponding leg of the grid.4 The operator uses
information from the synchroscope to adjust turbine speed and excitation energy,
thereby synchronizing the generator to the grid before closing the switch gear.
If the synchroscope indicator rotates counterclockwise, it is an indication that
the frequency of the generated energy ("incoming" to the grid) is greater than that of
the grid.4 A clockwise rotation would indicate a lower generator frequency than that
of the grid.
A stationary synchroscope pointer indicates that the frequencies are matched.
The angular displacement of the pointer is an indication of the phase difference
between the incoming and grid energy. The indicator is stationary and points directly
upward when the phase of the incoming energy is matched to that of the grid.4
18-10
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18.6
Turbine Generator Off-Nominal Conditions
TURBINE GENERATOR OFF-NOMINAL
CONDITIONS
Water Induction
Excessive Vibration
High Bearing Temperatures
High Back-Pressure
Speed Control
Slide 18-11
A number of potential off-nominal turbine generator operating conditions are
listed above.
Water induction can be caused by the flow of relatively cold vapor or liquid
water from the feedwater heater through the steam extraction line and into the
turbine casing. Water induction can cause severe thermal stress problems which can
cause distortion of the casing and destruction of turbine blades. It can be controlled
by installing automatic block valves and proper feedwater heater maintenance.
Excessive vibration of the turbine-generator may be an indication of potential
problems, which can cause serious damage to the unit. Many modern turbine-
generators are instrumented to "trip" if pre-set vibration limits are reached.
Likewise, high bearing temperatures can be caused by an inadequate cooling
water flow rate, excessive cooling water temperature, or by the lack of lubrication.
Most modern turbine-generator sets have bearing temperature controllers which will
"trip" the unit if excessive temperatures occur. If this happens, the turbine
manufacturer should be contacted for assistance.
It is possible for the generator to act as a synchronous motor and drive the
turbine. This phenomena, which is called "motoring," may occur during low load
operations, such as during the turbine generator start-up and shutdown. The turbine
blades can become overheated and damaged due to the lack of steam flow, which
normally controls the blade temperatures. Modern systems generally incorporate
reverse power relays to automatically prevent this occurrence.
High steam turbine back-pressure or low vacuum in the condenser can be
caused by inadequacies in the cooling water system. High back-pressure can result
in overheating of the low pressure blading if the problem is not corrected.
Temperature sensors or vacuum gages can be set to trip the turbine automatically.
18-11
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Problems with speed control can be attributed to the turbine governor, voltage
regulator or mechanical problems in the control system. Most units now incorporate
mechanical or electrical over-speed limit controls.
REFERENCES
1. Frederick M. Steingress and Harold J. Frost, Stationary Engineering.
American Technical Publishers, Inc., Homewood, IL, 1991, pp. 227-275,
printed with permission.
2. Kenneth Wark, Jr., Thermodynamics. Fifth Edition, McGraw Hill Book
Company, New York, 1988, p. 739.
3. Basic Electricity. Field Manual, FM 55-506-1, Department of The Army,
Washington, DC, April 1977, pp. 299-304.
4 Joe Kaiser, Eleqtrical Power. Motors. Controls. Generators. Transformers.
Goodheart-Willcox Company, Inc., South Holland, Illinois, 1991, pp. 166-186.
18-12
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CHAPTER 19. PREVENTIVE MAINTENANCE
19.1 Potential Economic Losses
19.2 Features of Preventative Maintenance
19.3 Periodic Inspections
19.4 In-Service Maintenance
19.5 Outage Maintenance Planning
Slide 19-1
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CHAPTER 19. PREVENTIVE MAINTENANCE
A well executed preventative maintenance program is essential to achieving
high reliability and efficiency as well as maintaining safety. In addition, a sound
maintenance program can reduce total operating expenses in the long term. This
learning unit considers the general aspects of preventive maintenance. The safety
aspects will be addressed in Chapter 20.
19.1
Potential Economic Losses
A preventative maintenance program can be thought of as an effective
insurance program. In some industries, insurance policies are available to provide
protection against revenue losses associated with unit outages, as well as casualty
and liability losses. In general, losses will occur if equipment is not properly operated
and maintained.
A broader view of preventative maintenance program includes the various
economic aspects of production and loss. The economic aspects include: the costs of
the preventive maintenance program; consideration of losses associated with injury
and repair; lost revenue associated with equipment outages; and fines for regulatory
violations.
POTENTIAL ECONOMIC LOSSES
1.
2.
3.
4.
5.
Cost of Preventive Maintenance
Personal Injury
Equipment Repair/Replacement
Lost Revenue - Equipment Downtime
Fines - Regulatory Violations
Slide 19-2
Operators participate in preventative maintenance through their decision-
making on issues of safety, operation, corrective maintenance and preventive
maintenance. Operators have the responsibility for assuring that the equipment is
both properly operated and maintained.
19-1
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OPERATOR RESPONSIBILITIES
1. Safety
2. Production (System Operations)
3. Preventive Maintenance
4. Corrective Maintenance
5. Record Keeping & Communications
Slide 19-3
Preventive maintenance consists of planned maintenance actions (including
inspection) to prevent equipment breakdown. In cases where the equipment has
failed, corrective maintenance is performed. Operators also have responsibilities for
record keeping and communications. Operators help address these issues in the
development of policies and standard operating procedures.
19.2
Features of Preventative Maintenance
A steam generating unit and associated air pollution control equipment must
be properly operated and maintained so that it can perform reliably, efficiently and
safely over their expected life. Consequently, there are considerable economic risks
associated with an improper maintenance program.
GOALS OF PREVENTIVE MAINTENANCE
1. Maximize Unit Reliability
2. Minimize Total Operating Costs
3. Enhance Equipment Life
4. Restore Unit Performance
Slide 19-4
An operating goal is to assure overall equipment reliability and to minimize
unit down-time. This is a critical component for minimizing the total operating costs
and preserving the plant's capital investment in the equipment. Maintenance can
represent a significant part of the total cost. Priorities must be set in an attempt to
balance the economic consequences associated with either acting now or deferring
maintenance.
19-2
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"A stitch in time saves nine" is still a valid expression. As maintenance is
deferred, operational problems will generally worsen and unit down-time will be
increased. The financial consequences include the direct losses associated with
making the repairs, lost production, and potential costs associated with safety
hazards.1 Preventive maintenance is performed to assure that the unit can operate
safely, efficiently, and reliably.
To some extent, the performance of all equipment tends to deteriorate with
operating time. Therefore, a preventive maintenance program is designed to assure
that productive equipment life is preserved. Obviously, good operating practices
must include many routine activities, such as maintaining proper boiler water
conditions to avoid tube failures and boiler problems and maintaining proper
lubrication for rotational equipment like compressors, fans, and turbines.
Preventive maintenance is also designed to restore performance efficiencies.
Routine operations, such as soot blowing, are important operations which restore
system efficiency. On smaller boilers, it is necessary to periodically clean tube
surfaces using manual methods such as rodding out the convective section.
Predictive maintenance is the part of preventive maintenance which tries to
identify potential problems. Routine inspection of equipment and instrument
readings, as well as a review of the performance and maintenance records, can lead to
the identification of equipment problems. Predictive maintenance also includes the
use of special instruments for vibrational analysis, lube oil sample analysis,
ultrasonic testing, infrared imaging and meggering (e.g., measuring electrical
resistance of insulation) of electric motors and wiring.2
FEATURES OF A MAINTENANCE PROGRAM
1. Review Vendor Recommendations
2. Identification of Problems
3. Evaluation of Options
4. Communication & Planning
5. Implementation
Slide 19-5
A maintenance program generally begins with the review of the equipment
design features and an implementation of the manufacturers' recommended
maintenance procedures. Special attention should be given to the specified
lubrication requirements and operating limits (temperatures, pressures, loads, etc.).
An important aspect of unit operations is to identify problems and solve them
before they become unmanageable. Problem evaluation begins with an analysis of
the current status and an attempt to identify problems and evaluate the causes.
19-3
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Repairing the symptom of a problem may be easier than solving the real
problem. For instance, a bad bearing can be replaced as a short-term solution.
However, determining and eliminating the cause of the failure, such as correcting an
imbalanced rotor or preventing a corrosion condition, can lead to a long-term solution
to the problem.
Communication with other individuals is also an important aspect of operators'
duties. Discussions and group meetings with auxiliary operators, maintenance staff,
vendor representatives, engineers and/or designers may be required for planning a
proper solution to a special maintenance problem.
Cooperative discussions may be in order before deciding whether to take the
equipment off-line for repair or to delay the maintenance until the next scheduled
outage. Knowledge of both the equipment design features and maintenance records
will be important in the decision. Nevertheless, operators are called upon to make
timely judgments about taking a unit out of service because of various equipment
upsets and safety considerations.
The implementation of maintenance must be scheduled with the operator. A
proper lock-out/tag-out program should be used for equipment that poses an
electrocution or mechanical injury hazard. Lock-out often refers to the use of
padlocks to lock circuit breakers in the "off1 position. It also refers to the use of
mechanical means to secure equipment (e.g., prevent rotation) for personnel safety.
Tags are used to identify who is in charge of the maintenance activity.
19.3 Periodic Inspections
Periodic inspection/maintenance of plant equipment may be on a weekly,
monthly, 6-month, annual or 2-year basis. The inspection intervals are typically
recommended by the equipment vendor manuals, just as with an auto owner's
manual. Power plant operating conditions vary much more than an auto's would
because of the large variables in fuel, water, and ambient conditions. Consequently,
in 48 of the 50 states, annual internal and external inspections of boilers axe required.
These inspections must be made by authorized inspectors acceptable to the state.
Auxiliary systems inspection requirements will vary based on the specific plant
conditions. For instance, a pulverizer's grinding components may need to be replaced
after 9,000 hours of operation on one coal, whereas a harder coal may wear the
components out after 6,000 hours. Therefore, experience and good records are
essential to establishing a good maintenance program.
Many components in the power plant can and should be inspected by regular
visual observation. Poor flame patterns or a change in the appearance of the stack
gases is an indication of fouled burner tips or improper fuel/air ratio. Equipment such
as fans and pulverizers have inspection doors that can be removed to permit internal
inspection. Some equipment such as pumps, heat exchangers and turbines will
19-4
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require performance tests to determine the internal conditions. Calibration of plant
instrumentation is one area that should receive high priority in the periodic
maintenance program.
19.4
In-Service Maintenance
In-service maintenance consists of the day-to-day activities that are
implemented while the boiler is in operation. These activities usually include
lubrication, seal and packing adjustments, and repair of components that can be
removed from service without affecting operation. These routine operations follow
the manufacturer's recommended procedures. For equipment, the special design and
operational features need to be reviewed prior to performing in-service maintenance.
In addition, a clear understanding of its relationship to other elements of the unit and
the possibility of switching to alternate equipment should also be reviewed as part of
the maintenance procedure.
IN-SERVICE MAINTENANCE
1. Follow Recommended Procedures
2. Know Special Design Features
3. Know Operational Relationships
Slide 19-6
Examples of in-service maintenance may include pulverizer maintenance,
CEMS instruments, and control sensors. Once again, communication is critical
between the boiler operator and maintenance personnel to indicate which equipment
is available for maintenance and which is critical for operation.
19.5
Outaee Maintenance Planning
Whether specific maintenance can be performed while the unit is in service or
during an outage will be determined by the severity of the conditions and the design of
the equipment. The scheduling of major (annual) outages requires planning, setting
priorities, and arranging for special inspectors and appropriate maintenance
personnel, supplies, replacement parts and repair equipment.
19-5
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OUTAGE MAINTENANCE
1. Make & Update an Outage Plan
2. Arrange for Materials/Services
3. Make Detailed Inspections
4. Revise Plans as Necessary
5. Follow Proper Procedures
6. Inspect Upon Conclusion
Slide 19-7
The annual boiler outage is a standard inspection requirement associated with
operating a boiler. The inspection and repair must be performed in accordance with
applicable requirements. The National Boiler Inspection Code (NBIC) is the
recognized standard for inspections, alterations and repairs to boilers and auxiliary
equipment* In particular, the NBIC Code includes the proper welding procedures and
welder qualifications for repair and alterations.
The annual outage is utilized for several purposes. The primary purpose is to
conduct a thorough inspection of the fire and gas side of the boiler as well as the water
side (steam drum, headers, waterwalls, etc). These are the areas with which the
State or insurance company inspector is most concerned.3
The secondary purpose is to permit inspection and repair operations of
ancillary equipment which cannot be conducted while the boiler is operating. This
might include components such as fans or pumps which, if removed from service,
would restrict boiler load. Example maintenance problems would be items such as
leaking valves, air/gas leaks, or inoperable dampers. The operator should
communicate these problems, preferably through written trouble tickets issued on a
daily basis, for inclusion on an outage action item list. This will permit proper
planning so that materials and manpower will be available to make the necessary
repairs during the outage period.
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REFERENCES
1. Riggs, James L. and West, Thomas M., Essentials of Engineering Economics,
Second Edition, McGraw Hill Book Company, New York, 1986, pp. 438-464.
2. Singer, Joseph G., Combustion, Fossil Power Systems, Third Edition,
Combustion Engineering, Inc., Windsor, CT, 1981, pp. 22-1 to 22-23.
3. Steam, Its Generation and Use, 39th Edition, Babcock and Wilcox, New York,
1978, pp. 36-1 to 36-20.
4. National Board Inspection Code, ANSI/NB-23 1992, The National Board of
Boiler and Pressure Vessel Inspectors.
19-7
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CHAPTER 20. SAFETY
20.1 System Safety Hazards
20.2 Consequences of Exposure to Hazards
20.3 Standard Safety Considerations
20.4 Personnel Protection Equipment
Slide 20-1
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20. SAFETY
The responsibility for employee safety is broadly based in federal regulations,
managers, and the employees themselves. The Occupational Safety and Health
Administration (OSHA) has established mandatory job safety and health standards
based on the specific operation and activity being performed. In addition, state and
local codes have been established and must be followed as well. Managers have the
responsibility to train and educate their employees about the health concerns and
hazards they may encounter and how to comply with the safe working practices. The
safe practices are specific to the equipment and plant design and comply with OSHA
standards. Ultimately, the boiler operator and other employees are responsible for
their own safety by following these safe practices.
The following is a discussion of the general steam generating system safety
hazards, consequences of exposure, standard safety procedures, and personnel
protection equipment. Once again, this manual is not intended to replace any existing
on-site safety training program. Each steam generating system will have a safety
program tailored to the specific plant design. All operators should be familiar with
these safe practices and execute them diligently.
There are four main elements to a safety procedure:
SAFETY PROCEDURE ELEMENTS
1. Recognition of Hazards
2. Consequences of Exposures
3. Standard Safety Procedures
4. Personal Protection Equipment
Slide 20-2
Recognition of hazards answers the question : Does a hazard exist? Education and
experience are required to answer this question. Once the hazard is identified the
consequences of the exposure must be known to assess what to do to reduce the
exposure. In some cases, personal protection equipment is required to reduce the
exposure. A discussion of each of these four aspects of a safety procedure follows.
20-1
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20.1
System Safety Hazards
The first step in a safety training program is to identify existing and potential
problems and hazards in the work place.
MAJOR HAZARDS OF
STEAM GENERATING SYSTEMS
• Water Side Explosions Due to
Overheating and Over Pressure
• Gas Side Explosions Due to
Explosive Mixtures
Slide 20-3
The combustion process releases heat that passes through the boiler walls and
is adsorbed by the water or steam flow. Any disruption in water or steam flow also
disrupts removal of heat from the boiler with potentially catastrophic effects. A
variety of factors can result in steam/water flow disruptions. Boiler operations and
safety systems must be available to deal with those disruptions and prevent
explosions. Two examples of water/steam flow disruptions are discussed to illustrate
the types of safety systems installed on boilers and to indicate why those safety
systems must be properly maintained.
First, situations such as a turbine trip cause the turbine stop valves to
instantly slam shut, stopping all steam flow from the boiler. Without immediate
action from the boiler control system and safety systems, the following situations
would occur:
• The feedwater pump continues to pump into the closed steam systems.
• The burners would continue to heat the fixed mass of
water/steam.
• Steam temperature and pressure rise rapidly.
• Boiler tubes or headers explode.
To keep this from happening, there is a series of critical safety features. First,
whenever steam flow is terminated, safety interlocks should instantly trip all fuel flow
to the boiler. This action helps, but often there is enough fuel already in the boiler (i.e.,
grate feed systems) or fuel in the supply lines that cause the heat release not to
immediately be terminated. The residual fuel can release enough heat to rapidly raise
the boiler pressure. To prevent catastrophic failure from over pressurizing, the
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ASME boiler code requires installation of pressure relief valves. Specific code
provisions define the number, type, installation, and testing features of the safety
valves.
A second, equally dangerous situation occurs if there is a loss of water level in
the boiler. This can occur through failure of feedwater pumps or mismatch of
feedwater pump and steam flow. Similar to the turbine trip example, heat released
by the flame is being adsorbed by a reduced mass of water and steam. The steam
pressure does not rise, but the steam temperature does rise. The boiler tubes can
then overheat, leading to structural failure of the tubes.
To prevent this type of failure, most boiler control systems monitor steam
temperature and water level in the boiler. Typically, water level is automatically
controlled by the combustion control system. Additionally, there should be alarms for
both high and low water levels and a trip switch for Hi-Hi and Lo-Lo levels which
initiate shut-off of fuel flow. The main fuel shut-off is referred to as an MFT, which
stands for Master Fuel Trip.
Many safety features are also included in the boiler combustion control
system. Before igniting the pilot flame of the boiler burner, no lingering combustible
gases are permitted to be presented in the furnace. Modern combustion control
systems are designed to prevent such hazards by adequately purging the furnace
with air to dilute any combustible gases that may remain in the furnace and cause
them to exit up the stack prior to starting the ignition sequence. Once operating,
excess combustion air needs to be provided to prevent the formation of pockets of
unmixed combustible gases within the furnace.
OTHER BOILER SYSTEM SAFETY HAZARDS
1. Combustion Gases
2. Noise
3. Observation Hatches
4. Operations in Confined Spaces
5 . Boiler Auxiliary Systems
Slide 20-4
The products of combustion or combustion gases are of health and safety
concern. Boiler operators may be exposed to carbon monoxide (CO) and sulfur oxides.
The best understood biologic effect of CO is its combination with hemoglobin in the
blood. Carbon monoxide enters the bloodstream through the lungs in the same
manner as oxygen, but it displaces the oxygen in the blood and reduces the oxygen-
carrying capacity of the blood. Therefore, exposure to CO prevents an adequate
oxygen supply from reaching the tissues of the body. Sulfur dioxide in relatively large
quantities causes irritation to the eyes and mucous membranes and over time may
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result in bronchitis and decrease pulmonary function.5 In addition, combustion gases
may carry particulate matter as dust or fly ash. The boiler operator may be exposed
to particulate matter in higher concentrations when operating or maintaining
particulate collection devices, such as baghouses and ESPs. In addition, the SCR and
SNCR techniques used to control NOX emissions, as discussed in Chapter 25, require
the injection of ammonia or another agent which releases ammonia. Operators
should be aware that excess ammonia emissions could occur and ammonia monitors
should be in use.
The boiler operation requires the operation of rotating equipment, such as fans
and pumps, which create noise during operation. In addition, the turbulent mixing of
the combustion air with the fuel also created noise. OSHA requires ear protection to
be worn for noise levels exceeding 85 dB. With 25% of all industrial workers
experiencing permanent noise-induced hearing losses, hearing protection should be
worn in this boiler operating environment^
Generally, observation hatches into the furnace should be opened only after
taking precautions against exposure to furnace pressure pulsations. Materials can
blow through an observation hatch as a result of sootblowing, tube failure or aerosol
can explosions on the fuel bed.4 Therefore, individuals should not stand directly in
front of open furnace ports or doors. Design provisions for safety include delivering
aspirating air to the observation hatch and providing a protective transparent cover.
Open-ended pipes should not be used for removing slag from walls, as the hollow pipes
can become very hot and can direct hot gases onto the handler.1
Operators should also be aware of the potential for eye damage associated with
intense thermal radiation. Tinted goggles or other eye protection should be used when
viewing the flame.
Serious burns can occur if individuals contact steam pipes, valves and other
hot metal objects. The improper opening of high pressure steam vents and/or the
rupture of steam pipes can cause severe scalding.
In addition, it is potentially hazardous to enter confined spaces such as the
equipment cavities of the furnace, steam drum, and baghouse. Hazards here arise
from poor ventilation, space being cramped, limited lighting and exposure to
accumulated pollutants and/or dust. Specific OSHA requirements must be met.
Explosion proof lights and properly grounded electrical extension cords should be
used.* Confined spaces should be entered only after they have been properly cooled
and ventilated. Appropriate doors and valves should be locked or tagged. The lockout
and tagout procedures should call for notification of all employees that a lockout
and/or tagout prior to the lockout/tagout. All stored energy must be dissipated or
restrained by methods such as repositioning, blocking, bleeding down, etc. After
applying the lockout/tagout and ensuring no personnel are exposed, a check on the
disconnection of the energy sources should be made by operating the control to make
certain the equipment will not operate. After the servicing is completed and the
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equipment is ready for normal operation, check the area for remaining tools, replace
protection guards, ensure that no one is exposed prior to restoring energy.
One of the primary requirements of the OSHA Hazard Communication
Standard is that Material Safety Data Sheets (MSDSs) must be available to all
employees potentially exposed to hazardous substances. A MSDS is a special form
that conveys the hazardous physical characteristics and properties of a substance,
known acute and chronic health effects, target organs, safe handling procedures, spill
and leakage procedures, and waste disposal procedures. Important data sheets for
boiler operators would include those for chemicals used in water treatment and
scrubber systems, solvents, refractories, and paints. In older boiler installation, the
operators should be aware that asbestos may be contained in insulation materials
used on the boiler and the steam piping, any handling of these insulating materials
should follow the asbestos handling procedures. The Hazard Communication
Standard requires that employees exposed to hazardous substances receive at least
annual training. New employees must be trained before they are placed in
environments where hazardous substances are being used.
20.2
Consequences of Exposure to Hazards
Although the reaction to the hazards encountered during boiler operation will
vary with each operator, operators should be aware of the significant safety risks
associated with operating staff who perform their duties while having certain
symptoms of illness.
SYMPTOMS OF ILLNESS
1. Headaches
2. Lightheadedness
3. Dizziness
4. Nausea
5. Loss of Coordination
6. Difficulty in Breathing
7. Chest Pains
8. Exhaustion
Slide 20-5
The above symptoms of illness may result from heat stress, inhalation
problems and/or a variety of non-occupational related conditions. An impaired worker
is a threat to the overall safety of the unit as well as to fellow personnel.
20-5
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20.3
Standard Safety Procedures
The standard safety procedures at a boiler operating facility should include, but
are not limited to, normal operation procedures, lockout/tagout, hearing conservation,
asbestos notification and identification, compressed gas cylinder training, respiratory
protection, contingency plan emergency response, hazardous materials training, fire
prevention plan, emergency action plan, and equipment qualification requirements.2
These procedures should account for the safety considerations, listed in Slide 20-6,
which exist when working around a boiler.
Standard Safety Considerations
Exposure to High Pressure Steam
Exposure to Hot Water
Electrical Shock
Exposure to Chemicals
Chemical Mixing
Asbestos Exposure
Noise & Vibration
Exposure to Rotary Equipment
Awkward Access
Movement of Heavy Objects
Fire Hazards
Slide 20-6
Standard industrial safety considerations include those associated with
electrical shocks, noise, vibrating equipment, exposure to hot metal surfaces,
exposure to rotating equipment, awkward access to equipment, movement of heavy
objects, welding, exposure to corrosives and fire hazards.
For example, the electrical and steam service to rotary equipment should be
"locked out" and "tagged out" before servicing. In addition, it may be appropriate to
have the shaft blocked to prevent rotation, which could otherwise cause injuries such
as mashed, cut, or severed fingers.
To address these safety issues the following safety rules should be incorporated
into the safety program and followed:
1. Use low-voltage droplights and ground fault interrupters when working inside
boilers. The entire boiler is a conductor, so low-voltage droplights minimize the
risk of electrical shock.
2. Know the locations of all emergency showers and eyewash fountains. Certain
chemicals can cause serious skin and eye burns.
20-6
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3. Wear ear and eye protection, safety shoes, and hard hats in all designated
areas. When looking into furnace ports use tinted glass to protect the eyes
from the infrared and ultraviolet rays.
4. Assume all piping is hot and wear protective gloves to prevent burns.
5. Do not wear loose-fitting clothing around rotating equipment such as pumps or
fans to prevent clothing from becoming entangled in a rotating shaft.
6. Use proper ladders to gain access to equipment. Do not climb on equipment or
building steel.
7. Eliminate clutter from the operating floor using good housekeeping standards.
Clean all spills immediately.
8. Always use appropriate lockout procedures when removing equipment from
service for cleaning or repairs.
9. Use proper lifting techniques and back support when moving heavy objects
and do not lift more than can be handled comfortably.
10. Store all oily rags and other waste in approved containers to prevent fires and
empty these containers regularly.
11. Inspect safety equipment, such as fire extinguishers, on a regular basis.
12. Repair of Tools/Devices should be completed by qualified personnel only.
Also, care should be exercised when walking to avoid bumps, slips and falls.
Improper ladders and unsecured scaffolds should not be used. Care should be used to
assure that objects are placed securely to avoid damage due to falling. All accidents
should be reported immediately to facilitate the investigation of the causes of the
accident and corrective actions as to how to prevent a recurrence.
20-7
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20.4
Personal Protection Equipment
The first line of defense against exposure to hazards is good engineering and
administrative practices.3 However, there are times when personal protective
equipment can provide and may be required to provide additional protection.
PERSONAL PROTECTION EQUIPMENT
1. Ear Protection
2. Heavy Gloves
3. Hard Hat
4. Respirator
5. Goggles and Safety Glasses
6. Safety Shoes
7. Proper Clothing
8. Back Support
9. Gaseous Concentration Monitors
Slide 20-7
Standard industrial safety procedures relate to the use of personal protective
equipment, such as that listed above. However, respirators should not be used unless
the operator has received the specific training. In addition to the above listed personal
safety protection equipment, persons should wear proper clothing so that there are no
loose fitting parts which could become tangled in rotating equipment. Natural fiber
work clothes should also be worn because some synthetic fibers can melt when
exposed to hot equipment. Exposure to harmful gases must be monitored. Depending
on the fuel and emission control systems, monitors for H2S, ammonia, CO, etc. may
be used.
20-8
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REFERENCES
1. Steam, Its Generation and Use, 39th Edition, Babcock and Wilcox, New York,
1978, pp. 34-8.
2. Steingress, Frederick M. and Frost, Harold J., Stationary Engineering,
American Technical Publishers, Inc., Homewood, IL, 1991, pp. 71-82.
3. Woodruff, E. B., Lammers, H. B. and Lammers, Thomas F., Steam Plant
Operations, Fifth Edition, McGraw-Hill Book Company, New York, 1984, pp.
223-230.
4. Singer, Joseph G., Combustion, Fossil Power Systems, 4th Edition, Combustion
Engineering, Inc., Windsor, CT, 1991, pp. 21-1 to 21-34.
5. Hoover, Reynold L, et al., Health, Safety, and Environmental Control, Van
Nostrand Reinhold, New York, 1989, pp. 187-189.
20-9
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CHAPTER 21. Affi POLLUTANTS OF CONCERN
21.1 Introduction
21.2 Air Quality Overview
21.3 National Ambient Air Quality Standards
21.4 Primary Pollutants
A. Particulate Matter
R Sulfur Oxides
C. Nitrogen Oxides
D. Hydrocarbons
E. Carbon Monoxide
21.5 Secondary Pollutants
A. Photochemical Oxidant
B. Acid Deposition
21.6 Hazardous Pollutants
A. Hazardous Metals
B. Organics
Slide 21-1
-------
21. Am POLLUTANTS OF CONCERN
21.1
Introduction
CLASSIFICATION OF POLLUTANTS
Primary Pollutants
Particulate Matter
Sulfur Oxides (SO2, S03)
Nitrogen Oxides (NO* NO2)
Hydrocarbons
Carbon Monoxide
Secondary Pollutants
Photochemical Oxidant (ozone, etc...)
Sulfates
Hazardous Pollutants
Metals (Lead, Mercury, etc...)
Organics (Benzene, Vinyl Chlorides, etc...)
Slide 21-2
From an environmental perspective, air pollutants can be classified into three
broad categories: primary pollutants, secondary pollutants and hazardous pollutants.
Primary pollutants, such as particulate matter, sulfur dioxide, and hydrocarbon
compounds, are those which are emitted directly from emission sources. These
pollutants may directly have an adverse effect on human health or welfare and may
also react in the atmosphere to form secondary pollutants such as photochemical
oxidant or sulfates, which also have negative impacts on the environment. Hazardous
pollutants, like primary pollutants, are also released from emission sources. These
pollutants can be broken into two categories: inorganic compounds, which are
primarily metals such as lead and mercury, and organic compounds, such as benzene
and vinyl chloride. Pollutants are classified as hazardous if exposure to them can lead
to death or serious illness.
In Learning Unit 6, we learned how pollutants are formed in combustion
systems. Recall that sulfur dioxide and particulate emissions are largely dependant
upon the fuel that is fired. Carbon monoxide and hydrocarbon emissions, both volatile
and hazardous organics, are pollutants that are emitted due to incomplete
combustion of the fuel. Nitrogen oxide emissions are dependant upon the fuel type and
the design and operation of the combustion system. In the atmosphere, nitrogen
oxides and reactive hydrocarbons can react to form other pollutants such as
21-1
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photochemical oxidant, which is commonly referred to as "smog". In this learning unit,
we will review the impacts that pollutants have on air quality and the environment in
order to gain a better understanding of the basis of pollution control regulations.
21.2
Air Quality Overview
Am QUALITY OVERVIEW
Atmospheric Interactions
\
Pollutant
Emissions
Effects
Sources
\
Receptors
Slide 21-3
To better understand how pollutants affect our health and welfare, we must
first understand how pollutants impact air quality. Pollutants emitted from sources
enter the atmosphere, where they are diluted, transported, and capable of reacting to
form secondary pollutants. The effects that the pollutants have on receptors
determines the extent to which air quality is degraded. If there were no adverse
effects on receptors, then pollutants would be of no concern1.
Pollutants can come from manmade sources or from natural sources, both
sources are important to air quality; however, manmade pollutants are the focus of
this lesson. Manmade or anthropogenic sources are classified as stationary or mobile.
Stationary sources include boilers and furnaces, while mobile sources include
automobiles, trucks, buses, and airplanes. The type and quantity of pollutant
emissions tend to vary by source. For example, nearly 75 percent of all sulfur dioxide
emissions due to combustion are from electric power generating boilers, while nearly
65 percent of all VOC emissions are from the use of fossil fuels in transportation.
21-2
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Once pollutants enter the atmosphere, they are mixed with air resulting in a
decrease in their concentration. Local and regional wind patterns then transport the
pollutants away from the source and promote additional mixing and dilution. During
the transport process, some pollutants undergo chemical reaction to form other
pollutants. Due to these different forms of atmospheric interactions — transport,
dilution, and reaction — the quality of air arriving at a receptor is a function of both the
type and quantity of the pollutant and the extent of mixing and chemical reaction
which has occurred during transport of the pollutant to the receptor.
Receptors which are potentially affected by air quality include people, plants,
animals, and materials. The effects of poor air quality range from respiratory
irritation and damage in humans, to damage of ornamental plants and crops. Long
term exposure to some pollutants can result in damage to exposed metals or other
sensitive materials. Pollution control regulations are implemented to preserve the
public health and welfare.
How is air quality defined? Generally, air quality is most often detected as a
reduction in visibility due to smog, haze, or smoke in the atmosphere. However, many
pollutants exist as gases or particles which are not visible. Special monitoring
equipment is used to detect the presence of these pollutants. Along with the need to
define air quality comes the need to establish standards for air quality.
21.3 National Ambient Air Quality Standards
To minimize the impacts of poor air quality on receptors, the federal
government has established air quality standards for pollutant species that impact
public health and welfares. These air quality standards are maintained by regulating
the emission of pollutants from combustion sources and by requiring that the
pollutants which are emitted are effectively mixed or dispersed into the atmosphere.
National Ambient Air Quality Standards (NAAQS) for particulate matter,
sulfur dioxide, nitrogen dioxide, hydrocarbons, carbon monoxide, were established in
1971 by the U.S. Environmental Protection Agency (EPA) as required by the 1970
Federal Clean Air Act Amendments. In 1978, the standard for photochemical oxidant
was revised and converted to an ozone standard, which is the compound most
commonly monitored as an indicator of photochemical oxidant. A standard for lead
was added to the NAAQS in 1978. Recognizing that the primary hazard to human
health due to particulate is from particles with a size below 10 microns, the
suspended particulate standard was revised in 1987 and redesignated as a standard
for particulate matter under 10 microns or
The National Ambient Air Quality Standards represent the maximum levels of
these pollutants that are permitted to exist in ambient air. Averaging times reflect
the period of time over which the concentration of a pollutant is averaged for
comparison to the standard. Standards, other than those based on the annual
average, are not to be exceeded more than once per year.
21-3
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NATIONAL AMBIENT AIR y UALlTlf STANDARDS
(Reference: Godish)
POLLUTANT
Particulate
Matter (< lOum)
Sulfur Oxides
Nitrogen Dioxide
Hydrocarbons
(corrected for
methane)
Carbon Monoxide
Ozone
Lead
AVERAGING
TIME
annual mean
24 hour
annual average
24 hour
3 hour
annual average
3 hour
8 hour
1 hour
Ihour
3 month average
PRIMARY
STANDARD
50 ug/m3
150 ug/m3
80 ug/m3
365 ug/m3
100 ug/m3
160 ug/m3
10 mg/m3
40 mg/m3
235 ug/m3
1.5 ug/m3
SECONDARY
STANDARD
50 ug/m3
150 ug/m3
1300 ug/m3
Same
160 ug/m3
Same
Same
Same
Same
Slide 21-4
Primary standards are those which were established to protect the public
health. Secondary standards, which are generally more stringent, are those which
were established to protect the public welfare (e.g. property, plants, etc...). Implicit in
the establishment of these standards is the assumption that there exist safe
exposure levels to these pollutants. To assure the public health, the established air
quality standards are based upon an assessment of the health risk associated with
21-4
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exposure based upon available scientific evidence. To this risk is added a margin of
safety to ensure that the health of sensitive individuals, such as those with asthma
or other respiratory diseases, is not at risk.
It is important to note that the National Ambient Air Quality Standards
establish a uniform nationwide standard for air quality, but do not define the limits on
emissions from boilers and other combustion devices. Individual states are required to
implement control measures for pollutants which allow the air standards to be met
and maintained. Since air quality is influenced by the type and quantity of pollutants
emitted and by local meteorological conditions, it is possible for allowable emissions
levels of pollutants to vary from state to state.
Pollutant
Particulate
Sulfur Dioxide
Nitrogen Dioxide
NAAQS OBJECTIVES
Objective of the Standard
To prevent health effects due to long term
exposure
To prevent pulmonary irritation (primary)
and to prevent odor (secondary)
To prevent possible risk to public health and
atmospheric discoloration
Hydrocarbons To reduce photochemical oxidant formation
Carbon Monoxide
Ozone
Lead
To prevent interference with the capacity to
transport oxygen to the blood
To prevent eye irritation and respiratory
problems and to prevent damage to
vegetation
To prevent lead poisoning
Slide 21-5
21-5
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As stated previously, the NAAQS were established based upon available
scientific evidence of the effects of these pollutants on human health and welfare.
More detailed effects of these pollutants will be described in subsequent panels. The
primary objectives of the NAAQS were to*:
• Prevent negative health effects due to long term continued
exposure to small particulate suspended in the
atmosphere.
• Prevent pulmonary irritation and unpleasant odor due to
sulfur dioxide.
• Prevent possible risk to public health and atmospheric
discoloration due to nitrogen dioxide.
• Reduce photochemical oxidant formation due to the
presence of hydrocarbons.
• Prevent the interference of carbon monoxide with the
capacity to transport oxygen to the blood.
• Prevent eye irritation and respiratory problems and to
prevent damage to vegetation and materials due to ozone.
• Prevent overexposure of sensitive groups, such as children,
to lead leading to acute or chronic lead poisoning.
21-6
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21.4
Primary Pollutants
Given the preceding background, we will now examine the primary effects of air
pollutants on human health and welfare. The following paragraphs address the
emission of particulate matter, sulfur oxides, nitrogen oxides, hydrocarbons and
carbon monoxide.
Particulate Matter
PARTICULATE MATTER
Typical Form: Solid, Liquid, Aerosol
Critical Factors: Particle Size
Particle Type
Aerosol Concentration
Health Effects:
Deposits in respiratory passages.
Increases exposure to toxic
substances
Welfare Effect: Reduces visibility
Slide 21-6
Particulate matter is a general term used to describe small solid and liquid
particles. As discussed in Chapter 6, particulate emissions from boilers may be in the
form of smoke or soot (i.e. unburned carbon), or in the form of flyash. Particulate
matter suspended in the atmosphere generally consists of these pollutants and
particulate matter formed from other pollutants, such as the sulfates formed from
sulfur dioxide. The term aerosol is used to describe a collection of suspended particles.
The three factors which most significantly influence the impact of particulate
on air quality are the size and type of the particulate and the concentration of the
particles. Small particles are most easily transported away from pollutant sources
and also have the highest impact on human health and welfare. The size of particles
in the atmosphere is measured in microns—one micron equals one millionth of a
meter. One thousandth of an inch is approximately 25 microns. Flyash from
combustion systems is generally in a size range of 0.5 to 100 microns. For
comparison, pollen has a size range of 10 to 100 microns, and tobacco smoke is
generally between 0.01 to 1.0 microns. The type of particulate is also important. For
example, exposure to sulfate aerosols is more hazardous than exposure to dust.
21-7
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There are two primary health effects associated with particles. First, small
particles are easily inhaled into the respiratory system where they are deposited in
bronchial passages and the pulmonary system. Buildup of these deposits can lead to
constriction of the bronchial passages. Particle size is important since the human
respiratory system can generally prevent particles above 10 microns in size from
entering the lungs. Particles below this size are deposited in the tracheobronchial and
pulmonary systems, which are the lung tissues responsible for supplying oxygen to
the blood. The deposited particles can irritate lung tissue and constrict small
passages. The second adverse health effect of particles is due to the tendency of toxic
substances to absorb onto the particle surface where they are easily transported
deep into the respiratory system and absorbed into the body through lung tissue.
Substances of concern include sulfates, polycyclic aromatic hydrocarbons (PAH), and
heavy metals such as lead and mercury.
Participate matter influences human welfare by reducing visibility of the
atmosphere. Visibility is difficult to quantify in substantial terms, but may be defined
as the ability to see clearly over a distance. Visibility is influenced by a number of
atmospheric and human factors. Particle size has a significant effect on visibility
since it influences the ability of a particle to scatter light. Particles in the size range of
0.2 to 1.0 microns are the most effective at scattering light. This is one of the reasons
cigarette smoke is so easily detectable.
Sulfur Oxides
Typical Form:
Critical Factor:
Health Effect:
Welfare Effect:
SULFUR OXIDES
Sulfur dioxide - gaseous
Sulfates (SO3, H2SO4) - liquid
Conversion of 862 to sulfates in the
atmosphere
Causes broncho-constriction,
especially in asthmatics
Results in acid deposition
Slide 21-7
Sulfur emissions from combustion systems are typically in the form of sulfur
dioxide, SO2, with a small amount of sulfur trioxide, SOs. In the atmosphere, sulfur
dioxide is oxidized to SOs which can react with moisture in the air to form sulfuric acid,
H2S04. The various sulfur carrying species which can exist following oxidation of SO2
21-8
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are collectively called sulfates. Conversion of sulfur dioxide to sulfates in the
atmosphere is the most significant influence of sulfur dioxide on air quality.
Exposure to high concentrations of sulfur dioxide can be fatal; however, the
concentration levels that are toxic are significantly above typical ambient levels.
Exposure to low levels of sulfur dioxide can lead to acute constriction in the bronchial
passages to sensitive individuals, particularly those with asthmatic conditions.
Scientists now believe that exposure to sulfate compounds, particularly acid aerosols,
is the more significant health risk associated with emissions of sulfur dioxide.
Deposition of sulfates in the environment poses a significant threat to human
welfare due to the potential consequences of acid deposition. Fossil fuels are the
primary source of sulfur oxides in the atmosphere. The amount of sulfur dioxide
emitted from a particular fossil fuel depends entirely on the amount of sulfur
contained in the fuel. The amount of sulfur contained in coals and oil vary widely
depending on where it comes from. Coal and fuel oils can contain very high amounts
of fuel sulfur where as natural gas typically contains no sulfur at all.
Nitrogen Oxides
Typical Form:
Critical Factor:
Health Effects:
Welfare Effect:
NITROGEN OXIDES
Nitric oxide (NO) - gaseous
Nitrogen dioxide (N02) - gaseous
Nitric acid (HNO3) - liquid
Conversion of NO to NO2 and to
nitrates in the atmosphere
Damages respiratory tissues, causes
respiratory symptoms
Results in atmospheric discoloration,
promotes formation of photochemical
oxidant, and results in acid deposition
Slide 21-8
Nitrogen oxide emissions from combustion systems are typically in the form of
nitric oxide, NO, with trace amounts of nitrogen dioxide, NO2- Nitric oxide is a
colorless, odorless, relatively nontoxic gas. Nitrogen dioxide is a light-brown, toxic gas
with a pungent, irritating odor reminiscent of bleach. In the atmosphere, nitric oxide is
21-9
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readily converted to NO 2 through oxidative and photochemical reactions. NC>2 can
then be converted to nitric acid,
Nitric oxide is a pollutant of concern because it is readily converted to N(>2 in
the atmosphere. Exposure to high concentrations of NO 2 results in severe damage of
lung tissue. Some studies indicate that exposure to low concentrations of N02 leads to
a higher occurrence of respiratory symptoms, such as chest pain, pneumonia,
bronchitis and asthma, in sensitive population groups like children.
Atmospheric NO2 can have several effects on human welfare. Since it is
colored gas, NO2 in small concentrations is visible in the atmosphere as a brown haze
or discoloration which can reduce visibility. Formation of NO2 in the exhaust from
boiler stacks can lead to problems with brown plumes. Nitrogen dioxide also
participates in the formation of photochemical oxidant. Nitrates formed from NO 2
result in acid deposition. The formation of photochemical oxidant and the problems
associated with acid deposition will be described in more detail in Section 21.5.
Nitrogen oxides result from the combustion of all fossil fuels. As will be
discussed in more detail in Chapter 25, NO x results from fuel bound nitrogen and
combustion dynamics. Natural gas, the cleanest burning of all fossil fuels, typically
achieves the lowest level of nitrogen oxide formation. Typical nitrogen oxide emissions
from natural gas fired boilers range from 0.03 to 0.45 Ib/MMBtu depending on the
type of boiler and the scale of combustion. Oil fired boilers have emissions in the
range from 0.08 to 0.39 Ib/MMBtu for distillate oils and 0.13 to 0.79 Ib/MMBtu for
residual oils. Coal fired boilers have a wide range of nitrogen oxide emissions
depending on the coal nitrogen content and type of combustion system, however
typical levels for new units fall into the range between 0.15 to 0.50 Ib/MMBtu.
Hydrocarbons
Typical Form:
Critical Factor:
Health Effects:
Welfare Effect:
HYDROCARBONS
A wide range of organic molecules are
possible
Molecule type
Not critical at typical concentrations
Contributes to photochemical oxidant
and ozone
Slide 21-9
21-10
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Combustion systems can emit a wide range of different organic compounds.
Substances that fall into this category contain only carbon and hydrogen molecules.
Organic compounds may be present in the atmosphere in gaseous, liquid, or solid
form. The smaller compounds which exist in gaseous or liquid form represent the
critical compounds which most significantly impact air quality. Larger organic
compounds are generally absorbed onto the surfaces of particles. In the atmosphere,
organic compounds released from combustion systems may react with a wide variety
of other compounds to form a wide range of hydrocarbon derivatives.
The variety of organic compounds which exist range from compounds that are
harmless to those which can be hazardous in large quantities. However, ambient
concentrations of these compounds are so low that they do not pose a significant risk.
Typical non-methane hydrocarbon concentrations in urban areas range from 1 to 10
ppm.3 Hydrocarbon emission standards are based upon the need to control
photochemical oxidant.
Natural gas typically achieves Total Hydrocarbon (THC) emissions in the
range from 0.00 to 0.117 Ib/MMBtu depending on the type of boiler and the scale of
combustion. Oil fired boilers have emissions in the range from 0.00 to 0.012
Ib/MMBtu for distillate oils and 0.00 to 0.031 Ib/MMBtu for residual oils. See the
individual chapters on boiler types for more specific information of the levels of THC's
found with different boilers and fuel types.
Carbon Monoxide
CARBON MONOXIDE
Typical Form: Gas
Critical Factor: Concentration
Health Effects:
Impairs oxygen transport in blood.
Impacts central nervous system.
Welfare Effect: None
Slide 21-10
Carbon monoxide, CO, emissions occur from the incomplete combustion of
fossil fuels and are generally low from properly operating boilers. Mobile sources emit
the largest quantity of carbon monoxide emissions. Carbon monoxide is a colorless,
odorless gas. In the atmosphere, carbon monoxide is slowly converted to carbon
dioxide though the action of microorganisms in the soil.
21-11
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Exposure to high levels of carbon monoxide concentrations causes
asphyxiation and death. However, ambient concentrations of carbon monoxide are
only a fraction of the level needed to cause asphyxiation. Exposure to low levels of
carbon monoxide impacts the central nervous system to an extent in direct
proportion to the concentration. No effects on human health or welfare have been
detected for exposure to the limit established by the air quality standards.
Carbon monoxide can result from combustion of all fossil fuels and is largely
dependent on the air to fuel mixture. The presence of CO is and indication of
incomplete combustion. Natural gas typically achieves the lowest level of carbon
monoxide emissions which range from 0.00 to 0.223 Ib/MMBtu depending on the type
of boiler and the scale of combustion. Oil fired boilers have emissions in the range
from 0.00 to 1.177 Ib/MMBtu for distillate oils and 0.00 to 0.114 Ib/MMBtu for
residual oils. Coal fired boiler carbon monoxide emissions depend on the type and
scale of combustion system, however typical levels fall into the range between 0.05 to
0.30 Ib/MMBtu.
21.5 Secondary Pollutants
Sulfur dioxide, nitrogen oxide, and hydrocarbons are pollutants which are
regulated primarily because they react in the atmosphere to form secondary
pollutants which have adverse effects on air quality. Two of the most common
secondary pollutants are photochemical oxidant and acid gases. These pollutants will
be described in the following.
Photochemical Oxidant
Photochemical oxidant is the name given to a mixture: of pollutants resulting
from the reaction of nitrogen oxides and reactive hydrocarbons in the presence of
ultraviolet rays in sunlight to form ozone and other pollutants. Here, the term reactive
hydrocarbons is used to indicate that some types of hydrocarbons are able to
participate more effectively in the process than other hydrocarbons.
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FORMATION OF PHOTOCHEMICAL OXIDANT
Photochemical
Oxidant
Nitrogen Oxide
+
Reactive Hydrocarbons
Slide 21-11
The five types of components that make up photochemical oxidant are: ozone,
nitrogen dioxide, aerosols, peroxyacyl nitrates (PAN), and other types of hydrocarbon
derivatives. As mentioned earlier, the federal air quality standard is based upon
ozone, Os, since it is the most significant and most easily measured component of
photochemical oxidant. Nitrogen dioxide and aerosols were introduced in previous
panels. Peroxyacyl nitrates are a family of compounds that occur in trace amounts in
photochemical oxidant.
Typical Form:
Critical Factor:
Health Effects:
Welfare Effect:
OZONE
Gas
Concentration
Irritates eyes and mucous
membranes.
Causes respiratory symptoms and
lung damage.
Damages plants and materials.
Slide 21-12
21-13
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Photochemical oxidant poses a significant risk to human health and welfare.
Ozone, the primary constituent of photochemical oxidant, is one of the most toxic
compounds for which ambient air quality standards have been established. Ozone
concentrations slightly below the standard can irritate mucous membranes and
temporarily impair lung functions. Ozone concentrations at or above the standard
can cause respiratory symptoms in adults. Long term exposure can result in lung
damage.
Three constituents of photochemical oxidant—ozone, nitrogen dioxide, and
peroxyacyl nitrates— can retard plant growth and cause severe plant damage. Ozone
can also cause metal corrosion and cracking in rubber.
Acid Deposition
ACID DEPOSITION
SulfuricAcid, H2SO4
Nitric Acid, HNO3
Dry Aerosol
Deposition
Precipitation
(Rain, Snow)
\
Sulfur Dioxide
Nitrogen Dioxide
Lakes
Vegetation
Slide 21-13
In the atmosphere, sulfur dioxide and nitrogen dioxide undergo reaction to form
sulfuric acid and nitric acid. Although these compounds can pose a hazard to human
health, their hazard to human welfare is far greater. The deposit of these acidic
compounds into lakes and on vegetation is called acid deposition. The term "acid rain"
is frequently used to describe this process. Acid deposition can occur through two
pathways: by dry deposition of the compounds onto surfaces and by incorporation of
the compounds into rain and snow.
It should also be pointed out that rain can be acidic naturally without chemical
mechanisms resulting from pollutant emissions. Carbon dioxide which occurs
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naturally in the atmosphere can become dissolved in rain and other forms of
precipitation causing rain to be slightly acidic.
Acid deposition is believed to have harmful effects on environmental
ecosystems. However, the effects of acid deposition on vegetation, lakes and streams
are complex and difficult to understand. At present the effects of acidification of lakes
and streams has not been proven conclusively but is believed to have a negative
impact on these ecosystems of and can potentially destroy both plants and fish.
21.6
Hazardous Pollutants
Federal regulations recognize that it is necessary to safeguard the public
health against exposure to extremely hazardous or toxic substances. Unlike the
pollutants just described, exposure to hazardous pollutants is not widespread, but
instead is confined to areas surrounding the emissions sources. For purposes of this
discussion, hazardous pollutants can be classified as metal or organic compounds.
Hazardous Metals
HAZARDOUS METALS
Beryllium
Copper
Mercury
Zinc Oxide
Cadmium
Inorg. Arsenic
Nickel
Lead
Chromium
Manganese
Zinc
Slide 21-14
Hazardous metals are emitted from combustion systems when they are
present in the fuel being combusted. Hazardous metals can be emitted directly when
present in ashes or particulates which escape control. In extreme instances
hazardous metals may occur in the vapor phase and escape control in very high
temperature thermal processes.*
Hazardous Organics
Sources of hazardous organic emissions fall into two different categories, which
are direct emissions and indirect emissions to the atmosphere. Direct emissions
typically occur from volatile organic pollutants and result from either spills, leaks or
process venting. Indirect emissions are typically the result of emissions from
21-15
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combustion systems where hazardous organics are partially destroyed as a result of
incomplete combustion. For example, benzene is a product of incomplete combustion
of toluene, a polycyclic aromatic hydrocarbon.
Acrolein
Carbon Tetrachloride
Ethylene Bichloride
Methylene Chloride
Toluene
Vinyl Chloride
HAZARDOUS ORGANICS
Benzene
Chloroform
HCHO
Peroxyacyl Nitrate (PAN)
Trichloroethane
Xylenes
Benzo(a)pyrene
Ethylene Dibromide
Methyl Bromide
Perchloroethylene
1,1,1-Trichloroethane
Slide 21-15
Health effects from hazardous organics depend on the particular hazardous
compound and its concentration during exposure. Slide 21-15 lists some hazardous
organic substances of concern to regulatory agencies. Many of these substance
target a particular organ in the body or are carcinogenic. Vinyl chloride appears to be
a multipotent carcinogen in that it produces cancers in many different organ and in
come cases it produces different kinds of tumors in the same organ. Hydrocarbon
chemicals of their derivatives of health concern include carcinogenic polycyclic
aromatic hydrocarbons (PAH), such as benzo(a)pyrene, and the eye irritants,
including formaldehyde (HCHO), acrolein, and peroxyacyl nitrate (PAN). The PAHs
are produced as a result of incomplete combustion of high-molecular-weight
hydrocarbon species. Benzo(a)pyrene is the most abundant PAH in urban air.3
Eye irritation for HCHO occurs in the range of 0.1 to 1 ppm. Acrolein produces
moderate eye irritation at levels of 0.25 ppm, and PAN causes irritation at 20 ppb.
Eye irritation experienced in urban areas is most likely produced by the combined
effects of these substances and other hydrocarbon derivatives.3
21-16
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REFERENCES
1. G. S. Samuelsen. Air Quality Impact Analysis. Chapter 3 in: Environmental
Impact Analysis Handbook. Rau, J. G. and D. C. Wooten, editors,
McGraw-Hill, New York, New York, 1980.
2. Pahl, D. A., D. Zimmerman and R. Ryan. An Overview of Combustion
Emissions in the United States. Chapter 1 in: Emissions from Combustion
Processes: Origin, Measurement, Control. Clement, R. and R. Kagel, editors,
Lewis Publishers, Incorporated, Chelsea, Michigan, 1990.
3. Godish, T. Air Quality. Lewis Publishers, Incorporated, Chelsea, Michigan,
1991.
4. Griffin, Roger D., Principles of Hazardous Materials Management. Lewis
Publishers, Incorporated, Chelsea, Michigan, 1988.
21-17
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CHAPTER 22. ENVIRONMENTAL REGULATIONS
22.1 Regulatory Overview
A. Clean Air Act History
B. Clean Air Terminology
C. Clean Air Act Provisions
22.2 Provisions of the Clean Air Act Relative to
Boiler Operations
22.3 New Source Performance Standards
A. Performance Standards for Steam
Generators (>250 MMBtu/hr)
B. Performance Standards for Electric
Utility Steam Generators (>250
MMBtu/hr)
C. Performance Standards for Steam
Generators (>100 MMBtu/hr)
D. Performance Standards for Small
Steam Generators (10-100 MMBtu/hr)
22.4 Additional Standards
A. Acid Rain Program
B. State Implementation Plans
C. National Emission Standards for
Hazardous Air Pollutants
22.5 Permits
A. Title V Overview
B. Permit Program Elements
C. Information Requirements
Slide 22-1
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22. ENVIRONMENTAL REGULATIONS
22.1 Regulatory Overview
The purpose of this chapter will be to review regulatory requirements that are
applicable to industrial and utility boilers. From the outset, it must be recognized that
federal regulations protecting the environment mandate that the states implement
sufficient pollution control measures both to attain the federal air quality standards
and to maintain air quality. Therefore, local limits on pollutant emissions can vary
significantly from the limits established by the Clean Air Act, and from state to state.
Boiler operators seeking a permit must consult with local and/or state regulatory
agencies to determine what standards are applicable for their situation. The
information contained in this learning unit is intended to provide boiler operators and
owners with the ability to begin discussions with regulatory agencies on an informed
basis.
Clean Air Act History
The process of burning fossil fuels creates air pollutants that are released to
the atmosphere. As discussed in chapters 6 and 21, the air pollutants which are
generated by burning fossil fuels include sulfur oxides, particulate matter, nitrogen
oxides, hydrocarbons, carbon monoxide and carbon dioxide. Some of these pollutants
represent a direct health hazard, while others are of concern because they react in
the atmosphere to form secondary pollutants, which have detrimental impacts on
public health and welfare (e.g. materials, vegetation, etc...). Therefore, regulations are
needed to limit the release of these pollutants to the atmosphere.
Modern air pollution control regulations have their beginnings at the turn of the
century. During this period, rapid industrialization lead to increased use of coal near
urban centers. Smoke control ordinances were enacted in 1881 in Chicago and
Cincinnati to abate smoke problems1. Local smoke control ordinances were enacted
by most large cities in the first half of this century; however, these ordinances did
little to control the detrimental impacts of modernization of the nation's air quality.
In 1955, federal air pollution legislation, commonly called the Air Pollution
Control Act, was passed enabling the Public Health Service to conduct research on
air pollution and to provide training and assistance to state and local governments in
developing air pollution control programs. Modifications to this legislation in the early
1960s emphasized research into the health effects of automobile emissions. In 1963,
the federal Clean Air Act was passed. This legislation provided for the award of grants
to states to develop and improve air pollution control programs and gave federal
agencies responsibility for establishment of non-mandatory air quality criteria,
abatement of interstate air pollution problems, and performance of automobile and
sulfur oxide pollution research. In 1965, amendments to the Clean Air Act required
federal agencies to establish emissions standards for new motor vehicles.
22-1
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Recognizing that improvements in air quality were slow under the 1963 Clean
Air Act, Congress passed the Air Quality Act in 1967. This act was significant
because it recognized that air quality was a regional problem and it called for the
development and implementation of air quality standards. The federal government
was given authority to establish standards and to require states to develop plans to
achieve these standards. The federal government was also given the authority to
review the plans and progress, and to take action if significant progress was not
made.
HISTORY OF THE CLEAN Am ACT
1881 Smoke control ordinances passed in Chicago
and Cincinnati.
1955 Federal Air Pollution Control Act enacted to
evaluate and assist with air pollution control.
1963 Federal Clean Air Act passed to increase federal
government role in protecting public health and
welfare.
1965 Motor Vehicle Air Pollution Control Act passed
to set emissions standards for new vehicles.
1967 Federal Air Quality Act enacted to increase air
pollution control efforts.
1970 Clean Air Act Amendments passed to improve
efforts for improving air quality.
1977 Additional Amendments to the Clean Air Act
passed to extend deadline for achieving air
quality standards.
1990 Clean Air Act Amendments passed to control
acid rain, auto emissions, hazardous pollutants,
and to meet the ozone standard nationwide.
Slide 22-2
Unfortunately, progress under the 1967 Air Quality Ad; was slow. Therefore,
Congress passed a series of amendments to the Clean Air Act in 1970. The 1970
Clean Air Act Amendments placed significant control and responsibility for air
pollution with the federal government and established a rigorous timetable for
implementing air pollution control measures. The basic premise of the Clean Air Act
22-2
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Amendments was that air quality could be preserved through two actions:
1) establishment of national ambient clean air standards to limit pollutant levels to
below thos^ which would have adverse effects on public health and welfare, and
2) development of emissions standards for combustion equipment designed to
maintain pollutant concentrations below the clean air standards. The Clean Air Act
also passed responsibility for federal air pollution control programs to a new
government agency, the Environmental Protection Agency.
Recognizing that many areas of the country had not achieved clean air
standards for several pollutants by 1975 as mandated by the 1970 Clean Air Act
Amendments, Congress passed additional amendments in 1977 extending the
deadline for achieving the standards.
In 1982, the Clean Air Act was slated for revision. However, delays in
Congress and lack of agreement between Congress and the President on the issue of
acid rain delayed further amendments to the Clean Air Act for nearly a decade.
Finally, on November 15, 1990, President Bush signed a series of amendments to the
Clean Air Act. The primary objectives of these amendments were to address
problems with acid rain (which is primarily linked to sulfur and nitrogen oxide
emissions), emissions from automobiles, and hazardous pollutants. A primary goal of
the act was also to permit the National Ambient Air Quality Standards for ozone and
other pollutants to be achieved across the nation, particularly in affected urban
areas. These amendments are referred to as the Clean Air Act Amendments (CAAA)
of 1990.
Clean Air Terminology
Before reviewing the Clean Air Act Amendments of 1990, it is useful to review
some of the terminology used in the regulations.
CLEAN AIR ACT TERMINOLOGY
NAAQS National Ambient Air Quality Standards
PSD Prevention of Significant Deterioration
NSPS New Source Performance Standards
SIP State Implementation Plans
NESHAP National Emission Standards for
Hazardous Air Pollutants
Slide 22-3
As discussed above, the Clean Air Act empowers the EPA to establish
National Ambient Air Quality Standards (NAAQS) for pollutants which have the
22-3
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potential to have an adverse effect on human health or welfare. Chapter 1 provides a
brief introduction to the NAAQS, while Chapter 21 summarizes the current
pollutants covered by the NAAQS and their known impacts. For the purposes of the
regulation, specific areas across the United States that are not in compliance with
the NAAQS are designated as nonattainment areas.
In order to protect air quality in regions of the country where the NAAQS are
being met, the Clean Air Act establishes guidelines for the Prevention of Significant
Deterioration (PSD) in air quality in these regions. These quidelines prevent areas of
high air quality from being polluted to the levels allowable by the NAAQS.
To control emissions from new sources, the Clean Air Act empowers the EPA
to establish New Source Performance Standards (NSPS) for various types of
stationary emissions sources. These standards limit the rate at which criteria
pollutants (e.g. sulfur oxides, nitrogen oxides, particulate, etc...) can be emitted from
new sources. These standards also apply to existing equipment undergoing major
modification resulting in increases in emissions of criteria pollutants.
The Clean Air Act also requires the EPA to develop National Emissions
Standards for Hazardous Air Pollutants (NESHAP). These standards will set
emissions limits on hazardous pollutants. The 1990 Clean Air Act Amendments
contain a list of 189 chemicals for which the EPA will be required to develop
standards requiring facilities to institute control of these pollutants.
CLEAN AIR ACT CONTROL STANDARDS
Criteria Pollutants
LAER Lowest Achievable Emissions Rate
BACT Best Available Control Technology
RACT Reasonably Available Control Technology
Hazardous Air Pollutants
MACT Maximum Available Control Technology
GACT Generally Available Control Technology
Slide 22-4
Passage of the Clean Air Act has introduced a wide range of terms regarding
the level of pollution control technology that needs to be applied to meet emissions
standards established under the act. For criteria pollutants, Best Available Control
22-4
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Technology (BACT) is the technology required for new sources or existing sources
undergoing major modification in attainment areas. BACT is defined as the most
effective emissions control in use, taking into account factors of availability and cost
on a case-by-case basis2. In nonattainment areas, new sources may be expected to
comply with the Lowest Achievable Emissions Rate, the most stringent emissions
limit. All existing major emissions sources in nonattainment areas will be required to
implement Reasonably Available Control Technology (RACT) control measures. The
EPA is required to release Control Technology Guidance documents which advise
states on technologies which will be classified as RACT for various sources.
Two levels of emissions control have been established for hazardous air
pollutants. Major sources of hazardous pollutants will be required to implement
Maximum Available Control Technology (MACT). This technology provides the
maximum degree of emissions reduction achievable, taking into account several
factors including availability and cost. Alternatively, the EPA may permit Generally
Available Control Technology (GACT) to be implemented for certain area emissions
sources.
Clean Air Act Provisions
The 1990 Clean Air Act Amendments were the most comprehensive piece of
environmental legislation enacted by the federal government to date. The impacts of
the Clean Air Act are expected to reach all businesses and consumers2. The Clean
Air Act Amendments are divided into eleven titles, each of which covers specific
topics:
Title I Air Pollution Prevention and Control establishes the framework for
attaining and maintaining National Ambient Air Quality Standards.
Areas which are specified as nonattainment areas are classified into
different categories. Deadlines and measures required to achieve
NAAQS are specified. State Implementation Plans are required for
specific pollutants in nonattainment areas.
Title II Emissions Standards for Moving Vehicles regulates mobile sources
by establishing stricter emissions limits for new vehicles and by
requiring the use of fuels with lower emissions (e.g. reformulated
gasoline).
Title III Hazardous Air Pollutants greatly expands the regulation of hazardous
pollutants. The title requires the establishment of MACT standards for
major sources emitting hazardous air pollutants identified in the act.
Title IV Acid Deposition Control governs the control of sulfur oxides and
nitrogen oxides, primarily from utility boilers. Industrial sources may
elect to participate in the emissions credits program.
Title V Permits establishes a new permit system for any source regulated
under the Clean Air Act. The permit system will be implemented at the
state level.
22-5
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Title VI Stratospheric Ozone Protection is designed to implement controls on
substances, primarily refrigerants such as chlorofluorcarbons and
hydrochlorofluorocarbons, that are believed to impact the ozone layer.
Title VII Enforcement provides new requirements for enforcement and
establishes criminal penalties for noncompliance.
Title VIII Miscellaneous Provisions contains several provisions regarding
control of emissions from sources in the outer continental shelf,
assessment of visibility in National Parks, and other topics.
Titles DC-XI Clean Air Research, Disadvantaged Business Concerns, and
Clean Air Employment Transition Assistance contain provisions for
research, allocation of research funds to disadvantaged businesses, and
assistance for persons who lose their job as a result of the Clean Air Act.
1990 CLEAN AIR ACT TITLES
L Air Pollution Prevention and Control
EL Emissions Standards for Moving Vehicles
EEL General
IV. Acid Deposition Control
V. Permits
VL Stratospheric Ozone Protection
VTL Enforcement
VEEL Miscellaneous Provisions
EX. Clean Air Research
X. Disadvantaged Business Concerns
XL Clean Air Employment Transition Assistance
Slide 22-5
22-6
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22.2
Provisions of the Clean Air Act Relative to Boiler Operations
CLEAN AIR ACT PROVISIONS RELATIVE TO
BOILER OPERATIONS
Title I: Air Pollution Prevention and
Control
Title III: Hazardous Air Pollutants
Title IV: Acid Deposition Control
Title V: Permits
Slide 22-6
The four provisions of the Clean Air Act expected to have the strongest impact
on owners and operators of industrial and utility boilers are Titles I, III, IV, and V.
Under Title I, each state has primary responsibility for assuring attainment of the
NAAQS through a state implementation plan (SIP). The SIP can have significant
impact on how a boiler is operated. Boilers located in areas needing to come into
attainment with the federal ozone standard will likely need to implement RACT to
control NOX emissions. Title I also requires the EPA to issue technical documents
which identify alternative controls for NOx emissions from industrial and utility
boilers. These documents will assist the states with developing and implementing the
SIP programs.
As discussed earlier, Title III focuses on the identification and control of
hazardous air emissions. Under the act, the EPA was directed to perform studies on
electric steam generating unit emissions to determine the hazards to public health
reasonably anticipated to occur as a result of emissions of listed hazardous air
pollutants. The results from this study and others may provide the basis for EPA to
formulate additional regulations to control emissions of hazardous pollutants from
power plant emissions. This section of the act also requires the EPA to develop a
model state program for the training and certification of high capacity fossil fuel fired
plant operators. This manual was prepared to satisfy the training requirements. The
American Society of Mechanical Engineers is developing a certification program for
such operators.
Title IV addresses acid deposition which occurs when sulfur dioxide and
nitrogen oxide emissions are transformed in the atmosphere to acids and return to
earth as rain, fog or snow. Most of the sulfur dioxide emitted in the U.S. is the result of
burning fossil fuels by electric utilities. Therefore, this title contains sulfur reduction
requirements for all power plants. Nitrogen oxides contribute significantly to acid
deposition. Therefore, Title TV also establishes limits on emissions of nitrogen oxides
from power plants.
22-7
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Title V contains a new permit system for sources controlled under the Clean
Air Act Amendments. Boiler operators will need to establish whether they need an
operating permit and then apply to obtain one if needed. Permits will be issued by the
states following federal quidelines. Permits will establish detailed requirements
governing emissions from the source and related activities such as monitoring,
record-keeping, and reporting.
The following chart shows how various air pollutants are governed under the
Clean Air Act Amendments. Title IV limits emissions of sulfur dioxide and nitrogen
oxides from utility boilers. Non-utility sources may apply to fall under this regulation
in order to generate emissions credits. Title I limits emissions of carbon monoxide,
nitrogen oxides, volatile organic compounds and particulate from stationary
combustion sources. Title II establishes limits for these pollutants from mobile
sources. Hazardous Organic compounds and inorganic particulate materials, such as
various metal compounds which may be present in fly ash will be regulated under
Title EL
AIR POLLUTANTS COVERED BY CAAA
Title IV Title I Title II Title III
Acid Deposition Nonattainment Mobil Sources Haz. Air Pollutants
Slide 22-7
22-8
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22.3 New Source Performance Standards
The Clean Air Act Amendments provide the EPA with the power to develop
and administer New Source Performance Standards (NSPS). These standards apply
to "new sources" and establish unit "performance standards" limiting the rate at
which pollutants may be emitted from the stack. The NSPS also apply to sources
undergoing modifications which would result in increases in regulated pollutants.3
NEW SOURCE PERFORMANCE STANDARDS
Apply to New Units or Significantly Modified Units
Regulations Established for different Groupings of
Pollutant Emission Sources
• Utility Boilers
• Industrial Boilers
• Gas Turbines
Establish Stack Emission Limits for Criteria Pollutants
Limits must be based on Demonstrated Performance
of Control Technologies
Establish Monitoring, Recordkeeping, and Reporting Requirements
Slide 22-8
From Chapter 1, you may recall that NSPSs have been developed for different
groupings of pollutant emission sources including gas turbines and:
• Large Fossil Fuel Fired Boilers - This grouping is dominated by electric
utility boilers, but includes all boilers with heat input ratings greater than
250 million Btu per hour.
• Industrial Boilers - This grouping includes all units with heat input rates
between 10 million and 250 million Btu per hour.
For each of these major groupings, the NSPSs establish limits on the stack
emission rates or stack concentrations for the NAAQS "criteria pollutants." Thus,
there is link between the ambient air quality standards and the new source
performance standards. There are, however, important differences in the applicability
and the basis for the two types of standards. The NAAQS limits are based on
consideration of health effects while the NSPS limits are established based on
demonstrated performance of actual units in full-scale operation.
22-9
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The utility boiler NSPS set different participate, sulfur oxide, and nitrogen
oxides emission limits for units firing gas, oil, and coal. The NSPS only apply to newly
constructed units or to existing units undergoing significant modification. The logic
behind this applicability is that boilers have a finite lifetime—on the order of 30 to 40
years. Boilers constructed prior to passage of the original Clean Air Act were
exempted from the original NSPS but they were expected to be retired by shortly after
the turn of the century. The significant modification provision was included to help
assure that old boilers would be retired in an orderly fashion and replaced by new
units, subject to the NSPS.
Performance Standards for Steam Generators (>250 MMBtu/hr)
NEW SOURCE PERFORMANCE STANDARDS
Steam Generators with Heat Input > 250 MMBtu/hr
Apply to Units Constructed After 8/17/71
or Significantly Modified Units
Fuel
Coal
Oil
Gas
Pollutant
S02
NOX
Particulate
S02
NOX
Particulate
NOX
Particulate
Allowable Emissions
Rate (lb/106 Btu)
1.2
0.7
0.1
0.8
0.3
0.1
0.2
0.1
Slide 22-9
The initial performance standards for fossil-fuel-fired boilers with a heat input
greater than 250 million Btu per hour are shown in the above table4. The standards
apply to units constructed after 17 August 1971. These standards were later revised
for utility boilers and for industrial boilers.
The performance standards also contain requirements for the installation of
continuous emissions monitors for measuring stack concentrations of sulfur dioxide,
nitrogen oxides, and either oxygen or carbon dioxide. Each boiler owner or operator is
required to install continuous emissions monitors for SC-2, NOX, and either 62 or CO 2
with the noted exceptions in Slide 22-10.
22-10
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CONTINUOUS EMISSIONS MONITORS
Each boiler operator is required to install continuous emissions
monitors for SO2, NOr, and either 02 or CO2 with the following
exceptions:
1) Boilers burning gas do not need an SO2 monitor.
2) Boilers burning coal and oil can opt to monitor SO2 by fuel
sampling and analysis, if they do not have a desulfurization unit.
3) Boilers with NOZ emissions which are less than 70 percent of the
standards do not need to install a NOX monitor.
4) Boilers not needing SO2 or NOX monitors do not need to install an
O2 or CO2 monitor.
Slide 22-10
To verify the compliance with the emission limits and the continuous emission
monitoring system operation, the NSPS requires specific reports be submitted to the
administrator of the regulation, which varies from region to region. These reports are
typically submitted every three months and contain the average emission rates for
each 30 day period, identification of boiler operating days which were not in
compliance with the standard, reasons for the non-compliance, and description of
corrective actions taken. For small steam generating units, the reporting
requirements may be semiannual if no excess emissions occurred during the quarter.
For those sources which require continuous emission monitoring system
(GEMS), similar information is required to be reported for the GEMS performance. A
typical list of the information boiler operators need to record and log to support these
reporting requirements is shown in Slide 22-11.
22-11
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BOILER OPERATION LOG DATA FOR NSPS REPORTING
Calendar date
Emission rates (hourly) and /or opacity
Reasons for noncompliance with the emission standards
Description of corrective actions taken.
Operating days for which emission data have not been obtained
by an approved method
Justification for not obtaining sufficient data
Description of corrective actions taken.
Type of fuel(s) combusted and reference to compostion
(i.e. fuel supplier certification)
If a GEMS is used,
• Identification of any times when the pollutant
concentration exceeded the full span of the CEMS.
• Description of any modification to the CEMS that
could affect the ability of the CEMS to comply with
Performance Specifications
• Results of daily CEMS drift tests
Slide 22-11
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Performance Standards for Electric Utility Steam Generators (>250 MMBtulhr)
Special emissions limits have been established for boilers used in electric utility
operations. As discussed earlier, this provision was added to the NSPS to address the
problems associated with acid rain—electric utility boilers are the greatest source of
sulfur oxide emissions in the United States. The performance standards for
fossil-fuel—fired boilers operated by electric utilities with a heat input greater than
250 million Btu per hour are shown in the following two tables. 5 The standards apply
to units constructed after 9/18/78. Emissions of sulfur dioxide and particulate have
been established based on the fuel type fired—coal, gas, or liquid. For NOX emissions,
the standards are based upon a wider definition of fuel types. A distinction is made
between typical fuels and fuels derived from coal and coal refuse. Coal refuse if defined
as waste products from coal mining, preparation or physical preparation. For coal,
NOX emissions standards are also based upon coal type. Note that boilers firing 25
percent by weight of North Dakota, South Dakota, or Montana lignite in a slag-tap
furnace have the highest allowable emissions.
NSPS - SULFUR DIOXIDE & PARTICULATE
Electric Utility Steam Generators
with Heat Input > 250 MMBtu/hr
Apply to Units Constructed After 9/18/78
or Significantly Modified Units
Fuel
Coal
Oil
Gas
Pollutant
S02
Particulate
S02
Particulate
SO2
Particulate
Allowable Emissions
Rate (lb/10« Btu)
1.2
0.6
0.03
0.8
0.2
0.03
0.8
0.2
0.03
Emissions
Reduction
90%
70%
99%
90%
0%
70%
90%
0%
Slide 22- 12
The NSPS for electric utility boilers requires two standards to be met: 1) a
maximum emission rate and 2) a percent reduction in potential emissions. The
percent reduction is calculated based upon the amount of emissions which would be
present in the absence of any controls.
22-13
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NSPS - NITROGEN OXIDES
Electric Utility Steam Generators
with Heat Input > 250 MMBtu/hr
Apply to Units Constructed After 9/18/78
or Significantly Modified Units
Allowable Emissions Emissions
Fuel Rate (Ih/lOfi Btu) Reduction
Gaseous Fuel:
Coal-Derived 0.5 25%
All Other 0.2 25%
Liquid Fuels:
Coal-Derived 0.5 30%
Shale Oil 0.5 30%
All Other 0.3 30%
Solid Fuels
Coal-Derived 0.5 65%
Fuel (25% coal Refuse) (1) (1)
Fuel (25% lignite/slag) 0.8 65%
Fuel (25% lignite/other) (2) (2)
Subbituminous 0.5 65%
Bituminous 0.6 65%
Anthracite 0.6 65%
All Other 0.6 65%
(l)exempt from the NOX standards and monitoring requirements.
(2) fuels in this category are not prorated.
Slide 22-13
22-14
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Federal regulations define the following potential combustion concentrations (e.g.
uncontrolled emissions) to be used in calculation of the potential emissions reduction:
• Particulate emissions:
7.0 Ib/million Btu heat input for solid fuels.
- 0.17 Ib/million Btu heat input for liquid fuels.
• Sulfur dioxide emissions to be calculate based upon the fuel
analysis.
• Nitrogen oxides emissions:
- 0.67 Ib/million Btu heat input for gaseous fuels.
- 0.72 Ib/million Btu heat input for liquid fuels.
- 2.3 Ib/million Btu heat input for solid fuels.
POTENTIAL COMBUSTION CONCENTRATIONS
Pollutant
Particulate
SO2
Fuel Type Concentration (Ib/MMBtu)
Solid 7.00
Liquid 0.17
All Based Upon
Fuel Content
Solid 2.30
Liquids 0.72
Gaseous 0.67
Slide 22-14
For utility boilers firing multiple fuels, the applicable NOX standard (in pounds
per million Btu of heat input) is calculated based upon a special formula:
En = [0.20 w + 0.30 x + 0.50y + 0.60 z + 0.80 u]/100
where: En is the emissions standard for firing combined fuels, w is the percent of heat
input from the combustion of fuels subject to the 0.20 Ib/MMBtu standard, x is the
percent of heat input from the combustion of fuels subject to the 0.30 Ib/MMBtu
standard, y is the percent of heat input from the combustion of fuels subject to the
0.50 Ib/MMBtu standard, z is the percent of heat input from the combustion of fuels
subject to the 0.60 Ib/MMBtu standard, and v is the percent of heat input from the
combustion of fuels subject to the 0.80 Ib/MMBtu standard. Consult 40CFR60.44a
(c) for details.
22-15
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Owners of electric utility boilers which are subject to these regulations are
required to install, calibrate, maintain and certify continuous emissions monitors for
opacity, sulfur dioxide, nitrogen oxides. Oxygen or carbon dioxide monitors must be
installed at all points where sulfur dioxide and nitrogen oxides are measured. Sulfur
dioxide emissions must be monitored at the inlet and outlet of any sulfur dioxide
control device. Outlet emissions monitoring only is permitted for units classified as
resource recovery facilities, units burning anthracite, and solid fuel burning units in
noncontinental areas. Fuel monitoring may be substituted for an emissions monitor
upstream of the control device.
CONTINUOUS EMISSIONS MONITORS
Requirements:
Install
Calibrate
Maintain
Certify
Record Output
Monitor:
• Opacity
• Sulfur Dioxide
• Nitrogen Oxides
• Oxygen or Carbon Dioxide
Slide 22-15
Performance Standards for Steam Generators (>100 MMBtu Ihr)
Performance standards have been established for steam generating units used
in industrial, commercial, or institutional facilities6. These standards apply to each
steam generating unit that commences construction, modification, or reconstruction
after 29 June 1984 and that has a heat input greater than 100 million Btu per hour.
The performance standards for these units are summarized in the following table7.
Similar to the standards for sulfur dioxide emissions from electric utility boilers,
the standards for industrial boilers are based upon a concept of maximum allowable
emissions rate and percent emissions reduction from the uncontrolled level. As before,
the uncontrolled level is defined as the emissions that would occur based upon firing
the fuel in an uncleaned, uncontrolled state. The potential emissions are based upon
the fuel analysis.
22-16
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The standard for NOX emissions varies with fuel type and, for coal, varies with
the type of boiler: spreader stoker, mass-feed stoker, pulverized coal, and fluidized
bed are the defined boiler types. For oil and gas fuels, the NOX standard also varies
with the heat release rate of the boiler. The heat release rate is defined as the design
heat input of the boiler divided by the total furnace volume.
The particulate standard also contains an opacity limit of 20 percent.
SOURCE PERFORMANCE STANDARDS
Steam Generators with Heat Input > 100 MMBtu/hr
Apply to Units Constructed After 6/19/84
or Significantly Modified Units
Fuel Pollutant
Allowable Emissions Emissions
Rate (lb/106 Btu) Reduction
Coal SO2
NOx:
Spreader Stoker
Mass-Feed Stoker
Pulverized Coal
Fluidized Bed
Particulate
Oil SO2:
Residual
Others
NOx:
HRR < 70,000
HRR > 70,000
Particulate
Gas NOx:
HRR < 70,000
HRR > 70,000
1.2
0.6
0.5
0.7
0.6
0.05
0.5
0.8
0.3
0.4
0.10
0.1
0.2
90%
0%
90%
HRR = Heat Release Rate in Btu/hr-ft3.
Slide 22-16
22-17
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Operators of boilers which are subject to these standards must install
continuous emissions monitors for sulfur dioxide, opacity,, and nitrogen oxides.
Continuous emissions monitors for oxygen and carbon dioxide must be installed at
points where sulfur dioxide and nitrogen oxides emissions are measured.
Similar to the provisions for utility boilers, sulfur dioxide emissions must be
monitored at the inlet and outlet of any sulfur dioxide control devices. Monitoring of
fuel sulfur content can be substituted for a sulfur dioxide continuous emissions
monitor at the inlet of the control device. Operators may also elect to use manual
sampling methods to monitor outlet emissions rather than installing a continuous
emissions monitor. Operators firing low sulfur fuel oil are exempt from the sulfur
dioxide monitoring requirements.
Boilers firing residual oil with a nitrogen content below 0.3 percent can elect to
develop and use a predictive methodology to estimate nitrogen oxide emissions based
upon monitored boiler operating conditions. Duct burners used in combined cycle
systems are exempt from the nitrogen oxide monitoring requirements.
Performance Standards for Small Steam Generators (10 to 100 MMBtulhr)
Performance standards have been established for small steam generating
units used in industrial, commercial, or institutional facilities^ These standards apply
to each steam generating unit that commences construction, modification, or
reconstruction after 9 June 1989 and that has a heat input greater than 10 million
Btu per hour, but less than 100 million Btu per hour. The performance standards for
these units are summarized in the following table.
SOURCE PERFORMANCE STANDARDS
Steam Generators with Heat Input 10-100 MMBtu/hr
Apply to Units Constructed After 6/9/89
or Significantly Modified Units
Fuel
Coal
Pollutant Allowable Emissions Emissions
Rate (lb/106 Btu) Reduction
SO2
Participate
Oil SO2
Wood Particulate
1.2
0.05
0.5
0.10
90%
Slide 22-17
22-18
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Similar to the standards for sulfur dioxide emissions large coal-fired industrial
boilers, the standards for small coal-fired industrial boilers are based upon a concept
of maximum allowable emissions rate and percent emissions reduction from the
uncontrolled level. As before, the uncontrolled level is defined as the emissions that
would occur based upon firing the fuel in an uncleaned, uncontrolled state. The
potential emissions are based upon the fuel analysis.
Operators of boilers that used an emerging technology for sulfur dioxide
emissions control must meet a standard of 0.60 Ib SO 2 per million Btu and achieve 50
percent control. Operators of oil-fired boilers may choose to limit fuel sulfur content
to below 0.5 percent by weight rather than complying with the emissions standard.
Fuel pretreatment can be used to comply with the reduction requirements; however,
it will not be credited to the reduction performance unless pretreatment results in a
50 percent reduction in potential emissions or reduces emissions to less than the
standard.
The particulate standard also contains an opacity limit of 20 percent. For
some boilers, this requirement may limit the permissible particulate emissions below
the allowable emissions rate.
22.4
Additional Standards
In addition to the New Source Performance Standards, boilers may also be
subject to additional emissions limits.
ADDITIONAL STANDARDS
REQUIRING EMISSIONS CONTROLS
Acid Rain Program (Title IV)
- SO2
- NOX
State Implementation Plans (SIP)
- NOX
- Hydrocarbons
- Particulate
National Emission Standards for
Hazardous Air Pollutants (NESHAP)
- Hazardous Organics
- Metals in flyash
Slide 22-18
22-19
-------
The three primary sources of controls will be due to requirements contained in
the acid rain provisions of the Clean Air Act established in Title IV, to limits
established in individual state implementation plans, and to standards established
under Title III of the Clean Air Act, Hazardous Pollutants. The requirements of under
Title IV will require significant reductions in emissions of both sulfur dioxide and
nitrogen oxides from electric power utility boilers. Provisions in the state
implementation plans may require additional control of nitrogen oxides and
hydrocarbons, particularly in ozone nonattainment areas, or particulate. The
NESHAP standards may require control of hazardous organic compounds resulting
from incomplete combustion or control of metal compounds contained in flyash.
Acid Rain Program
The objective of the acid rain program established under Title IV of the Clean
Air Act is to reduce emissions of acid rain precursors, both sulfur dioxide and nitrogen
oxides, from boilers used to generate electric power. In all, the provisions of the
program are designed to reduce annual sulfur dioxide emissions due to electric utility
boilers by 10 million tons by the year 2000. Thereafter, the provisions establish a
nationwide cap on annual sulfur dioxide emissions of 8.9 million tons. The initial
provisions of Title IV are also expected to reduce annual NOx emissions from utility
boilers by 2 million tons.
Reductions in sulfur dioxide emissions are to be achieved in two phases. In
Phase I, fifty percent of the total reductions will be achieved by limiting emissions
from power plants with a generating capacity above 100 MW. Total sulfur dioxide
emissions for large plants will be limited to 2.5 Ib/MMBtu multiplied by the average
fuel use during 1985 to 1987. The regulation specifically identifies the 111 plants
which will need to implement controls and their allowable emissions. These 111 plants
are the highest sulfur dioxide emitters in the United States. In Phase II, almost all
power plants rated at greater than 25 MW must limit emissions to below 1.2
Ib/MMBtu.
Sulfur dioxide emissions will be reduced though a new market-based scheme
under which power plants are allocated emissions allowances that will require plants
to reduce their emissions or acquire allowances from others to achieve compliance.
Under this scheme, one allowance is worth one ton of sulfur dioxide removed.
Allowances can be earned, banked, leased or bought. The emissions trading scheme
outlined in the Clean Air Act will permit utilities to emit more sulfur dioxide than
allowed by acquiring emissions allowances or to control to levels below those allowed
to generate emissions credits. This market-based scheme to emissions control is
expected to provide utilities with the ability to achieve compliance using the most
cost-effective control strategies.
22-20
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ACID RAIN PROGRAM
Purpose
• Reduce annual SOj emissions from electric utility power
plants by 10 million tons by the year 2000.
• Reduce NOx emissions from electric utility power plants by
2 million tons.
Sulfur Dioxide Control
Phase I (1995)
- Emissions limited to 2.5 Ib/MM Btu for plants greater
than 100 MW (111 affected plants).
- SC>2 allowance/trading scheme.
Phase II (2000)
Emissions limited to 1.2 ib/MM Btu for nearly all
power plants greater than 25 MW.
- Nationwide cap on utility SOj emissions at 8.9
million tons per year.
Nitrogen Oxides Control
• Emissions limits to be established by EPA.
• Preliminary limits:
Tangentially fired boilers = 0.45 ib/MMBtu.
Wall-fired boilers boilers = 0.50 Ibs/MMBtu.
• EPA to establish limits for cyclone boilers, wet bottom
boilers and boilers equipped with cell burners.
EPA to revise NSPS.
Slide 22-19
Emissions of nitrogen oxides will also be reduced under the acid rain program.
Preliminary limits for Phase I boilers were set at 0.45 Ib/MMBtu for tangentially fired
boilers and 0.50 Ib/MMBtu for dry bottom wall-fired boilers. EPA is in the process of
finalizing emissions limits for these boilers. Initial control limits are being established
on the basis of low-NOx burner technology. EPA will also be required to establish
limits for cyclone boilers, wet bottom boilers and boilers equipped with cell burners.
These boilers are not easily retrofitted with low-NOx burner technology. EPA is also
required to promulgate revised New Source Performance Standards for NOx
emissions from fossil fuel fired steam generating units.
22-21
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State Implementation Plans (SIPs)
Each state is required to develop a series of State Implementation Plans
(SIPs). In broad terms, SIPs are the detailed procedures that a state will use to
assure that NAAQS requirements are maintained or the detailed corrective actions
that a state will use to bring local areas into compliance. If areas are in compliance,
the state has broad flexibility in establishing emission criteria for all source
categories. Most states rely on the NSPS for stationary sources and mobile source
standards to limit emissions from automobiles. The states may elect to impose more
strenuous emission limits than suggested by the federal government. If an area is
out of compliance with the NAAQS, a completely different set of emission criteria are
imposed. Clearly, any new source represents an additional burden to an ambient air
situation that is already considered unacceptable. Accordingly, to add a new source,
that source must (1) meet extremely stringent emission control, requirements, and (2)
the owners must find a way to reduce emissions from an existing source that more
than off set emissions from the proposed new unit. Further, to remedy the non-
compliance situation in the area, states may require the existing sources make plant
modifications to reduce the emission rate for a particular pollutant.
STATE IMPLEMENTATION PLANS (SIPs)
• Plans for Implementing the Requirements of the Clean
Air Act at the State level.
• SIPs provide the road map for States to meet NAAQS
• Regulations may apply to New and Existing sources
• Regulations may be More Stringent than NSPS
• SIPs must be reviewed and approved by Federal EPA
• As SIPS are approved, boiler operators will need to
contact state regulatory agencies to determine
compliance requirements.
Slide 22-20
Across the nation, the need to bring ozone non-attainment areas into
compliance will likely require control of NOX emissions from boilers. These controls
may place stricter limits on NOX emissions that those established by the NSPS, and
may affect boilers not governed under the NSPS. In addition, further controls for
hydrocarbons or particulate may be required by the states.
Boiler owners and operators will need to contact state regulatory agencies to
determine compliance requirements as the SIPs are approved.
22-22
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National Emission Standards for Hazardous Air Pollutants (NESHAPs)
The NSPS address the group of criteria pollutants and are only applicable to
new sources. There are a variety of pollutants that have been determined to pose
immediate health risks to the exposed public. To address this situation, the EPA has
authority to develop National Emission Standards for Hazardous Air Pollutants
(NESHAPs). The major factors associated with NESHAPs are that these standards
are based on acute health risk determinations and they apply equally to all sources
covered by the regulations. That is, a NESHAP emission release rate requirement is
the same for existing sources and new sources. The 1990 Amendments to the Clean
Air Act required the EPA to conduct wide ranging research relative to a group of 189
compounds that are classified as hazardous air pollutants (HAPs). Many of those
pollutants are emitted from fossil fuel fired boilers. Those regulations have not yet
been enacted but it is likely that in the near future, control of HAP emissions will be a
major consideration for fossil fuel fired boiler operations.
22.5 Permits
Title V Overview
Title V of the Clean Air Act establishes a comprehensive federal permit
operating program for sources regulated under the act. The primary objective of this
provision is to include in one document all of the requirements concerning air
emissions that apply to a specific plant.
TITLE V-PERMITS
• Comprehensive Program for Federal Operating Permits
• Applies to significant sources of air pollution:
- Major sources of criteria pollutants
- Sources regulated by NSPS provisions
- Sources subject to NESHAP rules
• States to develop operating permit program based upon EPA
quidelines
• EPA to approve program plan
• Annual permit fees - $25/ton of pollutant, except CO
Slide 22-21
22-23
-------
The secondary objectives of Title V are to provide operators with the ability to have
flexibility to respond to changing market conditions and to generate money for states
to fund aspects of their emissions control programs.
Under the act, sources will be required to apply for and obtain an operating
permit. Sources required to obtain a permit are those which are classified as major
sources of criteria pollutants under the act, which are subject to the New Source
Performance Standards, or which are subject to the NESHAP regulations on
hazardous pollutants. Major sources of criteria pollutants include those which emit
100 tons per year and smaller sources in more extremely pollutant areas9.
States are required to develop a plan for administering the Operating Permit
Program. The program is to be based upon guidelines published in the Federal
Register on July 21, 1992. Following EPA approval of the state plan, the original time
line calls for the state operating permit program is to be established in late 1995.
States are allowed to charge annual permit fees of at least $25 per ton of each
regulated pollutant emitted excluding carbon monoxide.
Permit Program Elements
STATE PERMIT PROGRAMS
• Provisions for permit applications and their
completeness
• Requirements for payment of fees
• Authority to issue permits
• Provisions for reopening and terminating permits
• Provisions to ensure operating flexibility
• Permits to contain requirements for:
- Compliance certification
- Monitoring requirements
- Reporting Requirements
Slide 22-22
22-24
-------
The state operating permit program must contain specific elements dictated
by the EPA. The plan must contain provisions for permit applications and
determination of the completeness of the application. States are given authority both
to issue permits and to levy fees. The permit program is also structured to permit
reopening and terminating permits. The program also contains defining enforcement
authorities including civil and criminal penalties for sources not in compliance. Civil
penalties of up to $10,000 per day for individual permit violations may be levied.
Under the operating permit program, sources who determine that they need it
will apply to the state to obtain an operating permit. The state will review the permit
application and, if acceptable, will issue an operating permit. Each permit application
and final permit will be transmitted to the EPA. To permit business to have some
operating flexibility, the permit application can contain several different operating
scenarios that a business anticipates operating over to meet future market demands.
Once these scenarios are approved in the permit, businesses will be allowed to make
operating changes that may result in emissions increases without being subject to an
extensive and time consuming administrative review process.
When issued, an operating permit will contain all of the detailed information
regarding emissions from the source and several other requirements, such as
procedures for compliance certification, monitoring and reporting of emissions. Each
permit will be issued on a three to five year term.
Information Requirements
PERMIT INFORMATION REQUIREMENTS
• Location
• Type of source
• Owner/operator details
• Source and process description and an alternative
operating scenario.
• Emissions inventory information
• Compliance plan (if needed)
• Compliance certification
Slide 22-23
A significant amount of information will need to be assembled to submit a
proper permit application^. The table above details some of the requirements. State
and local authorities should be consulted to obtain the exact requirements for a
22-25
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permit application. The permit application will need to summarize pertinent
information regarding the source including: location, type of equipment, and names of
the owner/operator. The permit application will also need to include a detailed
description of the process, including fuels used, fuel firing rates, raw materials,
production rates, and operating schedules. Where possible, alternative operating
scenarios should be included.
A key element of the permit will be the development of a detailed emissions
inventory for a source. The emissions inventory will include quantifying emission
rates and emission points of all regulated pollutants. A description of air pollutant
control equipment should also be included. All emissions calculations should be
included in the application. Sources will need to determine whether they are in
compliance with state and federal regulations. Those that are in compliance will need
to submit a report certifying that the facility is in compliance. If a source is not in
compliance, a compliance plan detailing level of pollution control required, and a
schedule for achieving compliance will be needed.
22-26
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REFERENCES
1. Godish, T. Air Quality. Lewis Publishers, Incorporated, Chelsea, Michigan,
1991.
2. Moyer, C. and M. Francis. Clean Air Act Handbook: A Practical Guide to
Compliance, Clark Boardman Company, 1991.
3. Elliott, Thomas C., Standard Handbook ofPowerplant Engineering, McGraw-
Hill Publishing, 1989.
4. Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which
Construction is Commenced After August 17, 1971. Title 40, Code of Federal
Regulations, Part 60, Subpart D, U.S. Government Printing Office, July 1,
1991.
5. Standards of Performance for Electric Utility Steam Generating Units for Which
Construction is Commenced After September 18, 1978. Title 40, Code of Federal
Regulations, Part 60, Subpart Da, U.S. Government Printing Office, July 1,
1991.
6. Standards of Performance for Industrial-Commercial-Institutional Steam
Generating Units. Title 40, Code of Federal Regulations, Part 60, Subpart Db,
U.S. Government Printing Office, July 1, 1991.
7. Steam, Its Generation and Use, 40th Edition, Babcock and Wilcox Company,
1992.
8. Standards of Performance for Small Industrial-Commercial-Institutional
Steam Generating Units. Title 40, Code of Federal Regulations, Part 60,
Subpart DC, U.S. Government Printing Office, July 1, 1991.
9. Quarles, J. and W. H. Lewis, Jr. The New Clean Air Act. Morgon, Lewis &
Bockius, Washington, D. C., 1990.
10. Beckham, B. J. CAAA Title V Permit Regulations Vary from State to State.
Chemical Processing, pp. 29-38, March 1993.
22-27
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CHAPTER 23. CONTINUOUS EMISSION MONITORING
23.1. Statement of Purpose
23.2. General Classifications of CEMS
A. In-situ
B. Extractive
23.3. Components of CEMS
A. Probe
B. Sample Transport Line
C. Conditioning System
D. Analyzer and/or Detector
E. Data Acquisition System (DAS)
23.4. Usage of CEMS in Utility/Industrial Boilers
23.5 Analytical Methods
A. Spectroscopic
B. Luminescence
C. Electrochemical
D. Paramagnetism
23.6 Opacity Monitors
A. Single-Pass Transmissometer
B. Double-Pass Transmissometer
23.7 Flue-Gas Flow Monitors
23.8 Maintenance and Continuing Operations
A. Calibrations
B. Probe Blockage
C. Condensation
D. Leakage
Slide 23-1
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23.1
CHAPTER 23. CONTINUOUS EMISSION MONITORING
Statement of Purpose
This learning unit presents the design and operational features of
instrumentation which is used to measure the concentrations of selected gaseous
constituents and stack opacity. Instrumentation of this type is generally referred to
as continuous emission monitoring systems (GEMS). The term "GEMS" denotes the
entire system of instrumentation required to measure the gas constituents and
should not be confused with "analyzers" which are the subcomponent which actually
determines the concentration of selected constituents.
The following paragraphs contain the descriptions of GEMS classifications,
GEM components, analytical methods employed by analyzers, and operating and
maintenance procedures.
23.2
General Classifications of GEMS
Monitoring systems are categorized as either in-situ or extractive GEMS
according to the location of the detection device used and the means by which sample
gas is delivered to the analyzers.
CLASSIFICATION OF CEMS
In-situ
Extractive
Slide 23-2
The in-situ systems directly measure gas concentrations in the stack. In-situ
systems utilize a sensor that is mounted either in the flow of the gases or adjacent to
the gas stream. The term in-situ refers not to the placement of the sensor but rather
to the monitoring of the gases without conditioning. The typical in-situ system
utilizes electro-optical or acoustical techniques, where light or sound is transmitted
through the flue gas. The effects of the flue gas on the transmission are used to
provide a measurement of flue gas parameters.
23-1
-------
IN-SITU CEM SYSTEMS
Analyzer
and Detector
Slide 23-3
There are two categories of in-situ monitoring systems: in-stack monitors and
cross-stack monitors.
The in-stack system, samples at a specific point in the stack. Typically, this
type of in-situ sensor must be able to withstand high particulate loading and elevated
temperatures (>250 °F) and must be rugged in construction. These monitors use
both spectroscopic and electroanalytical techniques. The measurement of oxygen is
commonly performed using an in-stack monitoring system. These analytical
techniques are discussed in detail in Section 23.5.
Cross-stack monitoring systems measure the gas concentration along a path
greater than 10 percent of the stack diameter. The cross-stack monitoring systems
combine a light source shining across the stack with a receiver-analyzer. There are
two types of path monitors: single-pass and double-pass. In the single-pass
arrangement, the light source and receiver are located on opposite sides of the stack.
Single-pass systems are used for the measurement of gas concentrations, flue gas
velocity, and opacity. A double-pass monitor utilizes a reflector to redirect the light
beam back to the source where the detector is located. Double-pass systems are
used for measuring gas concentrations and opacity. Both of these are discussed in
Section 23.7.
In-situ systems have the advantage of providing near "real-time"
measurements. Some of these systems are typically mounted on the stack. These
systems must be housed in weatherproof enclosures to minimize the effects of
ambient conditions.
23-2
-------
EXTRACTIVE CEM SYSTEMS
Heated
Transport
Line Conditioning
System Analyzer
and Detector
Readout
Stack Gas
Slide 23-4
Extractive systems are by far the most common type of CEM system. These
systems withdraw a sample of the gas stream by using a vacuum pump and then
condition the sample by removing moisture, particulate, and reducing the
temperature to ambient. The analyzers used in an extractive system generally
operates on a dry basis. Therefore, the conditioning system must remove the
moisture prior to sending the samples to the analyzers. Analyzers are typically at a
convenient location within the plant and do not need weatherproof enclosures. A
disadvantage of extractive systems is the "lag" in response to the process conditions
which is a function of the internal volume of the extraction system (e.g. probe,
sampling line, and conditioning system) since the sample must travel through all
components of the sample extraction system. This lag time ranges from 5 to 10
minutes depending on the sample line length.
Another type of extractive system is the dilution-extraction system which uses
a carrier/dilution gas mixed with the sampled air. The dilution gas is supplied to the
extraction probe and creates a positive pressure in the sampling line. The dilution gas
is supplied downstream of a critical orifice opening which creates a vacuum to pull the
sample gas from the stack. The dilution of the sample gas by a ratio of 50 to 200
reduces the problems associated with dirty, wet and corrosive flue gases. The
conditioning system is similar to the extractive conditioning system with the
exception of the moisture control. Since the flow rate associated with these systems
is relatively high compared to the extractive system, typically the conditioning does
not remove the moisture from the sample. Like the in-stack monitors the readings
obtained from these systems is on a wet basis.
23-3
-------
CLOSE-COUPLED CEM SYSTEMS
Conditioning
System
Readout
Stack Gas
Analyzer
and Detector
Slide 23-5
Another type of extractive system is the close-coupled system which reduces
the "lag" time. Close-coupled systems refer to those systems which utilize a
conditioning system and analyzer both placed directly on the stack. Typically, a
sample is withdrawn from the gas stream and conditioned to remove particulate
and/or moisture and to lower the temperature. The sample then passes through a
detection chamber for measurement of the gas constituent of interest. The method of
detection varies but often involves wavelength-specific energy absorption in either
the ultraviolet (UV) or infrared (IR) range. This method has been successfully applied
to the measurement of the common gas constituents. Close-coupled systems are
often used in industrial settings where gas stream conditions prohibit the use of in-
situ systems and the response time from a conventional extractive analyzer would be
too long.
23-4
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23.3
Components of GEMS
So far we have discussed the general classifications for CEMS. This sub-
section deals with the components which typically comprise a system. Although not
every system will have every component, certain elements are present in all
systems. The five components which typically make up a CEMS are: (1) probe; (2)
sample transport line; (3) conditioning system; (4) analyzer and/or detector; and (5)
data recorder or data acquisition system (DAS). Each of these is discussed below.
COMPONENTS OF CEMS
Heated
Transport
Line Conditioning
System
Readout
Analyzer
and Detector
Stack Gas
Slide 23-6
Probe
The basic purpose of the probe is to provide continuous access to a
representative portion of the stack gas. For extractive systems, the probe should
therefore be:
• located to obtain a representative gas sample;
• protected from the buildup of particulate matter;
• unaffected by moisture, temperature, and vibration;
• capable of accepting calibration gases; and
• constructed of a corrosion resistant material such as stainless steel,
glass, quartz, or ceramic.
In the case of in-situ analyzers, the probe is typically not present or is a coarse
ceramic filter used to shield the sensor from particulate matter.
23-5
-------
Sample Line
Only extractive GEMS will have a sample line or conditioning system.
Typically, the gas sample from the probe is transferred to the conditioning system via
a heated sample line. The line is heated to prevent condensation of moisture since
water vapor and acid gases can easily condense in a nonheated pump and corrode the
interior. In addition, the condensing of the gas sample would result in an inaccurate
measurement of the gas concentration. In extractive systems utilizing the dilution
technique (discussed later in this subsection), heating of the sample line may not be
necessary. The sampling line must also be chemically and corrosion resistant to
minimize reactions and ensure long-life.
Conditioning System
The conditioning system typically provides a clean, dry sample to the
analyzers, however, not all conditioning systems remove the moisture from the
sample. Sample conditioning equipment usually includes primary and secondary
particulate filters as well as some type of water removal apparatus. The primary
filter is often located at the probe inlet. This filter serves to remove the coarse
particulate. The secondary filter, located downstream of the primary filter, removes
nearly all of the remaining particulate greater than 1 micrometer. Moisture removal
is typically accomplished either by condensation, permeation, or dilution.
Condensation of the moisture is accomplished by rapidly cooling the sample and
trapping the condensed water in a collection vessel. The standard approach uses a
compressor-type refrigeration unit. More recent systems have used thermoelectric
plate coolers or a vortex chiller. Permeation dryers can be used with or in place of
condensero. The operation of permeation dryers is based on the selective
permeability of water through a membrane.
The third method employed by some units for moisture conditioning is the
addition of dilution air to the sample stream. Moisture is not removed in this method
but merely diluted to a level acceptable to the analyzers being used. This step may
take place in the stack (probe) or at a remote location. Dilution requires the accurate
metering of air so that the diluted sample concentrations measured can be corrected
to the actual stack concentrations. Dilute ratios of 100:1 are typical, although higher
ratios are used for hot, moist gas streams.
Analyzer
The overall purpose of the analyzer is to accurately measure the concentration
value of the target gas. The components of the analyzers include detectors,
converters, and readouts. The variety of analytical techniques are discussed in
Section 23.5. As these analyzers measure selected parameters, a signal will be
received by the detector, converted to an electrical signal, and sent to a readout
instrument as a concentration value.
23-6
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DAS
The final subsystem of a GEMS is the data recorder or data acquisition system
(DAS). Typically, this is separate from the analyzer and incorporates the signals
from multiple analyzers on a single output. Often, the DAS is as simple as a pen
chart recorder. More sophisticated systems developed recently take advantage of
computer technology to develop systems which not only store the data on a
permanent media but also provide such functions as averaging and data trending. On
a daily basis, the CEM system operator or plant environmental engineer works more
with the DAS than with any other GEMS components
23.4
Usaee of GEMS in Utilitv/Industrial Boilers
GEMS typically used in utility and industrial boilers include analyzers for the
measurement of opacity, oxygen, carbon dioxide, carbon monoxide as well as NOX and
SO2- The specification for a GEMS applied to a given boiler depends mainly upon the
various state and federal regulations. Case in point, Title IV of the Clean Air Act
Amendments requires continuous monitoring of flue gas flow rate. State or local
regulatory reporting requirements may necessitate the use of CEMS for oxygen or
CO£ to correct other pollutant concentration to a given standard. Under local
regulatory agency requirements, some utility and industrial boilers are required to
correct pollutant concentrations to 3 percent oxygen although 12 percent CO 2 may
also be used by local regulatory agencies.
ANALYZERS TYPICALLY USED IN UTILITY
AND INDUSTRIAL BOILERS
Oxygen (O2)
Carbon Dioxide (CO2)
Carbon Monoxide (CO)
Nitrogen Oxides (NOZ)
Sulfur Dioxide (SO2)
Opacity
Flue-Gas Flow Rate
Slide 23-7
23-7
-------
23.5
Analytical Methods
In general, measuring techniques are based both on the physical and chemical
properties of gases. The method selected for gas analysis is primarily dependent upon
characteristics of the gas, but it can also be due to regulatory or process
requirements. Detection of individual gases is possible because of the unique
characteristics gases exhibit when subjected to specific analytical methods. These
characteristics determine the principles of design and operation of reliable CEMS.
ANALYTICAL TECHNIQUES
Spectroscopic
Luminescence
Electrochemical
Paramagnetism
Slide 23-8
The four analytical techniques to be discussed herein are spectroscopic,
luminescence, electrochemical, and paramagnetism.
Spectroscopic
One of the most common analytical techniques used in CEMS are
spectroscopic absorption techniques. Using these methods, CEMS are able to
identify and to measure the amounts of selected gases via the attenuation
(weakening) of a beam of electromagnetic radiation (EMR) at a specific wavelength.
This can also be referred to as "light" although it may not be visible. Specific
examples of electromagnetic radiation include ultraviolet, infrared, microwave, x-rays,
television, and radio waves as well as visible light.
Identification of a gas is possible because different types of gaseous molecules
are known to absorb specific, unique wavelengths of electromagnetic radiation.
Determining the amount of a particular pollutant gas is accomplished by converting
the percentage of absorbance (also called attenuation) to a concentration. This is
generally accomplished by comparison with a reference absorption of a known gas.
23-8
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BASIC SPECTROSCOPIC INSTRUMENTATION
Light Wavelength
Source Selector
Detector
Signal Processor/
Readout
Sample
Vessel
Slide 23-9
The five basic components of a spectroscopic instrument are:
• a stable source of EMR ("light"). This can be as simple as a standard
household light bulb;
• a wavelength selector or filter to isolate the desired wavelength;
• a sample chamber;
• a radiation detector/transducer used to convert the radiation energy into
an electrical signal; and
• a signal processor and readout.
23-9
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NDIR ANALYZER*
Beam
Chopper
Infrared
Source
Simple
Exheust
Seneor
Slide 23-10
Nondispersive infrared (NDIR) analyzers measure the amount of light
absorbed by a pollutant molecule. NDIR spectroscopy uses infrared "light". The light
is filtered to isolate the wavelengths which are selectively absorbed by gaseous
molecules. These instruments differ from dispersive infrared instruments in that the
light is not scanned or "dispersed." The filtered light passes through a cell that
contains flue gas extracted from the stack. Another portion of the light passes
through a cell which contains a reference gas which does not absorb any of the filtered
light. A detector senses the amount of light absorption in the sample cell relative to
the signal from the reference cell. This relative difference is output to a readout as a
concentration reading. NDIR instruments have been developed for measurement of
S02, NO, NO2, HC1, CO, and CO2.
23-10
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GAS FILTER CORRELATION ANALYZER
Light
Source
Beam
Alternator
Neutral Filter D-t.ctor
• • • • Tn rn
° ' ". • '-Is
• :•••-. la)
Slide 23-11
A variant of the NDIR technique, called gas filter correlation spectroscopy,
requires light, usually in the IR or UV region, to pass through the sample cell and into
a receiving unit. In this unit, the beam is divided into two beams which enter into two
parallel cells called the gas filter and the neutral density filter cells. The gas filter cell
contains a high concentration of the gas being analyzed, and therefore removes
nearly all of the energy of the light source. Thereby, the reference (gas filter) cell has
a zero transmittance (100 percent absorbance). The beam to the neutral density cell
passes through unchanged. The difference at the detector between the two beams is
related to the concentration of the gas of interest. This method has been successfully
applied to both in-situ (e.g. the sample cell is in the stack or ducting) and extractive
analyzer systems.
23-11
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DIFFERENTIAL ABSORPTION ANALYZER
u... .,!««
?ho,otub.
Mirror Calibration »amolo Colt
80,/NOx
Lamp
Recorder
Slide 23-12
Differential absorption spectroscopy is also based on the principle that certain
gas molecules absorb unique wavelengths of light. Unlike NDIR spectroscopy which
uses a sample and a reference cell, differential absorption uses two distinct reference
and measuring light wavelengths. The measuring wavelength corresponds to a
wavelength where the gaseous molecules of interest absorb light energy while the
reference wavelength corresponds to a wavelength in which the gaseous molecules of
interest absorb no light. The concentration of the gas is determined by rinding the
difference in energy for the two wavelengths. Some differential absorption systems
are single pass, in-situ monitors that use ultraviolet light. These can measure SO 2 or
NO, although by changing the optical system it is possible to measure other gases.
The differential absorption method can also be used in extractive GEMS.
Luminescence
Luminescence is the emission of light from an atom or molecule that has been
excited in some manner. Excitation refers to the temporary placement of electrons
into higher energy levels. As the electrons return to their normal levels, excitation
energy in the form of light is emitted. Two luminescence methods are used in the field
of source monitoring: UV fluorescence and chemiluminescence. The component
requirements are the same as for spectroscopic techniques though their configuration
is somewhat different.
23-12
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ULTRAVIOLET FLUORESCENCE ANALYZER
Limp
Sampto In
Sampl*
Exhauat
Slide 23-13
The UV fluorescence method of analysis is primarily used to measure SO 2
present in exhaust gas streams. SO2 molecules are excited by the use of UV light of
wavelength 210 nanometers. Excitation is the results of an atom's absorption of the
beam of EMR. As the molecule returns to a relaxed state, light is emitted. The
released light is detected and its intensity related to the gas concentration. A
constant background (concentration of other gas constituents) must be maintained in
order to account for quenching of the signal due to the emitted energy being absorbed
by other gas molecules. Typically, UV fluorescence analyzers are used in conjunction
with dilution extractive systems to account for background quenching.
23-13
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Chemiluminescence is the most common method used for the measurement of
NO and NO2- A chemiluminescent analyzer senses the light emitted in a chemical
reaction. In this application, excited NO2 molecules are produced by reaction of NO in
the presence of ozone. The light emitted as the NO2 returns to its ground state is
detected by a photomultiplier tube and related to the NO arid NO2 concentrations.
Chemiluminescence methods have the advantage of high specificity and sensitivity.
CHEMILUMINESCENCE ANALYZER
Sample
Exhaust
Slide 23-14
23-14
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Electrochemical
Two principal electrochemical techniques have been developed for the
measurement of gases in exhaust streams: polarography and electrocatalysis.
These method can quantify flue gases by measuring the currents or voltages that are
produced in the electrochemical cells.
POLAROGRAPfflC ANALYZER
Thin-Film
Membrane
Counter
Electrode
Signal Proceaaor/
Readout
Slide 23-15
Polarography utilizes analyzers which are basically diffusion-controlled
electrochemical cells. The current across the cell is proportional to the rate of
diffusion of the pollutant into the cell and also proportional to the pollutant
concentration. Being constructed much like batteries, the cells have a sensing
electrode, an electrolyte, and a counter electrode. The main difference from a battery
is that polarographic analyzers also possess a thin-film membrane through which the
pollutant must diffuse in order to initiate the electrochemical reaction and current
flow. Polarographic analyzers have been developed to measure gases such as C>2,
SO2, NO, NC>2, CO, and CO2- Different types of electrodes and electrolytes are
required depending upon which gas is selected. As with batteries, the electrolyte will
eventually be consumed and must be replaced. Because these type of analyzers
require clean, dry sample, they can only be used in conjunction with extractive
systems.
23-15
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ELECTROCATALYTIC ANALYZER
Sensing
Electrode
Thin-Film
Membrane
•WCounter
| Electrode^.
Signal Processor/
Readout
Slide 23-16
Electrocatalysis employs analyzers that use a solid electrolyte instead of a
liquid electrolyte. A thin film on the surface of the solid usually catalyzes the reaction
which allows gas molecules to migrate through the solid and generate a current. A
typical electrocatalytic analyzer uses a zirconium oxide (ZrOz) disc which has been
coated with a thin film of platinum. A reference gas (usually ambient air) at 21
percent oxygen is maintained on one side of the solid. The sample gas is on the other
side. Oxygen ions are generated at the platinum surface and then migrate through
the solid electrolyte. Electrons are released in the process as the system attempts to
reach equilibrium (i.e. the same concentration) of oxygen on both sides of the solid.
The electron flow is related to the concentration of oxygen in the sample. The ZrC>2
analyzer has the distinct advantage that it can withstand temperatures up to
1560 °F. This type of analyzer is commonly used as the oxygen sensor in the exhaust
system of newer automobiles to measure and adjust the fuel/stir mixture.
23-16
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Paramagnetism
Oxygen is known to exhibit paramagnetic behavior. That is to say that oxygen
is attracted by and interacts with a magnetic field. Although this property can be
used in several different ways to measure oxygen concentrations, one extractive
method is commonly used. The magnetodynamic technique is used in CEMS to relate
the oxygen concentration in the gas to disturbances in a magnetic field about a
torsion pendulum. Oxygen flows through the magnetic field and disrupts the
alignment of the magnetic charges which consequently causes the torsion pendulum
to turn. The degree of this movement can be related to the 02 concentration.
Paramagnetism can also be used to measure other diatomic molecules such as N2-
PARAMAGNETIC ANALYZER
Detector Signal Processor/
Readout
Slide 23-17
23-17
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23.6
Flow Monitors
Under the Clean Air Act Amendments—Title IV, emissions standards are
expressed in terms of mass emission rates as in Ib/MMbtu. This implies that flow
monitors are required as part of the CEM system. There are a number of techniques
currently available for monitoring flue gas flow rates. These techniques include:
differential pressure sensing, thermal sensing, and acoustic velocimetry.
FLOW MONITORING TECHNIQUES
Techniques
Instrumentation or Sensor
Differential Pressure Sensing Head Meters, Pitot Tube, Annubar
Fluidic Sensor
Thermal Sensing
Acoustic Velocimetry
Heated Sensor
Ultrasonic Tranducers
Slide 23-18
Differential Pressure Sensing
Pitot Tubes: A pitot tube consists of two tubes, one facing the direction of the flow of
the gas to measure an impact pressure and the other tube either perpendicular or
opposite to the direction of the flow to measure static pressure. The pressure
differential between the static pressure and the impact pressure is the velocity
pressure (Ap) and is measured using a manometer, Magnehelic gauge, or pressure
transducer.
VELOCITY AND VELOCITY PRESSURE RELATIONSHIPS
Vs = KpCp[(TsAp)/(PsM8)]i/2
Where: Vs = velocity of the gas
= constant
= pitot tube calibration coefficient
Ts = absolute temperature of the gas
Pa = absolute pressure of the gas
Ms = molecular weight of the gas
Slide 23-19
23-18
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Type-S pitot tube, specified in EPA Reference Method 2, is the simplest pitot tube.
The impact and static pressures can be monitored continuously using pressure
transducers. A thermocouple is usually attached to the pitot tube to monitor the
stack gas temperatures. A pitot tube is used to measure single point velocity only.
Multiple tubes can be used to average a flow distribution across the stack or duct.
Annubar: The annubar is a modified form of pitot tube that has multiple ports in a
pipe, located at the grid points of the stack cross section. These ports face the
direction of flow and give an averaged stagnation pressure over the stack diameter.
The static pressure is averaged using ports located behind the high-pressure ports.
Annubars are usually made specific to each application since port locations are
different from one installation to another, and the stack dimensions must be carefully
specified before the annubar is constructed.
The annubar and pitot tube are less sensitive to low flow rates than to high flow rates
because low pressure differentials are difficult to measure accurately. To clear the
tubes from pluggage, high pressure blowing with air is usually employed.
Thermal Sensing System
Thermal sensing systems are based on the transfer of heat from a heated body
to a flowing gas. This requires the use of two sensors; one heated and one unheated.
Slide 23-20 shows typical thermal sensing systems. One configuration uses two
platinum resistance wires wound on ceramic cylinders, which are then protected by a
stainless steel tube. The longer sensor is heated ; the shorter one is not heated.
These two resistance elements are connected to a bridge circuit that maintains the
temperature of the heated sensor. As the flue gas passes and cools the sensor, the
current through the element is increased to keep the temperature constant. This
current is related to the heat loss from the sensor. The unheated sensor is used to
compensate for the temperature changes in the gas.
The other configuration combines the heated and the unheated resistance
elements into a single tip (also called hot-wire anemonmetry). The tip is glass coated
and is typically applied to monitoring flow in noncorrosive atmospheres.
The thermal sensing systems measure mass flow rates directly, rather than
volumetric flow rates as in the case of pressure sensing systems, the rate of cooling
of the heated sensor is dependent upon the thermal conductivity of the gas, which is
dependent upon the gas viscosity and specific heat. Gas viscosity in turn is
dependent upon velocity over a given path and on the gas density. As a net results of
these effects, thermal sensing instruments produce an output that is proportional to
mass flow:
[Signal] ~ [Heat Loss] ~
where p is the density of the gas
23-19
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One advantage of the thermal sensing systems is that multiple sensors can be
combined easily in arrays to measure the average flow rate over the cross-section of
a duct or a stack. Because each sensor makes an independent measurement, it is
possible to monitor the gas flow distribution over the cross-section.
THERMAL SENSING SYSTEMS
A thermal-sensing
velocity probe
A hot-wire
anemometry sensor
Slide 23-20
Acoustic Velocimetry
This method measures the time it takes sound pulses to travel with and
against the direction of gas flow. Slide 23-21 shows a schematic of the acoustic
velocimetry technique. In this method, ultrasonic pulses in the rage of 50 kHz are
transmitted both upstream and downstream of the flow. Two transceivers are
located opposite each other on the stack at an angle of typically 45°. In each
transceiver, a piezoelectric transducer transmits ultrasonic pulses to the opposite
transceiver. The transducers both convert electric signals to acoustic signals and
acoustic signals to electric signals. The speed at which the pulses crosses the stack
is dependent upon whether it is going with or against the flow.
23-20
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ACOUSTIC VELOCMETRY
VS =
Slide 23-21
The stack gas velocity can be expressed as:
Va =
/ 1
[
2 COSOC tA
tfi
Where:
1 = path between A and B
t = transmit time from A to B
23-21
-------
ts = transmit time from B to A
Vs = gas velocity
a = angle between stack and path /
This expression gives the volumetric flow rate in actual cubic feet per minute when
used with stack cross-sectional area. Note that the expression is independent of
other gas properties such as density, pressure, or temperature.
Because the acoustic instrument is a cross-stack path system, it is not
subject to the corrosion and particulate fouling problems that may affect the in-stack
insertion-type probes. However, the particulate matter can foul the transceivers, so
purge air is blown directly through them.
23.7 Opacity Monitors
Many sources are required to monitor opacity. Opacity is defined as the
amount of attenuation of a visible light beam as it passes through stack gases. The
visible light attenuation by smoke is primarily due to the scattering of light by small
particles. Opacity monitors measure the effects of light scattering and absorption.
In its most elementary form, opacity from a source can be determined by
visual observation. Individual smoke readers observe the flue gas plume leaving the
top of the stack and record the relative opacity. Legally binding visual opacity
readings are allowed in most states if made by certified opacity (smoke) readers.
However, opacity observations are limited in precision and are somewhat subjective
based on atmospheric conditions.
Opacity analyzers are the simplest of the in-situ monitoring devices. Opacity
monitoring systems or transmissometers are composed of a light source, detector,
and associated electronic and optical components. Continuous opacity
measurements are made on a fixed line across the flue gas stack.
A transmissometer measures the transmittance of light passing through the
flue gas. Transmittance and opacity are related by the following expression:
% opacity = 100 - % transmittance
So, if all the light is transmitted through the flue gas, the transmittance is 100% and
opacity is 0%. A single pass transmissometer incorporates a light source, focusing
and diffusing lenses, and a detector.
23-22
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A single pass transmissometer incorporates a light source, focusing and
diffusing lenses, and a detector.
SINGLE PASS TRANSMISSOMETER
Collimating
tens
Collimating
lens
Detector
Rotary blower
Slide 23-22
23-23
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A double pass transmissometer has the distinct advantage of providing an
internal reference. The light beam is split to provide a reference and a measurement
beam. The reference beam is directed onto the detector while the measurement
beam crosses the stack and is reflected back to the detector. The transmittance is
determined by comparison of the reference and measurement beams. Calibration at
zero and span values is obtained through the use of standard filters which can be
inserted into the path of the beam.
DOUBLE-PASS TRANSMISSOMETER
Collimating
lens
Lght
source
Beam
splitter
Reflecting
mirror
] y^llMHMNHMNNIIHIIHMliNMttUUIIMiniHHIIinilllinilHIIHU'HHIIIIIIIMIMIMIIiniHMHIIMMN|t
ACROSS-STACK
\
Rotary blower
Slide 23-23
23.8
Maintenance and Continuing Ooerations
CEMS owners are responsible for implementing a written quality assurance
plan to ensure the validity of the data recorded. The plan, should include written
procedures for CEMS calibration, calibration drift determination, preventative
maintenance, data recording and reporting, accuracy audit procedures, and corrective
action for CEMS malfunctions. This plan will be very specific to the type of
analyzers incorporated into the CEMS. The following is a g;eneral discussion of the
operating and maintenance procedures for CEMS.
Operation checks are procedures performed on a daily basis to determine
whether the system is functioning properly. These procedures include daily zero and
calibration checks and visual checks of system operating indicators, such vacuum
and pressure gauges, rotometers, and control panel lights.
23-24
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OPERATION CHECKS
Routine Calibration
Probe Blockage
Condensation
Leakage
Optical Surfaces
Slide 23-24
Routine calibration of the individual instruments can be achieved through the
use of standard calibrated optical filters or through the use of zero and span gases,
depending upon the design of the instrument. Span gases must be analyzed or
replaced periodically to assure their validity. The calibration procedure for each
instrument is dependent upon its design. Generally, an extractive CEMS must be
zeroed and spanned using special bottled gases of known concentrations.
Nitrogen is normally selected as the zero gas. Span gases are selected to cover
the concentration ranges for the instrument. If a single span calibration is to be
completed, the span gas is generally selected at 80 percent of the full scale (FS) range
of the instrument. A three point (zero and two span) calibration would also include a
20 percent FS calibration gas. CEMS are normally zeroed and spanned at least once
per day, although some may require more frequent calibration to account for drift.
Calibration drift is the difference in the CEMS output reading from a reference value
after a period of operation during which no adjustments took place. The performance
drift specifications found in the federal regulations are 2 to 5% of the instrument span
value. In other words, if the reading from the calibration gases varies by more than 2
to 5% from the previous calibration, the system will need to be re-calibrated.
The blockage of the gas sampling probes and transport lines can be a serious
problem, particularly if the flue gas contains significant flyash. Monitoring the
system vacuum and rotometers provides an indication of possible problems. Filters
which are used to remove particulate must be cleaned or replaced routinely. Most
conditioning systems also include an arrangement for purging particulate matter
from the filter, lines, and probe periodically. The condenser, if present, must be
maintained at a constant temperature slightly higher than the freezing point to
prevent blockage.
Other problems related to the condensation of moisture and acid gases can
occur. These liquids can absorb gas constituents of interest and/or cause chemical
reactions which lead to scale build-up and corrosion. All components of the system
should be inspected for corrosion on a regular basis.
Leakage of gases into lines transporting collected samples to analyzers can
occur if the connections are not properly sealed. Vibration and thermal expansion
can cause leakage to occur. Because the sample line is generally below atmospheric
23-25
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pressure, leakage will occur into the sampling line. Leakage will result in sample
dilution and gas concentration readings which are lower than actual. The indication of
leakage will occur when the reading from the calibration results in a lower than
acceptable reading.
Although fans are provided to limit the accumulation of deposits on the optical
surfaces in opacity monitors, routine maintenance includes cleaning of such surfaces
and recalibration.
Closely related to the operations checks, a suggested maintenance checklist is
shown below with a brief description of the maintenance procedures.
GEMS MAINTENANCE CHECKLIST
Filter Cleaning
Sample Line Leakage Check
Optical Surface Cleaning
Pump Maintenance
Data Recording Equipment Check
Slide 23-25
Filter Cleaning The performance of the filter should be monitored for increased
pressure drop across the filter which would indicate pluggage. For the filters which
flow from the outside in, a visual inspection can be made to determine the cleanliness.
In most cases, a dirty filter is simply replaced.
Sample Line Leakage Check: The easiest method of determining leakage in the
sample line is to plug the end of the sample probe. When this is done and there is no
leakage, there will be no flow rate to the analyzers. When leakage is indicated, each
connection in the line needs to be inspected and adjusted accordingly.
Optical Surface Cleaning: The optical surfaces in the NDIR and NOX analyzer
periodically require cleaning. However, these surfaces should only be cleaned in a
clean laboratory environment equipped with the proper equipment to realign the
surfaces after the cleaning.
Pump Maintenance: Pump maintenance includes oil replacement, seal inspection and
replacement, diaphragm replacement, and motor bearing replacement. The need for
maintenance may be indicated by reduced sample flow rate, reduced vacuum, and/or
inability to perform the span check on the instruments.
Data Recording Equipment Check: To check the accuracy of the data recording
equipment, a voltmeter should be used to compare the voltage at the recorder to the
voltage output from the data acquisition system.
23-26
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REFERENCES
Jahnke, J. A., "Continuous Emissions Monitoring" Van Nostrand Reinhold,
New York, 1993.
23-27
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CHAPTER 24. PARTICULATE CONTROL
24.1 Control Methods and Typical Arrangement
24.2 Cyclones
A. Design Principles
B. Performance
C. Operator Duties
24.3 Electrostatic Precipitators
A. Design Principles
B. Performance
C. Operator Duties
24.4 Fabric Filters
A. Design Principles
B. Performance
C. Operator Duties
Slide 24-1
-------
24.1
24. PARTICULATE CONTROL
Control Methods and Typical Arrangement
Particulate matter (PM) constitutes a major source of air pollution. Particles
have a variety of shapes and sizes with a wide range of physical and chemical
properties. Particles are emitted from many different natural and manmade sources
including combustion sources, industrial processes, mining operations, motor vehicles,
volcanoes, forest fires, and pollen. This section presents information on the design,
performance, and operation of some typical particulate control devices used for the
removal of particles from boilers.
PARTICULATE CONTROL
Particulate Pollution Sources:
Boilers, Industrial Processes, Mining, Motor
Vehicles, Nature
Particulate Distribution in Boilers:
Bottom Ash, Convective Passes, Air Pollution
Control Device, Stack
Slide 24-2
Fossil fuels can possess high levels of ash comprising over 20 percent of the
fuel's mass. This ash consists of many elements including metals. Ash and unburnt
carbon from the gas suspended particulate which can fall-out in furnace bottom ash,
be removed in convective heat transfer passes, be captured by particulate control
devices, or emitted to the atmosphere.
Boiler's are generally equipped with cyclones, electrostatic precipitators, fabric
filters, wet scrubbers, or side stream separators depending on the particle capture
requirements. Other types of particulate control devices include venturi scrubbers,
sintered metal filters and ceramic filters. These particulate control technologies, are
more extensively found in specific applications where high efficiency capture of fine
particulate is required, or where extreme operating conditions exist.
24-1
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PARTICULATE CONTROL DEVICES
Cyclone
Electrostatic Precipitator
Fabric Filter
Wet Scrubber
Side Stream Separator
Slide 24-3
With the increasing need to reduce pollution, some boilers are equipped with
combinations of particulate control devices while others integrate pollution control
devices such as acid gas scrubbers with the more conventional particulate control
devices such as fabric filters. Cyclones are often used as an initial step in particle
removal since cyclone efficiency for fine particle removal is poor. This section will
focus on the three common and conventional particulate control devices, namely;
cyclones, electrostatic precipitators, and fabric niters. The wet scrubber operation is
discussed in Chapter 26 on SOX control since these devices reduce SOX emissions as
well as remove particulate. The side stream separator system is a recent
development in particulate removal. Its application is currently limited to retrofitting
existing mechanical collectors on spreader stokers firing a limited range of coal
types.3 The side stream separator system consists of a cyclone and a pulse-jet
baghouse which will each be discussed in the following sections.
24.2
Cyclones
The cyclone separator is typically incorporated as a pre-filtering process for
removing larger particles. Cyclones can operate at relatively high temperatures and
function without moving parts making operation simple. The cyclone chamber
provides angular (swirling) gas flow which causes the suspended particles to
accelerate towards the chamber walls. Particles, being denser than gas, separate
from the gas stream and impact the cyclone chamber walls. The cyclones are
erected vertically and the particles fall under gravity to the collection hopper.
24-2
-------
CYCLONE APPLICATION
Low Capture Efficiency
Poor Fine Particle Capture
Simple Operation and Maintenance
High Temperature Application
Slide 24-4
Design Principles
The cyclone device is typically positioned immediately downstream of the
boiler. The cyclone's service environment is dependent on its material of
construction. Cyclones can be constructed to withstand harsh environments such as
extreme weather conditions and high temperatures since they have no moving parts.
CYCLONE DESIGN
Vertical Gas Chamber
Axial or Tangential Gas Entry
Swirling Gas Flow
No Moving Parts
Slide 24-5
The cyclone is typically a vertically erected conical or cylindrical shaped
chamber which receives particle laden gas in the upper chamber region. The gas
enters either tangentially or axially in a downward spiral path around the chamber
walls. The spiralling motion causes the particles in the gas flow to accelerate to the
chamber walls where their momentum causes thenuto separate and fall-out of the
gas stream. The particles drop to the bottom of the cyclone by gravity and downward
motion of the gas. The particles fall into the collection hoppers and are removed by
an ash removal system. The cleaned gas still carries significant levels of fine
particulate which remain suspended in the flow due to their airborne characteristics.
The treated gas reverses direction at the bottom of the chamber and returns up the
center of the chamber and exits out the top.
24-3
-------
CYCLONE
aeM
-------
Performance
Cyclone removal efficiency is dependent on the gas velocity, rate of change of
gas direction and the particle size distribution, density and composition. The main
limitation of the cyclone is the inability to effectively remove small particles less than
5um in diameter. For small particles, the inertial separating force (particle
momentum) is low and the particles are more prone to remain suspended in the gas
stream.
CYCLONE PERFORMANCE
Capture Efficiency is Dependent on:
• Gas Velocity
• Chamber Diameter
• Particle Size, Density and Composition
Slide 24-7
The removal efficiency of a cyclone can be increased by increasing the swirling
velocity of the gas which increases the inertial separating force or particle
momentum. This is effectively accomplished by reducing the diameter of the cyclone
chamber or increasing the gas flow rate. Cyclone performance is effected by gas flow
rate since this effects the swirling velocity in the cyclone. Cyclone efficiency is
relatively insensitive to dust loading and in fact, the efficiency can increase with
higher loading due to particle interactions.
Cyclone efficiency is generally poor compared with the efficiency of
electrostatic precipitators and fabric filters. Cyclone efficiency is less than 20
percent for sub-micron particulate. Efficiency varies linearly with particle size from
5 percent for 0.5 micron particles to 50 percent for 3 micron particles.
Operator Duties
Process Monitoring: The pressure drop and inlet gas temperature are
monitored to assure proper operation. The pressure drop is monitored so that any
tendency of the cyclone to plug can be signaled by high pressure drop. Also leaks and
cracks in the cyclone can be detected by reduced pressure drop. Pressure drop is also
a function of gas flow and may be used as an indicator of capture efficiency.
Generally efficiency increases with higher pressure (i.e. higher gas flow). Monitoring
the inlet gas temperature may be required depending on the cyclone's application and
material of construction to operate above the acid dew point and avoid corrosive
conditions.
Inspection and Maintenance: Cyclones have minimal maintenance
requirements due to lack of moving parts. Cyclone wall corrosion, leakage, particle
deposits and plugging should be regularly checked. Life expectancy of cyclones is long
24-5
-------
and is only limited by material corrosion, erosion and thermal stresses and cracking.
Overall, the cyclone requires very little routine maintenance.
CYCLONE OPERATION
Pressure Drop and Inlet Gas Temperature
are Routinely Monitored.
Inspection and Maintenance Requirement
is Minimal.
Life Expectancy is Long
Slide 24-8
24.3
Electrostatic Precioitators
Electrostatic precipitators (ESPs) are more efficient at removing fine particles
than are cyclones. The electrostatic precipitators are available in a variety of
designs and can operate in dry or wet mode and in hot or cold gas conditions. Many
ESPs are operated in dry cold-side applications. The "cold-side" categorization refers
to the ESP located downstream of the air preheater. Dry cold-side ESPs operate
ELECTROSTATIC PRECIPITATOR APPLICATION
High Capture Efficiency
Lowest Capture Occurs with 0.1 to 1
Micron Particles
Extensive Monitoring Requirements
Automatic Controls
Low Routine Maintenance
Slide 24-9
without water spray and at gas temperatures below SOOT. The principles of
electrostatic precipitation are more complex than the principle of cyclone separation,
however, the fundamental process is the same. The suspended particles are
accelerated towards the electrostatic precipitator's chamber walls by electromotive
forces rather than inertial forces. The particles collect on the walls and are
periodically dislodged from the walls and fall into the collection hoppers. The typical
cold-side electrostatic precipitator is erected downstream of the air heater and is
configured with rod or wire discharge electrodes and flat collecting plates.
Electrostatic precipitators consist of a series of chambers with vertical hanging
24-6
-------
collecting plates, electrical power supplies and mechanical rapping devices to dislodge
particle build-up from the plate.
Design Principles
Electrostatic precipitators are a well established particle removal technology
for pollution control on utility boilers. Electrostatic precipitation is a process by
which gas suspended particles are electrically charged and passed through an electric
field which propels the charged particles towards the collecting plates. The charged
particles stick to the plates and periodically a rapping (impact) mechanism dislodges
the collected particles from the plates. The dislodged particles drop into the collection
hopper for removal.
ELECTROSTATIC PRECIPITATOR
COVE* PLATE
TOP f A/0
PMEi.
DISCHARGE ELECTP.OOC
RAPPER
INSULATOR
COMPARTMENT
COLLECTING
PLATE RAPPER
— SIX PANfL
COLLECTING
PLATE
(Reprinted from "Pollution En|ineerinf Guide to Fine Pirtculue Control in Air Pollution"
by P. Chenranisoff with pemuuion from Conner Publishing)
Slide 24-10
24-7
-------
Electrostatic precipitators can be found in both low or high temperature
applications up to material limits of 1300°F and down to the condensation point of
flue gas constituents. Precipitators are commonly designed for either hot- or cold-side
treatment. Hot-side precipitators, located upstream of the air preheater, have larger
collecting plate areas and are constructed of suitable steels to handle continuous high
temperature operation. The principle of electrostatic precipitation is carried out in
three main steps, namely; particle charging, particle collection, and particle removal.
The electrostatic precipitators can be classified in the following three types; tubular,
wire-to-plate and flat plate. Some ESPs have precharge chambers which divide the
precipitator into a charging stage and a collecting stage. These types of units are used
for particles which are characteristically harder to charge.
ESP DESIGN CHARACTERISTICS
Basic Physical Characteristics
• Number of Fields
• Number of Passages per Field
• Wire-to-Plate Spacing
• Collection Plate Surface Area
• Wire (or Rod) Diameter
• Aspect Ratio (Length to Height)
Electrical Characteristics
• Maximum Secondary Voltage
• Maximum Secondary Current
• Number of Sparks per Minute
Process Characteristics
Gas Volume Flow Rate
Even Flow Distribution
Particle Loading
Gas Temperature
Particle Size Distribution
Particle Composition
Particle Resistivity
Slide 24-11
The general configuration of an ESP is a wire (or rod) discharge electrode
positioned an equal distance between two collecting plates. The electrostatic
precipitator casing houses many passages of parallel collecting plates with wires (or
rods) suspended at regular intervals through the passage. The plates are further
compartmentalized into fields, with each field typically energized by its own set of
power supplies. A negative high-voltage direct-current power is applied to the
discharge electrodes and the collecting plates are grounded. The high-voltage, direct-
current power source produces a corona in the wire-to-plate spacing by ionizing the
gas. The corona creates an avalanche of negative ions traveling from the negative
discharge electrode to the grounded collecting plates. Suspended particles passing
24-8
-------
through the wire-to-plate spacing are bombarded by negative ions and become
charged. The high voltage electricity produces an electric field between the wire and
the plate which provides the electromotive force to attract the charged particles to
the collecting plates.
The charged particles which accumulate on the collecting surfaces must be
periodically dislodged. Dislodging the collected particle layer is accomplished in
several ways using either mechanical rapping devices or water. Typically, dry
electrostatic precipitators utilize mechanical rapping devices which strike the
collecting plates and dislodge the particles. The particles fall into the collection
hoppers and are removed for disposal. Wet electrostatic precipitators utilize water
to rinse the collected particle layer of the collecting surface. The wet electrostatic
precipitator is used effectively in the following conditions:
after flue gas has been through a wet scrubber,
low gas temperature and high moisture content,
high sub-micron particle concentration,
liquid particle collection,
for handling wet dust.
Newly designed ESPs have larger wire-to-plate spacings and use rigid rod
discharge electrodes instead of wire. The newer electrostatic precipitators are
capable of operating at higher voltage which increase the electric field strength and
the subsequent particle capture. Many electrostatic precipitators are equipped with
advanced controlled power supplies which monitor electrical condition and maximize
performance while minimizing power consumption. Advanced control units provide
features such as intermittent energization and spark rate control. Intermittent
energization switches off power repeatable for extremely short durations and
maintains ESP performance while minimizing power consumption. Spark rate is
important in the electrical operation. Sparking is a phenomenon which occurs due to
an ionized discharge to the collecting surface resembling an electrical arc. Excessive
sparking will reduce the applied voltage and waste power, insufficient sparking may
indicate that the ESP is not operating near its full potential. With automatic
controls, a desired spark rate can be specified and will be automatically monitored
and maintained.
Performance
Operating efficiency of the ESP increases with increasing plate area,
increasing voltage and decreasing gas flow rate. The precipitator's size is measured in
terms of specific collection area (SCA) which is the ratio of collection surface area to
gas volume flow rate. Electrostatic precipitators are least efficient at capturing
particles in the 0.1 to 1 micron diameter size range; however, when designed and
operated properly the ESP is still capable of excellent collection of particles in this
size range. Electrostatic precipitators capture submicron particulate with
approximately 90 to 95 percent efficiency. From the efficiency level for submicron
particles, the efficiency increases linearly to 99.9 percent for particles of 5 microns.
Operation is sensitive to fluctuations in gas flows, temperature, particulate and gas
composition, and particle loadings.
24-9
-------
ESP PERFORMANCE
Capture Efficiency is Dependent on:
• Specific Collection Area (SCA)
• Operating Voltage
• Particle Characteristics
Particle Size of 0.1 to 1 Micron is
Hardest to Capture
Particle Resistivity in the Range of
2x108 to 2xlOU ohm-cm is Best
for Performance
Slide 24-12
In addition, the electrostatic precipitator's effectiveness is strongly influenced
by the resistivity of the particles in the gas stream. Resistivity is a measure of the
resistance of the particulate matter to being charged. Normal resistivity for ideal
operation is between 2xl08 and 2xlOn ohm-cm.
Other factors which adversely effect electrostatic precipitator performance
include; misaligned electrodes, excessive dust build-up on collecting and discharging
electrodes, re-entrainment of collected particle especially during rapping, undersized
equipment, flow distribution within the ESP and the presence of non-ideal electrical
conditions.
Operator Duties
Process Monitoring: To assure proper operation, the inlet gas temperature,
flue gas flow rate and electrical conditions are monitored. On-line electrostatic
precipitator performance is typically monitored with a opacity meter, however,
continuous and reliable monitoring of electrostatic precipitator performance is
difficult. An electrostatic precipitator's performance is sensitive to flow rate, particle
composition and temperature and the electrostatic precipitator's response to these
parameters is relatively slow.
Temperature has a direct effect on particle resistivity and therefore
electrostatic precipitators must be operated within the designed temperature range.
Temperature changes due to changes in the boiler load may adversely affect the ESP
effeciency. For cold-side ESPs, the temperature range is limited to temperatures
above the condensation point and below the electrostatic precipitator's material limit
usually specified by the manufacturer. For hot-side electrostatic precipitators, high
temperature is preferred within the maximum operating range specified by the
manufacturer. Particle resistivity peaks at about 400°F and is lower for
temperatures greater than and lower than 400°F.
24-10
-------
The electrical conditions do depend on the type of ESP. For the conventional
cold-side wire-to-plate ESP, the voltage will range from 25 to 50 kV with even higher
voltage for wider wire-to-plate designed electrostatic precipitators. Spark rate is
often optimized on site but is generally between 50 and 150 sparks per minute. The
higher the secondary current the better. Secondary current may be quenched by
excessive particle loading. The secondary current density, which is the secondary
current divided by the collecting plate surface area, is often less than 100 nA/cm2.
The secondary current density can be calculated for each field by dividing the field
secondary current by the plate surface area in that field. Generally, the first fields
have the lowest current density because a significant percentage of the current goes
into charging the particles which are captured in fields downstream.
ESP MONITORING AND MAINTENANCE
Monitoring:
• Inlet Gas Temperature
• Gas Flow Rate
• Electrical Conditions
• Rapper Intensity
• Hopper Ash Level
Maintenance:
• Requires Highly Trained Personnel
• Requires Low Routine Maintenance
• Inspect for Electrode Misalignment,
Pitting, Ash Build-Up, Ash Hardening,
Hopper Blockage, Electrode Insulation
Cracks, and Rapper Performance.
Slide 24-13
Inspection 9nd Maintenance: Maintenance is required for cleaning carbon
deposits on plates which can cause short circuits, corrosion of plates, and erosion of
electrodes. Electrostatic precipitators are fairly sophisticated devices requiring
automatic controls for rectifier equipment, measurements systems for rapper
intensity, hopper dust level, and monitoring systems of gas process variables such as
gas flow and temperature. Because of this complexity, highly trained maintenance
personnel are required. The frequency of inspections and maintenance are typically
monthly for external systems such as power supplies, monitors, etc. and annually for
internal systems such as electrode conditions, electrical connections, etc. Internal
inspections and maintenance are conducted in hostile environments due to the
potential mechanical and electrical energy of the electrostatic precipitator. Annual
inspections are necessary of electrode alignment, electrode pitting, ash build-ups, ash
hardening, hopper performance, electrode insulation and rapper operations.
24-11
-------
24.4
Fabric Filters
Fabric filters, also commonly known as baghouses, are used to remove gas
suspended particles much like the filtration device on common household vacuum
cleaner. The fabric filter is utilized in relatively low temperature environments
around 350°F but always above the dew point of water and common acid gases. The
particle laden gas stream enters the fabric filter chamber and passes through
vertically suspended filter bags. Particles collect on the filters. Particle build-up is
periodically removed from the filters by one of a variety of methods. The collected
particles fall to the collection hopper situated below the filter bags.
Design Principles
Fabric filters are used to remove suspended particles from flue gas by
capturing the particles on the surface of a porous fabric. Pairticle laden gas enters
the collection device and passes through an array of cylindrical filtering bags which
retain the particles; and the clean gas exits through the outlet duct. The design of the
fabric filter system slows the gas velocity and evenly distributes the gas to all the
filter bags. Particle collect on the filters and form a dust cake on the surface of the
filters. As the dust layer builds, it becomes more difficult for particles to penetrate.
This increases both the pressure drop across the filters and the collection of the
particles. It is actually the dust cake which achieves the high efficiency collection of
particulate. For this reason, unless the filters are preconditioned (i.e. an artificial
filter cake is built-up) prior to operation, filter efficiency is lowest at start-up and
after the bags are cleaned.
FABRIC FILTER APPLICATION
High Capture Efficiency
Capture Efficiency Independent of
Particle Characteristics
Frequent Routine Maintenance
Monitoring, Inspection and Maintenance
is Simple
Slide 24-14
Fabric filters are usually externally heated and/or insulated to ensure that the
device remains above the minimum require operating temperature to prevent
condensation which can plug and corrode the filter bags. This is especially important
during start-up and shutdown operations when temperatures are likely to drop below
the gas dew point. Fabric filters' maximum operating temperature is limited by the
working temperature of the fabric. For many common filtering fabrics the maximum
operating temperature is less than 500°F. Fabric filters are equipped with spark
arresters upstream to prevent fugitive sparks and hot flyash from burning the filters.
24-12
-------
FABRIC FILTER
Fum«
Exhaust Ouct
To
Atmosh«r«
Induced Ftew
M»nom«t«r
Slide 24-15
24-13
-------
Filters are most effective at collecting particles when coated with dust,
however, too high a coating will create a high pressure drop across the filter. The
filters need to be cleaned periodically. When removing the dust build-up, it is
important not to remove too much dust cake since excessive dust leakage will occur
while fresh cake develops. There are four principal types of cleaning systems; pulse
jet, reverse gas, shaker, and sonic.
The pulse jet system utilizes high pressure air to clean the filters. The high
pressure air inflates the bags, cracking the external dust cake. When the air is
removed, the bags return to their original shape and the dust cakes drop into the
collection hopper. Pulse jet systems can be cleaned while on-line which allows
continuous operation of the unit. Filters can be maintained from outside the collector,
which allows the maintenance to be performed in a clean, safe environment. This
vigorous cleaning technique tends to limit filter bag life.
PULSE JET
High Pressure Air
Inflates Bag to Dislodge Dust Cake
On-line Cleaning
Vigorous Cleaning Limits Bag life
Slide 24-16
In reverse air systems the dirty gas enters the fabric filter and passes from
the interior to the exterior of the bags. The fabric filter must be divided into modules
which are taken off-line during cleaning. Air is introduced from the exterior of the
bags, collapsing the bags and cracking the interior dust cake which fall to the
collection hopper. The cleaning is accomplished at a relatively low air pressure which
results in maximum bag life.
REVERSE AIR
Low Pressure Air
Contracts Bag to Dislodge Dust Cake
Off-Line Cleaning Requires Modular
Fabric Filter System
Low Pressure System Provides
Maximum Bag Life
Slide 24-17
24-14
-------
Shaker systems move the tops of the bags in a circular path causing a wave
motion through the bag length. This causes the dust to crack and fall to the hopper.
Bags must have high abrasion resistance for this cleaning technique. In addition,
individual bags must be taken off-line for the cleaning process.
SHAKER
Mechanical Sinusoidal Bag Shaker
Off-Line Cleaning Requires Modular
System
High Abrasion to Fabric
Slide 24-18
Sonic cleaning, if used, usually augments another cleaning method. Sonic
energy is introduced into the filtering device. The sonic waves generate acceleration
forces that tend to separate the dust from the fabric.
SONIC
Augments Other Cleaning Techniques
Sonic Waves Generates Acceleration
and Dislodges Dust Cake
Slide 24-19
Performance
Fabric filters are very efficient at removal of particles of all sizes. Efficiency
ranges between 99 and 99.9 percent for particle sizes as low as 0.1 microns. Particle
capture is relatively insensitive to particle and dust physical characteristics such as
particle resistivity and dust loading. Efficiency is decreased as the gas-to-cloth ratio
increases, which increases as gas velocity increases. Gas-to-cloth ratio is a ratio of
the gas volume flow rate to the filter surface area and is a measure of the superficial
gas velocity through the filter. Particle capture efficiency is also dependent on the
frequency of bag cleaning, cake build-up, fabric type and weave, and on the physical
condition of the bags.
Operator Duties
Process Monitoring: Fabric filter operations are monitored by flue gas inlet
temperature, gas flow rate and pressure drop across the system. The baghouse
temperature must be maintained above the acid condensation point in order to
reduce corrosion and fabric wear. This is most important during boiler start-up and
shut-down conditions. If acid deposition occurs after shut-down, the acid moisture will
24-15
-------
settle on the fabric and eventually leave behind a residue which may contribute to the
brittleness of the bags and cause a failure when put into operation again.3 An
atypically high pressure drop can signify that bags are binding or plugging, gas flow is
excessive or fabric cleaning is inadequate. Low pressure drop signifies possible filter
holes and leakage, leakage between the bag and bag supports, or inadequate dust
cake formation. The fabric filter performance can be monitored with an opacity
meter.
FABRIC FILTER PROCESS MONITORING
Operation is Monitored by:
• Flue Gas Temperature
• Gas Flow Rate
• Pressure Drop
• Opacity
CEM
High Pressure can Indicate:
• Binding or Plugging of Filters
• Excessive Gas Flow
• Inadequate Filter Cleaning
Low Pressure can Indicate that Leaks and
Holes Exist Across the Filters.
Slide 24-20
24-16
-------
Inspection and Maintenance: Fabric filters require relatively simple operation,
maintenance and repair. However, they require frequent routine inspection and
maintenance. Several fabric filter inspections and maintenance items are required on
a daily and weekly basis. Filter bags require periodic inspection for correct tensioning
and conditions such as tears, holes abrasion, and dust accumulation on the surface.
The typical filter bag life is as much as 10 years using reverse air cleaning, but this
can be reduced to 2 years for improperly operated systems. Filter bags are fragile
and prone to hole formation if not handled carefully.
FABRIC FILTER MAINTENANCE
High Routine Maintenance is Required
Simple Operation, Maintenance and Repair Compared to ESP
Periodic Inspection of Filter Bags for Tears, Holes, Abrasion,
Leaks and Dust Build-Up
Cleaning Cycle Timing, Effectiveness and Equipment
Typical Bag Life is 10 Years but can be Reduced to 2 Years for
Poorly Operated Device
Slide 24-21
24-17
-------
REFERENCES
1. Elliott, Thomas C., Standard Handbook ofPowerplant Engineering, McGraw-
Hill Publishing Co., 1989.
2. McDonald, Jack R. and Dean, Alan H., Electrostatic Precipitator Manual, Noyes
Data Corporation, 1982.
3. "Fossil Fuel Fired Industrial Boilers - Background Information", Volume 1,
Chapter 4, EPA-450/3-82-006a, March, 1982.
4. Steam, Its Generation and Use, 40th Edition, Babcock & Wilcox, 1992.
24-18
-------
CHAPTER 25. NITROGEN OXIDES CONTROL
25.1 Overview
A. Sources
R, Species
C. Environmental Concerns
25.2 NOZ Formation
25.3 Control of NOX Emissions
A. Combustion Modifications
R. Post-Combustion Control
Slide 25-1
-------
25.1
Nitrogen Oxides Control Overview
SOURCES OF NITROGEN OXIDES
Mobile Combustion Sources
Automobiles, Trucks
Stationary Combustion Sources
Power Plants, Heaters
Natural Combustion Sources
Forest Fires, Volcanos
Non-Combustion Sources
Nitric Acid Manufacturing
Slide 25-2
Nitrogen oxides are emitted from almost all combustion sources, including
stationary sources such as power plants, mobile sources such as automobiles, and
natural sources such as forest fires. Non-combustion sources include those
associated with the manufacture and use of nitric acid and ammonia.
NITROGEN OXIDES
Nitric Oxide (NO)
Nitrogen Dioxide (NO2)
Nitrous Oxide (N2O)
Nitrogen Trioxide (^Os)
Nitrogen Pentoxide (^Os)
Slide 25-3
There are a number of different oxides of nitrogen which are listed above.
Nitrogen oxides are essential to the nitrogen cycle in nature. Nitrogen dioxide (N02)
can be converted to nitric acid in the atmosphere, which under normal circumstances
reacts to form nitrates which return to the earth as either dry deposition or
precipitation (rain and snow). Nitrates are an important natural fertilizer for organic
growth. However, the additional NOT produced by man-made sources shift natures
balance. NOX has been associated with respiratory disorders, corrosion and
degradation of materials, and damage to vegetation.
25-1
-------
For regulatory purposes, nitrogen oxides (NOX) are composed of nitric oxide
(NO) and nitrogen dioxide (N02), the two major combustion related oxides of nitrogen.
NO is the dominant molecular form produced during combustion. It undergoes slow
oxidation to NO2, with most of the conversion occurring in atmospheric air.
Commonly, NOX emission measuring instruments have provisions for measuring NO
and NO2.
Nitrous oxide is commonly known as laughing gas. It is a greenhouse gas
which reacts in the upper atmosphere (stratosphere) to form nitric oxide which
subsequently depletes ozone. 1 Nitrous oxide is generally not included as part of NOX,
because conventional NOr instruments do not measure it. Likewise, nitrogen trioxide
and nitrogen pentoxide are found in very small, trace quantities and are not
commonly measured.
ENVIRONMENTAL CONCERNS ABOUT NOX
Acid Rain
Damage to Structures
Damage to Water Quality & Fish Life
Sudden Release of Acids
Photochemical Smog
Impairs Human Health, Respiration
Stunts Growth of Vegetation
Oxidizes Materials
Slide 25-4
A significant fraction of the NOX emitted from stationary combustion sources
can result in either the formation of acid rain and/or photochemical smog.
Environmental concerns about acid rain can be related to the damage done to
structures, plants and fish-life both near and far from the emission sources. The
problems are worsened by the sudden release of acid materials, such as occurs during
the melting of snow which contains accumulated amounts of the acid precipitation.
Likewise, the first rain after a drought generally is much more acidic than normal due
to the scrubbing action of rain water on the atmosphere.
Photochemical smog is the brownish colored air, first identified in the 1940s in
the Los Angeles air basin. Sunlight causes the break down or disassociation of
nitrogen dioxide, which leads to a series of chemical reactions with hydrocarbons and
other gases. Photochemical smog formation is a transient process which varies with
sunlight, atmospheric mixing conditions, and the emissions of NO*, hydrocarbons and
other products of combustion. Photochemical smog is often trapped by an
atmospheric inversion, which prevents its dilution with fresh air. 2 Smog is
particularly observable by looking through the horizontal layers of such stratified air.
25-2
-------
The high oxidant levels associated with smog can impair human health,
particularly for those individuals with respiratory diseases. Other measurable effects
of smog are the stunting of growth of vegetation, the discoloration of fabrics, the
cracking of rubber, the deterioration of concrete structures, and the corrosion of
metals.
25.2
NOj Formation
NOX FORMATION -
FOSSIL FUEL FIRED BOILERS
FUELNOX
Combustion of Chemically-Bound Nitrogen
in the Fuel with Oxygen
THERMAL NOX
High Temperature Reaction of Nitrogen with the
Oxygen and Nitrogen from Air
PROMPT NOX
Oxidation of Fuel Bound Nitrogen under Fuel
Rich Conditions
Slide 25-5
Oxides of nitrogen formed in combustion processes are due to either the
conversion of chemically bound nitrogen in the fuel which produces "fuel NOX" and
"prompt NOX" or thermal fixation of atmospheric nitrogen and oxygen in the
combustion air which produces "thermal NOX".
Fuel NOT designates the NO formed by oxidation of the chemically-bounded
nitrogen in the fuel. Fuel-bound nitrogen occurs in petroleum and coal fuels. During
combustion, most of the fuel nitrogen will be released as molecular nitrogen (N2),
hydrogen cyanide (HCN), NO and ammonia (NHa), with a modest fraction remaining
with the char. Fuel nitrogen conversion to NO is highly dependent on the fuel/air ratio
for the range existing in typical combustion equipment. The stoichiometric and
mixing conditions will determine the fractions of the HCN and NHa which is oxidized
to NO. Conversions of fuel nitrogen to NO range from around 5% at starved-air
conditions to 50% under well-mixed conditions.
25-3
-------
Thermal NOX designates the NO formed through the mechanism of high
temperature oxidation of nitrogen from the air. A fuel with a low fraction of chemically-
bound nitrogen, such as natural gas, forms mainly thermal NOX. The formation rate
of thermal NO is dependent on the reaction temperature, the local fuel and air mixing,
and the residence time. The thermal dependency of NO generated is linked to the high
activation energy required to break the triple-bonded nitrogen molecules and to
disassociate the 62 molecules to supply O atoms needed to form NO.
NO formation decreases with increasingly fuel-rich mixtures due to the
preferential reaction of available oxygen with carbon and hydrogen. Fuel-lean
mixtures also suppress NO formation due to the fact that high excess air dilutes the
reaction mixture, thus depressing the reaction temperature. The temperature
depression effect of high excess air overrides the effect of the increased oxygen
availability. The amount of thermal NO formed is lastly determined by the residence
time in a high temperature region. Residence times in utility boilers at temperatures
sufficiently high to form NO have been hypothesized to be on the order of 0.01 to 0.05
seconds. Although the mean residence time for gases in a utility boiler furnace is on
the order of 1 to 2 seconds, the lower bulk gas temperature generally leads to
significant NO formation for most of this period.
IMPACT OF TEMPERATURE AND FUEL NITROGEN
ON NOX EMISSIONS
§
o
'3
00
'i
3
2
Nitrogen Content
Flame Temperature
Shapes of curves depend
on excess air level
Fuel Nitrogen Content
Flame Temperature
Slide 25-6
25-4
-------
Prompt NOX is formed during the early stages of the combustion process.
Combustion is initiated under fuel rich conditions which produces intermediate
hydrogen cyanide (HCN) species. After reacting with molecular nitrogen and
hydrocarbon compounds in this environment, the HCN then forms NO by oxidation.
Prompt NOX is a small contributor to the total NOX emissions. As a consequence, the
control of Prompt NOX is not as fully understood as the other two forms of NOX
production.
25.3
Control of NOj Emissions
The control of NOX emissions can be achieved by inhibiting the initial
formation of the NOX and/or reducing the NOX species after they form. Therefore, this
discussion is divided into two major categories: (1) Combustion modifications, and (2)
Post-combustion control processes.
NOX FORMATION REDUCTION TECHNIQUES
1. Decrease Primary Flame Zone Oxygen Level
a. Decrease overall oxygen level
b. Controlled mixing of fuel and air
c. Use of fuel-rich primary flame zone
2. Decrease Time of Exposure at High Temperature
a. Decreased peak temperature
b. Decreased adiabatic flame temperature
c. Decreased combustion intensity
- Increased flame cooling
- Controlled mixing of fuel and air
- Fuel-rich primary flame zone
d Decreased primary flame zone residence time
Slide 25-7
Combustion Modifications
A variety of NOX control methods use these NOX formation reduction
techniques singularly and in combination and are classified as combustion
modifications.
Operational modifications, such as low excess air (LEA) and burner-out-of-
service, are typically the simplest and least costly NOX control techniques.
25-5
-------
NOT CONTROL TECHNIQUES ~~
Combustion Modifications
Low Excess Air Operation
Burners-Out-of-Service (BOOS) Operation
Overfire Air (OFA)
Reduced Air Preheat
Low NOX Burners (LNB)
Flue Gas Recirculation (FOR)
Reburning
Slide 25-8
Low Excess Air Operation (LEA) - Boilers are always operated with an excess
of combustion air to insure complete combustion. Since the formation of thermal and
fuel NOX are directly related to the concentration of available oxygen in the furnace,
the level of excess air is one of the primary operating variables in the control of NOT.
The level of excess air also directly impacts boiler operating efficiency. The practical
limit of minimum excess air will vary with furnace design, maintenance, control
flexibility and fuel characteristics. Boilers designed to provide nearly equal air/fuel
ratios at all operating conditions have the potential to operate at the lowest excess
air levels. Windbox configuration, burner design, primary to secondary air flow ratios
as well as combustion air damper and control settings can have a significant impact
on minimum excess air requirements. Accurate monitoring of the level of excess
oxygen is necessary to optimize this NOX reduction technique. Likewise, monitoring
any increase in carbon monoxide emissions will allow early detection of localized
combustion problems.
NO* Emissions as a Function of Excess Air
OQ
I
00
o
o
1
<5
z
NOX
Excess Air (Boiler O2)
Slide 25-9
25-6
-------
Burners-Out-Of Service (BOOS) - Throttling of the fuel flow to selective
burners while maintaining partial or full air flow through these same burners is an
effective method of implementing staged combustion. Staged combustion involves
generating a fuel-rich region near the burner with the remainder of the air added
downstream in another section of the furnace. The limited availability of oxygen in
the fuel-rich region results in a reduction in the conversion of fuel-bound nitrogen to
NOX. Although this is an excellent method of reducing NOX emissions, extreme care
must be taken when implementing combustion in this manner. Boiler design
parameters which contribute to NOX emission control include the burner type, burner
zone heat release area, burner spacing, and windbox configurations. Redistribution of
combustion (staged combustion) produces variations in the heat transfer occurring in
the furnace. Therefore, monitoring of superheater temperature and reheater
temperature, as well as the oxygen and carbon monoxide levels, are necessary to
optimize BOOS.
Typical-Burners-Out-of-Service Patterns
for Face Fired Units
* O0O*
OOOOO
O OOOO
OOOOO
OOOOO
OOOOO
OOOOO
• O • Ot
0 t O*O
OOOOO
OOOOO
• oo o •
O ••• O
OOOOO
OOOOO
OOOOO
• •o ••
OOOOO
OOOOO
o • • • o
• oo o*
00*00
OOOOO
• Fuel Flow Terminated
O Burner in Service
Slide 25-10
25-7
-------
Overfire Air (QFA) - Another means of achieving staged combustion involves
the use of OFA operation. A portion of the combustion air is diverted to air ports
arranged above the burner elevation to generate an air blanket similar to that set up
in BOOS operation. This technique requires that the furnace be fitted with overfire
air ports as a retrofit or as part of the initial design. The location of these ports is
dependent on the flue gas flow pattern characteristics. The primary advantage of
using OFA is that it offers more flexibility for implementing the staged combustion
with varying operating conditions, if required. The entire burner region serves as a
first stage combustion region. A portion of the sensible heat of the flue gas is
removed prior to the addition of the OFA, thus reducing the maximum temperature
achieved. For pulverized coal-fired boilers, OFA has the added advantage of not
involving the pulverizer feed supply system and therefore does not limit boiler
capacity.
Combustion Zone NOX Control
CONVECTIVE
SECTIONS
li
RADIANT
FURNACE
BURNER
ZONE
AIR
HEATER
r
Slide 25-11
25-8
-------
Reduced Air Preheat - Significant reduction in NOX emission have been effected
for certain fuels through the use of reduced combustion air preheat temperature. The
implementation of such control involves minor hardware modification comprising
either of the installation of air preheater bypass ducts or the removal of air preheater
surface. The effect of reduced air preheat is to lower combustion temperatures, thus
lowering the formation of thermal NOX. Therefore, reduced air preheat is not an
effective means of control for oil and coal-fired furnaces where the fuel NOX
component is significant. Also, the use of reduced air preheat results in substantial
boiler efficiency losses since the heat, which is otherwise transferred to the
combustion air, is exhausted in the flue gas.
NOX Emissions as a Function of Air Preheat Temperature
O3
G
o
'i
a
a
Oil Fired
Gas Fired
Air Preheat Temperature
Slide 25-12
25-9
-------
Low NOj Burners (LNB) - A variety of LNB designs have been developed to
reduce NOX emissions from gas-,oil-, and coal-fired boilers. LNB designs control NOX
formation by (1) limiting the availability of oxygen in the primary combustion regions,
(2) reducing flame temperatures, and (3) reducing the residence time at peak
temperatures.
Each burner designer has a different approach toward achieving NOX emission
reduction while maintaining flame stability, complete combustion, and high turndown
ratios. The LNB designs can be categorized into four general groups determined by
the approach used to achieve reduced NOX emissions. The first burner group includes
designs that limit oxygen availability and reduce flame temperatures through two-
stage combustion. Burners generating localized off-stoichiometric conditions, both
fuel-rich and fuel-lean, form the second group. The third group uses self-recirculation
of furnace gases from the near-burner region into the flame to reduce peak
temperature and thereby NOr formation rates. The fourth and final group includes
the LEA burners primarily designed for high efficiency, low-NOx, low excess air
operation.
Burmeister & Wain Energi (BWE) Low NOX Burner
Tertiary
Air
Igniter Asi«mtty
Primary Air
Coal
RamcHoktor
Slide 25-13
25-10
-------
Flue Gas Recirculation (FOR) - The effect of FOR is a reduction in combustion
temperature and thus, suppressed thermal NOX formation. For the most part, inert
flue gas and/or steam are mixed with the combustion air and act as heat sink
materials to reduce combustion gas temperatures. Flue gas recirculation is often
used to control thermal NOX emissions from natural gas fired power plants. Steam
injection is a traditional means of NOX control in gas turbines. The flue gas injection
header is normally located in the combustion air duct at the exit of the air preheater.
The recirculation of the flue gas reduces the combustion product residence time in the
furnace cavity and increases the mass flow which provides more heat transfer in the
convective section. In some gas-fired boiler applications, the NOZ emissions have
been reduce by 30 to 60% with the introduction of FGR flow rates of 10 to 30%. The
application of FGR requires the boiler operator to monitor changes in heat
distribution due to the increased total flue gas flow rate.
NOZ Emissions as a Function of % FGR
73
§
a
w
o*
Percent FGR
Slide 25-14
25-11
-------
Reburning - Reburning is a three-stage NOX control technique which has been
applied in various fossil fuel power plants. In reburning, the first stage of combustion
is under excess air conditions to complete the combustion. The second stage occurs
downstream where an auxiliary fuel is injected into the combustion product gases.
The auxiliary fuel is typically natural gas or some other low nitrogen content fuel
although an emerging technology makes use of coal as the auxiliary fuel. Reburning
is generally designed to occur in the radiant section of the furnace, so that auxiliary
fuel is part of the overall energy input. Reburning creates a reducing atmosphere
with about 90 percent of the theoretically required air. The reburn fuel and NO are
primarily converted to CO, Na, and HaO. In the third combustion stage, burnout air is
injected in order to convert the CO to CO2-
It is possible for reburning to occur with the use of a conventional auxiliary fuel
burner. However, auxiliary fuel burners typically operate under excess air conditions
and are designed to increase combustion gas temperatures. Modifications would be
required to produce the required reducing atmosphere and the subsequent
downstream addition of air for complete combustion. Reburning has been
demonstrated to reduce NOX emissions by as much as 50-70%.
Gas Reburning Configuration
Overfire
Air Ports
Burnout
Reburning
Zone
Primary
Combustion
Zon*
Slide 25-15
25-12
-------
Operator Duties
In general, the combustion modifications for NOX control require little
additional effort from the boiler operator than monitoring of normal operation. The
operating boundaries for each of the modifications are specific to the boiler design.
For each combustion modification, extensive optimization testing of the boiler should
be performed to determine the optimal setting for the control parameters as a
function of boiler load. Once the combustion process has been modified for NOX
control, the following parameters should be monitored:
Operating Parameters to Monitor
CO Emissions
O2 Emissions
Superheater Steam Temperature
Reheater Steam Temperature
Boiler Efficiency
Soot/Slag Formation
Slide 25-16
25-13
-------
Post-Combustion Control
NOX reduction techniques applied downstream of the combustion zone are
categorized as post-combustion control technologies. These technologies, which
include Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction
(SCR), will be discussed in this section.
NOX CONTROL TECHNIQUES
Post-Combustion
Selective Non-Catalytic Reduction (SNCR)
Selective Catalytic Reduction (SCR)
Slide 25-17
Both of these technologies control NOX emission by injecting NOX reduction
reagents into the exhaust flue gas stream. The SNCR and SCR techniques have
some similarities to gas reburning. The contrasting feature is that gas reburning
provides an additional fuel input into the furnace combustion zone, whereas the
SNCR and SCR reagents are generally injected after the combustion zone.
SNCR - The operation of SNCR systems requires the injection of a reagent
material which can react with nitrogen oxide (NO) to produce nitrogen gas (N£). A
number of reagent materials can be used. Ammonia and urea are the most widely
used reagents. The process using ammonia for SNCR is generally known as Thermal
DeNOx, which is patented by EXXON. The process using urea for SNCR was
developed under sponsorship of the Electric Power Research Institute.
The SNCR process involves the injection of the reagent within the convective
section of a boiler. The process is implemented by the installation of an injection grid
at a location within the boiler where the optimum temperature occurs. The injection
grid generally covers the entire boiler cross-section to ensure good mixing between the
ammonia and the flue gas.
25-14
-------
Reagent
Injection
Post Combustion NO, Control SNCR
CONVECTTVE
LJ~
AIR
HEATER
Slide 25-18
The major operational factors which influence the performance of SNCR are
listed below. A properly designed SNCR system is required to have controls which
take into consideration the influences of these factors. The most important
constraint is the temperature of the flue gases into which the reagent is injected. M
Although the process will often work in the design temperature window from 1,600° to
1,800°F, the temperature at which the process works best will vary depending upon
which reagent is used and on the specific features of the application. For instance, a
complicating factor is that as the concentration of CO increases, there is a shift of
the effective range for the reduction reaction to lower temperatures. Because of the
variability of the combustion conditions, the practical limit of NO reduction is
considerably less than would occur under ideally controlled mixture conditions.
SNCR PERFORMANCE FACTORS
Reagent Selection
Temperature Region: 1,600°- 1,800°F
CO Concentration
Residence Time
Reagent Injection Rate Keyed to NO
Gas Mixing Efficiency
Slide 25-19
25-15
-------
Under steady conditions, the relative rate of reagent injection must be set to
obtain the amount of NO reduction desired. However, the fuel burning rates and
combustion gas temperatures will vary as the boiler load changes. Corresponding
variations will occur in residence times and NO concentrations. Therefore, the
injection rate must be metered in response to demand. In addition, mixing of reagent
and combustion gases must be appropriately controlled. The usual application
includes a heater for the reagent and a carrier gas stream to enhance injection of the
reagent into the furnace.
Either steam or compressed air can be used as the carrier gas. In some
applications the reagent is mixed with recirculated flue gas before being injected into
the flue gas stream. An air compressor or blower can be used to deliver the mixture
to various damper controlled nozzles which will control the injection location and to
regulate its delivery and mixing rate.
Operators should be aware that there are three possible reactions which can
occur when reagents are injected into the flue gas. The reduction reaction, oxidation
reaction, or neither type of reaction may dominate, depending upon the combustion
gas temperature and local mixture conditions.
COMPETING REACTIONS OF AMMONIA
Reduction:
4 NH3 + 4 NO + O2 —> 4 N2 + 6 H2O
Oxidation (Flue Gas too Hot):
4NH3 +5O2—> 4NO + 6H2O
No Reaction (Cool Flue Gas, Ammonia Slip):
NH3—> NH3
Slide 25-20
Ammonia will be used to illustrate the three types of reactions because it
undergoes a fairly simple set of chemical reactions. The first reaction in Slide 25-20 is
the reduction reaction, in which the ammonia causes the NO to be reduced back to
molecular nitrogen. This reduction process generally occurs if the gases are in the
right temperature range.
However, if the gas temperatures are too high (e.g. above 2,000°F), the
ammonia will undergo an oxidation process, forming additional NO. If the gas is too
cool, the ammonia will simply flow out with the combustion gases, or "slip" through
(or break through) without being reacted or influencing nitrogen oxide.4 If excessive
ammonia is injected, some of it may react with HC1 or sulfur compounds, forming
ammonium chloride or ammonium sulfate. These two products cause the formation
of a white or blue smoke, respectively.
25-16
-------
Urea offers an attractive alternative to the use of ammonia for the reduction
of NOX emissions. The urea compound dissociates to produce ammonia (NH 3). When
injected into the boiler in an aqueous solution the urea remains in solution essentially
until the liquid drop is totally evaporated. Therefore, the solution strength
(urea/water ratio) and degree of atomization (drop size distribution) can be controlled
to time the release of the NHa molecule in the boiler. Upon being injected into the
furnace, urea decomposes to ammonia and iso-cyanuric acid (HNCO). The ammonia
fraction performs in much the same way as in the thermal DeNOx process. The iso-
cyanuric acid can also react with NO to cause its reduction. A potential product of
reactions with the iso-cyanuric acid is nitrous oxide (N2O). However, reagent
additives are being developed to limit the formation of NaO by iso-cyanuric acid.
CHEMICAL DECOMPOSITION OF UREA, CO(NH2)2
CO(NH2)2 —> NH3 + HNCO (Iso-cyanuric acid)
Slide 23-21
The urea process offers several process variables that may be modulated to
optimize its performance in a practical application and provide the means to deal
with potential variations in injection temperature. These include modulating the urea
solution concentration and/or controlling the drop size distribution of the urea spray.
If too much reagent is injected or if the mixing or temperature levels are
inappropriate, some of the reagent can slip through unreacted.4 This reagent can
subsequently react into such compounds as ammonium chloride, ammonium sulfide,
or ammonium bisulfide. These materials may cause plume opacity and/or corrosion
problems.
25-17
-------
Operator Duties
The SNCR system will typically consist of the following components:
• Reagent Storage Tanks
• Air Compressor
• Reagent and Air Control Loops
• Microprocessor or Programmable Controller
Generally, the operation of these components will be automatically controlled.
However, potential operating problems may occur as listed below.
SNCR POTENTIAL OPERATIONAL PROBLEMS
Furnace Temperature Variations
Furnace Velocity Variations
NO Increases if T > 2,000 °F
Ammonia Slip - Can React to Form
Ammonium Chloride & White Smoke
Slide 25-22
The furnace temperature and velocity will change with boiler load. The use of
multiple injection ports will assist in maintaining NOX reduction efficiency. In less
sophisticated systems, the operator may be required to adjust the number of
injectors in operation for a given operating condition.
Excessive injection of ammonia with respect to the NOxin the flue gas will
result in ammonia slip. Since reliable ammonia monitors are not readily available, a
relationship between the boiler load and reagent injection rate needs to be maintained.
Thus, monitoring the furnace temperatures and superheater temperatures are
essential to proper operation.
25-18
-------
SCR - Selective Catalytic Reduction systems reduce the NOX in the flue gas to
molecular nitrogen and water by using a ammonia injection and a catalyst material
to increase the reaction rate. Depending on the application, NOX emissions from 70%
to 90% have been achieved, which is significantly higher than for SNCR systems.5 In
a SCR system, flue gas leaving the economizer at a temperature of about 750°F is
first mixed with ammonia in approximately a 1:1 NO-to-ammonia molar ratio. The
gas is then processed through the fixed bed catalytic reactor. The treated gas then
resumes the flow through the normal boiler system; i.e., air preheater, particulate
collection, etc.
Post Combustion NO* Control SCR
SCR
REACTOR
STACK
CONVECTIVE
C
SECTIONS
RADIANT
FURNACE
BURNER
ZONE
CEM
PARTICULATE
CONTROL
NH3 INJECTION ]
DISPOSAL /
RECYCLE
Slide 25-23
The ammonia is injected through a grid system into the flue gas stream
upstream of a catalyst bed as shown in Slide 25-24. On the catalyst surface,
ammonia reacts with NOX and forms molecular nitrogen and water.
25-19
-------
SCR Injection Grid and Catalyst Bed
Ammonia Lan
• NOX
• NOX
Exhaust ^
Gas ^ ' ^^
• NOX
• x
*A
Catalyst Bed
^ 0 NH3
• NOX
^ 0 NH3
^ • NOX
^ © NH3
• NOX
^ © NH3
r* • NO,
QN2
OH20
O N2 ^ Clean
QH20 Gas
O 2
OH2O
Slide 25-24
Many different types of catalyst composition and configuration have been
developed. Active metals used in catalyst include titanium and vanadium which are
resistant to SOX poisoning. Many other active metals are used but the exact
combination and bonding techniques for most catalysts are proprietary.
Operator Duties
Two basic process controls are essential for optimum NOr removal. One is
maintaining proper reactor temperature and the other is controlling the feed of
ammonia. Temperature control can be achieved by the processes previously
discussed. Ammonia feed control is essentially achieved by measuring the gas
throughput and the NOX concentration.
The major problem with most catalyst systems is that the gas must be
cleaned before the catalyst is used. Many metals such as copper, iron, chromium,
nickel, molybdenum, vanadium and cobalt can be used as the catalyst material. If
any dirty gas were to come in contact with the catalyst, its surface would become
fouled by the particulate and/or condensable materials. The conversion performance
would be considerably decreased by fouling of the catalysts.
Therefore, for a coal or oil fired boiler, a designer would have to provide for flue
gas cleaning before the gases enter the SCR process. Assuming that a spray dry
absorber and fabric filter system is used, the flue gas would be cooled to somewhere
around 400°F. This temperature is below the optimum operating temperature range
for the catalysts, which generally range from 530° to 800°F.4 Therefore, the flue gas
would have to be reheated, requiring either auxiliary fuel or the application of an air-
to-air heat exchanger.
25-20
-------
REFERENCES
1. H. Whalely et al., "Control of Acid Rain Precursors," Emissions from
Combustion Processes: Origin. Measurement, Control. Raymond Clement and
Ron Kagel, editors, Lewis Publishers, Chelsea, Michigan, 1990, pp. 315-316.
2. Philip A. Leighton, Photochemistry of Air Pollution. Academic Press, New York,
1961, pp. 1-5, 254-278.
3. "Nitrogen Oxide Control For Stationary Combustion Sources," EPA/625-5-
86/020, U. S. Environmental Protection Agency, July 1986, pp. 1-3.
4. Michael Medock, "An Overview of Non-Catalytic NOX Control," Solid Waste
and Power. February 1990, pp. 46-51.
5. "Sourcebook: NOx Control Technology Data," EPA-600/2-91-029, U.S.
Environmental Protection Agency, July 1991.
25-21
-------
CHAPTER 26. SOx CONTROL
26.1 Introduction
26.2 Wet Scrubbers
A. Operating Fundamentals
B. System Hardware
C. Operation and Maintenance
26.3 Dry Scrubbers
A. Semi-Dry Scrubbers
B. Dry Injection
26.4 Furnace Injection
Slide 26-1
-------
26. SO, CONTROL
26.1 Introduction
In the United States, Title IV of the 1990 Clean Air Act Amendments specifies
that annual emissions of SOX from utilities must be reduced by 10 million tons. To
achieve this, an Allowance system has been devised. Every year, each utility will be
given an Allowance by EPA to emit a certain number of tons of 862 in that year. The
utility then must decide whether to:
1. Buy additional SOz Allowances at the Chicago Board of Trade to cover
their actual SO2 emissions, or
2. Reduce their emissions of SO2 and either sell or save their unused
Allowances.
The choice will depend upon the cost of the SO2 control equipment and the cost of SO 2
Allowances on the market.
There are several options available to reduce SO2 emissions from utility and
industrial boilers: reducing the sulfur content of the fuel fired, or purchasing SO2
control equipment. The majority of the SO2 controls in place today on utility and
industrial boilers are the result of the NSPS regulations. To reduce the sulfur content
of the fuel used, the boiler can switch to low sulfur coal, oil, or natural gas.
Unfortunately, boilers are typically designed to fire a specific fuel, and switching can
reduce boiler efficiency and shorten boiler life. Alternatively, many large boiler owners
have already purchased flue gas desulfurization (FGD) equipment consisting mainly
of wet and dry scrubbers, and furnace sorbent injection systems. Each of these
systems are described in the following subsections.
26-1
-------
26.2
Wet Scrubbers
Of the approximately 180,000 MW of FGD systems installed worldwide, 85
percent are wet scrubbers. The advantages of wet scrubbers include high SOX
removal efficiencies coupled with efficient use of the scrubbing slurry. The following
sections describe wet scrubber operating fundamentals, system hardware, and
operation and maintenance requirements.
Operating Fundamentals
Wet scrubbers work by reacting the SOz in the flue gas with a scrubbing
solution. This solution is also often referred to as scrubbing liquor or scrubbing slurry.
The majority of operating scrubbers use lime or limestone as the scrubbing solution
because of its wide availability and low cost. Sodium based scrubbing solutions are
also used, but to a lesser extent. A popular wet limestone scrubber design is the
spray tower shown schematically in Slide 26-2.
Schematic of wet scrubbing spray tower system
Cleaned
"Flue Gas
To Stack
Mist-
Eliminators
Flue Gas From . —
Dust Collector ~*1 —
Limestone ,
Slurry Feed
^^vty^w/vf
SSSSSS m i
ywwwww
" » " "~ • '
2%s%a4
Absorber
Reaction.
Tank
Wash
Water
To Slurry
Nozzles
Recycle Liquid
Solids Disposal
Slide 26-2
After the flue gas passes through the boiler's ESP or baghouse, it enters the
scrubber horizontally just above the scrubber solution level. The flue gas travels up
through the spray nozzles where it contacts the scrubbing slurry. The SO 2 in the flue
gas is absorbed into the scrubbing solution and forms a disposable sludge. The
cleaned gas passes through the mist eliminators, and travels to the stack.
26-2
-------
The scrubber slurry side of the process starts with the fresh scrubber slurry
being pumped into the scrubber. The portion of the scrubber that contains the slurry
solution is often referred to as the reaction tank. Next, the scrubbing slurry is
pumped from the bottom of the tank to the slurry nozzles located approximately two
thirds of the way up the tower. The nozzles spray down against the flue gas flow. The
scrubbing solution reacts with the flue gas and most of the particles fall back into the
reaction tank, but some of the slurry (the smaller particles) can become entrained in
the flue gas flow and travel up toward the mist eliminators. The mist eliminators
serve to trap most of the particles entrained in the flue gas, and they are then washed
down to the reaction tank by wash water spray.
Not all of the slurry pumped from the bottom of the reaction tank is sent to the
slurry nozzles. A small percent is removed as waste, and is made up for by the fresh
slurry feed. The spent slurry is diverted to a thickener or hydroclone which removes
moisture. The dewatered slurry is disposed of, and the excess moisture is recycled
back into the reaction tank and is also used as mist eliminator wash water.
The chemical reactions governing SO2 reduction by lime or limestone scrubbing
are shown in Slide 26-3. As the flue gas contacts moisture, the gaseous SO 2 dissolves
to aqueous SO2- Aqueous SC>2 in turn forms bisulfite ion (HSOa"). At the same time
that the S02 is dissolving and ionizing, the limestone is also dissolving and forming
calcium ion (Ca++). The bisulfite ion formed from the SO2 combines with the calcium
ion, and forms calcium sulfite hemihydrate (CaS03»i/2H2O) and gypsum - solids that
are ultimately removed from the scrubbing solution.
Wet limestone scrubber chemistry
Gaseous S02
SO2 (gas) —> SO2 (aqueous)
S02(aqueous) + H2O —> HSO3'
Limestone
CaC03 + H+ — 5
HC0
HSO3"
1/2H20 — > CaS Gypsum
Slide 26-3
26-3
-------
Limestone and lime based scrubbing slurries are by far the most commonly
used scrubbing reagents. The main advantages of using lime or limestone include:
1. The process is simple and has few process steps.
2. Capital and operating costs are low and limestone is abundant.
3. SC-2 removal efficiency can be as high as 95 percent.
The main disadvantages of lime and limestone based scrubbing systems include:
1. Large quantities of waste must be disposed of in an acceptable manner.
2. Limestone systems have a tendency for scaling, plugging and erosion.
3. Large slurry flows are needed resulting in large pumps with high
electrical consumption.
In addition to lime and limestone scrubbing slurries, dual alkali systems are
also being used which use a mix of sodium carbonate (NaCOa) and lime or limestone.
The main advantage of the dual alkali process is that scaling (deposits of calcium
solids on the scrubber surfaces) is minimized. The main disadvantage is that sodium
may leak out of the system with the waste and potentially contaminate ground
water. While many industrial boilers utilize some form of sodium scrubbing, the
majority of the wet scrubber population are lime and limestone based systems.
Therefore, the remainder of this discussion focusses on lime and limestone scrubbers.
From the chemistry shown in Slide 26-3, it is clear that good removal of 862
depends primarily upon good contacting of the bisulfite ions (formed from S02 in the
flue gas) with the calcium ions. To achieve this, several design and operating
parameters must be considered including:
• Concentration and pH of limestone in scrubbing slurry,
• Scrubbing slurry flow rate compared to gas flow rate,
• Uniform distribution of the scrubbing slurry, and
• Uniform distribution of the flue gas.
The amount of limestone in the slurry controls the amount of calcium ion available to
react with the bisulfite ion. The chemical equations show that theoretically one
molecule of limestone is required to remove one SO 2 molecule. However, due to real
world limitations on how well the limestone and flue gas can mix, up to 1.2 molecules
of limestone are typically used for every molecule of SC>2.
26-4
-------
One would think that to achieve very good contacting of limestone to 862, one
should simply increase the concentration of limestone in the scrubber solution.
However, if too much limestone is added, the pH of the solution will rise (the solution
will become less acidic). The SOa removal reactions work most efficiently at pH
levels below approximately 6.3. Therefore, the amount of limestone added must be
high enough to allow contacting with SO 2, but not so high as to raise the pH above
6.3. Slide 26-4 shows the effect of scrubber solution pH on SOa removal.
Impact of slurry pH (acidity) on S(>2 removal efficiencyi
I
100
90
80
7°
50
l/g=2.5 liters/cubic meter
AP « 4 inches water
Two Stage Absorber
456
Scrubber Effluent pH
Slide 26-4
26-5
-------
In addition to limestone concentration in the scrubbing solution and scrubbing
solution pH, the slurry solution flow rate also determines what level of SC>2 reduction
can be achieved. The slurry flow rate is related to the flue gas flow rate and is
referred to as the liquid to gas ratio (1/g). In general, the higher the liquid to gas ratio,
the better the SO 2 removal efficiency will be. Typical limestone scrubbers operate at
liquid to gas ratios of approximately 30 gallons of slurry for every 1000 cubic feet of
flue gas. Since the flue gas flow rate varies with load, so must the slurry flow rate if
the design liquid to gas ratio is maintained. Slide 26-5 demonstrates how the liquid to
gas ratio (at a constant pH) impacts the 862 removal efficiency. As may be seen,
liquid to gas ratios above 30 gallons per 1000 cubic feet of flue gas does not
significantly impact SO2 reduction efficiency.
Impact of liquid to gas ratio on SO2 removal efficiency1
100
95
90
8 85
75
70
AP = 10"
water
= 5.8to7.1
Single Stage Absorber
i
10 20 30
Liquid to Gas Ratio (gal/1000 acf)
40
Slide 26-5
Even if the concentration of limestone, the pH and the liquid to gas ratio are
optimum, good SO 2 removal efficiencies will not be achieved unless the scrubbing
slurry is sprayed evenly into the flue gas. To mix the slurry with the flue gas as
rapidly and evenly as possible, it is best to have a lot of small nozzles distributed
across the scrubber cross section. If one or two nozzles only are used, pockets of flue
gas can escape the scrubber without being treated. Unfortunately, small nozzles
have a tendency to plug, so the final design must be a compromise between many
small nozzles that evenly distribute the scrubbing slurry but have a tendency to plug
and a few large nozzles that do not evenly distribute the slurry but will not plug.
Finally, care must be taken to ensure that the flue gas flow is evenly
distributed across the scrubber. For example, if most of the flue gas goes up the right
26-6
-------
side of the scrubber, there will not be enough scrubbing solution to react with all the
SC>2 on the right side, causing poor SC>2 reduction. There will be unreacted scrubbing
solution on the left side. The flue gas inlet duct at the bottom of the scrubber is
designed to promote even distribution of the flue gas across the scrubber cross
section. In some cases, perforated plates are used to help distribute the flow, but
these cause the pressure drop across the scrubber to increase resulting in a higher
electricity consumption by the fan.
System Hardware
Slide 26-2 showed a spray tower type wet scrubber, but there are several other
designs in use. These include the venturi, tray, and packed tower scrubbers. As seen
in Slide 26-6, the most prominent feature of the venturi design is a converging throat
section which causes acceleration of the flue gas flow. The scrubbing slurry is
introduced at the inlet of the throat and is sheared into fine droplets by the high
velocity flue gas stream. A turbulent zone downstream of the throat promotes
thorough mixing of the gas and slurry droplets. As the droplets slow down through the
diverging section, the droplets collide and agglomerate and are separated from the
cleaned gas stream by gravity as the gas passes on to the stack.
Venturi scrubber schematic
Gas
Scrubbing
Slurry
Drum Actuator [^C
Liquid Outlet ^D C
Scrubbing
Slurry
Movable
Drum
Mist
Eliminator
Slide 26-6
26-7
-------
Venturi scrubbers are usually employed to remove particulate as well as SO 2
since they can remove submicron size particulate matter. Despite the small slurry
droplet size, they do not absorb as much SOz as other scrubber types because the
amount of time available in the scrubber is short, and because the scrubbing slurry is
not injected against the flue gas flow. Many venturi scrubbers have adjustable throat
diameters to maintain constant flue gas velocity as the boiler load varies.
A tray tower scrubber is similar in design to the spray tower. The flue gas
enters at the base and passes upward through the holes in a perforated plate
mounted across the scrubber. Scrubbing slurry is sprayed onto the top of the tray
from above. The slurry on the tray becomes a froth due to the gas passing through it,
providing very good contact of the flue gas 862 with the slurry. The main
disadvantage of tray tower scrubbers is that they can not handle load variations (flue
gas flow variations). At low boiler loads, the slurry will drop through the sieve
(weeping) while at too high of a load, the slurry mixture is blown out of the scrubber.
Additionally, the tray holes are prone to plugging, and the scrubber must be shutdown
and cleaned periodically.
Packed tower scrubbers incorporate a bed of packing material (normally small
glass balls) mounted across the scrubber vessel. The flue gas enters at the base of
the tower and flows up through the packing against the slurry flow which is
introduced at the top of the scrubber. The packing slows the flue gas down and
provides increased surface area for the gas to contact the slurry, resulting in high SC>2
removal efficiencies.
Reagent Preparation and Injection Equipment
Typically, wet limestone and lime scrubbers employ on-site wet grinding
(slaking for lime) for slurry preparation. Slide 26-7 shows a typical limestone reagent
preparation system. The raw limestone with a diameter of approximately 1 inch is
fed through a weigh belt feeder to a ball mill. Water is added at the feed chute of the
mill. From the mill, the limestone is sent to a classifier which separates the coarse
limestone from the fine limestone. The classifier sends the fine limestone to the
limestone feed tank to be made into scrubber slurry. The coarse limestone is sent
back to the mill for more grinding. Grinds ranging from coarse (70 percent of the
limestone passing through a 200 mesh sieve) to fine (95 percent passes through a
325 mesh sieve). The finer the grind, the better the SO 2 reduction will be, but the
energy consumption for fine grinding is high.
26-8
-------
The spray nozzles used to control the slurry mixing with the flue gas typically
operate between 5 and 20 psi and have corkscrew tips. The nozzles produce many
droplets of approximately 2500 to 4000 microns in diameter. The SC>2 reduction
chemistry occurs on the droplet surfaces, so the smaller the droplets, the more
surface area is available for reaction, improving SC>2 removal efficiency. However, to
decrease the droplet size, nozzles with smaller openings are required. The pressure
required to push the slurry through smaller nozzles is high, and smaller nozzles tend
to plug.
Limestone reagent preparation system
Dry Limestone
Feed Bin
and Gate
Hydroclone
Classifier
Grinding
Water Supply
,,r • , Y-, , Underflow
Weigh Feeder T ... _^ , ,
6 I I- -CX- +1 Launder
Dilution Water
i-DXF-
Mill
Product
Tank
Main Process
Water -
Mill
Product
Pump
Slide 26-7
26-9
-------
Mist Eliminators
Mist eliminators are used on wet scrubbers to collect slurry droplets entrained
in the scrubbed flue gas stream and return them to the scrubbing liquor at the
bottom of the scrubber. Mist eliminators are located at the exit to the scrubber as
shown earlier in Slide 26-2. Most of the droplets drop out of the flue gas flow due to
gravity, but the small droplets can be carried out with the gas. If these droplets are
not removed from the gas before it exits the scrubber it can deposit on the ductwork,
the induced draft fan, and the walls of the stack. This may lead to pluggage and
corrosion.
Most mist eliminators are of the impingement type - the small liquid droplets
impact a collection plate, coalesce and fall by gravity back into the scrubbing liquor.
Slide 26-8 shows typical mist eliminator designs. The chevron vane is the most
widely used type. The mist eliminators are sprayed with wash water to remove
accumulated solids. The wash water is generally a mixture of fresh water and clear
water from the slurry dewatering system.
Examples of mist eliminator patterns
111111
\\\\\\
I I 1111
\\\\\\
Slats
Gas Flow Direction
A
rrr
rrr
Louvers
Chevrons
S Curves
Slide 26-8
26-10
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Waste Treatment and Disposal
There are several types of waste treatment and disposal methods currently in
use. The earliest method of waste disposal was simply to discharge the spent wet
slurry to a settling pond. However, site availability and pond management costs
have limited ponding in recent years. The most popular disposal approach in practice
in the U.S. today is to perform two separate stages of dewatering and then sending
the filter cake to a landfill.
The first stage of dewatering (primary dewatering) can consist of using
thickeners or hydroclones. After the primary dewatering, the sludge is between 20 to
30 percent solids. Secondary dewatering is accomplished with vacuum filters, or
centrifuges. Vacuum drum filters make up 80 percent of the secondary dewatering
equipment population. Normally before the dried sludge goes to a landfill, the sulfites
must be mixed with flyash and lime. Since gypsum needs no further treatment before
it can be landfilled or sold to wallboard manufacturers, some scrubbers employ forced
oxidation equipment in the reaction tank to convert the calcium sulfite hemihydrate
to gypsum.
Operation and Maintenance of Wet Scrubbers
No matter how well the scrubber has been designed, it will only work as well as
the operation system allows it to. Effective control of the scrubber system requires
effective communication between the scrubber operators and the boiler operators.
Operators must constantly monitor and control the system to ensure proper
performance. For example, when load changes occur, the scrubber operator needs to
reset the limestone feed rate and use the pH monitor as a backup. In addition to good
operation and communication, a preventive maintenance program specified by the
manufacturer should be implemented. Table 1 is an example checklist.
26-11
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TABLE 1. WET SCRUBBER INSPECTION CHECKLIST
Equipment
Scrubber Module
Agitators
Mist Eliminators
Wash Water Nozzles
Dampers, Fans, Ducts
Limestone Mill
Slurry pump
Slurry pipes
Valves
Thickener
Instrumentation
Action
Visually inspect for scale & corrosion
Inspect for corrosion and erosion
Check bearings and seals.
Check for scale
Monitor pressure
Inspect for corrosion and erosion
Inspect visually, lubricate
Check lining, bearings and seals
Check for deposits and wear
Test functionality, leakage, packing
Check coating for corrosion
Check moving parts for wear
Lubricate motor
Flush slurry lines
Calibrate
Frequency
Annually
Annually
Based on history
Once per shift
Annually
Each usage
Annually
Annually
Annually
Annually
Annually
Frequently
Daily
Once per shift
Slide 26-9
Visual inspection of the scrubber section and tanks should be performed on a
regular basis to identify leaks, scaling, corrosion and erosion problems. Visual
inspection can allow identification of small problems before damage becomes so
extensive that major repair is required.
Mist eliminators tend to be subject to buildup of slurry solids and chemical
scale causing the passages to restrict the flow of the flue gas. The first sign of scale
buildup is typically noticed by an increase in pressure drop across the scrubber.
Water washing is typically sufficient to prevent serious buildup problems.
Because the scrubber control system is based on flue gas and scrubber flow
rates, the operating staff should routinely monitor and record readings from all
instruments used to measure these flows. If any of the readings appear abnormal,
they should be investigated. To verify liquid flow rates or evaluate pump/nozzle
erosion, the operator should monitor pressure in the slurry header and the
recirculation pump discharge. An increase in the pressure usually indicates plugging
of nozzles. A decrease can indicate wear of the nozzles or pump impellers. Slurry
flow in pipes can be checked by touching the pipe. If it is cold at the normal operating
temperature, then the line is plugged.
26-12
-------
The slurry feed requirement is usually controlled by the pH indicator. The
sensor lines where pH measurement elements are used should be frequently
backflushed and calibrated with buffer solutions to ensure reliable operation.
26.3
Dry Scrubbers
Dry scrubbing is the second most popular form of FGD in the United States
after wet scrubbing. However, since dry scrubbing is a newer technology than wet
scrubbing, less than 50 systems have been installed to date. There are two types of
dry scrubbers: spray dryer (or semi-wet scrubber) and dry injection (or duct injection).
Spray Dryer
In dry scrubbing, the hot flue gas exiting the air heater enters the dry scrubber where
it is sprayed with a scrubbing slurry. The S(>2 in the flue gas reacts with the
scrubbing reagent and forms a solid particle. The hot flue gas dries the sulfur solids
formed before exiting the scrubber and traveling through either a conventional
baghouse or electrostatic precipitator. In the dust collection device, the fly ash and
newly formed sulfur particles are captured and disposed of. The general arrangement
of a dry scrubbing system is shown in Slide 26-10.
Configuration of Dry Scrubbing System
Stack
r^ra
Atomizer
I—Air Heater --•!-
r—CXI
Dry Scrubber
Baghouse
VVV
0
Reagent Preparation System
Slide 26-10
26-13
-------
The main difference from wet scrubbing is that dry scrubbing systems place the dust
collector after the scrubber.
Typically, flyash from the dust collector is recycled and mixed with the fresh
lime before injection into the scrubber. Atomization of the shirry is accomplished by
pneumatic or rotary atomization. Air is often used to help atomize the slurry into fine
droplets and to promote rapid and thorough mixing of the flue gas with the lime. A
schematic of a dry FGR scrubber system is shown in Slide 26--11.
Dry FGR Scrubber System Schematic 3
Pebble
Lime
Stack
Atomizing Reheat
Air (Optional)
Lime Slak ng
Dry
Scrubber
1
1
Pan ic ui ate
Collector
1
ID Fan
Dilution
To Waste
Disposal
-Recycle Sol KJs
Slurrying
Slide 26-11
26-14
-------
The dry scrubbing chemistry is slightly different from wet scrubbing
chemistry. Almost always, slaked lime is used as the reagent. Pebble lime (CaO) is
the raw ingredient. In the slaker, the pebble lime is reacted with water to form slaked
lime which is calcium hydroxide (Ca(OH>2). The chemical reactions governing SOa
removal are shown in Slide 26-12. As in wet scrubbing, the gaseous SC>2 is first
absorbed into water (becomes aqueous). Next, the aqueous S02 combines with water
and forms bisulfite ion (HSOs~). At the same time, the calcium hydroxide dissolves to
form Ca++ and OH~. The bisulfite ion reacts with the OH~ to form SO3=. Finally, the
calcium and sulfite ions combine to form the solid CaS03»i/2H2O. This solid is
captured in the dust collector along with the unreacted lime and boiler fly ash. A
portion of the captured ash is recycled to the slurry nozzles and the rest is landfilled.
Dry scrubbing chemical reactions
Gaseous SC>2
zsss
SO2 (gas) —> SO2 (aqueous)
SO2(aqueous) + H2O —> HSO3"
HSO3- + OH- —> SO3= + H20
Slaked Lime - Ca(OH)2
Ca(OH)2 —> Ca++ + 2OH'
SO3- + 1/2H2O —> CaSO3«i/2H2O
Slide 26-12
The operating parameters that impact the SO 2 removal efficiency of dry
scrubbers also differ somewhat from their wet scrubber counterparts. The two main
controlling parameters are:
• Flue gas temperature at scrubber exit,
• Amount of lime injected.
The following paragraphs describe each of these parameters.
Flue Gas Temperature: It is important to realize that the flue gas exiting the
dry scrubber is dry. In fact, the amount of water sprayed in with the slaked lime is
set by requiring the outlet gas to be dry. Typically, the gas temperature at the
26-15
-------
scrubber exit is set at 25°F above the saturation temperature (approximately
300°F), and then the amount of water that will cool the gas to this temperature is
calculated. It has been shown that the closer the exit temperature is to the
saturation temperature (the colder it is), the better the 862 removal efficiency will be.
However, the downstream equipment needs to be protected from condensation of
corrosive acid gases that can damage the induced draft fan or baghouse bags. In
some applications where high levels of SO 2 removal are required, the scrubber exit
temperature is very close to the saturation temperature. In these cases, the flue gas
is heated after it exits the scrubber to prevent condensation in the downstream
equipment.
Lime Injection: Because the water flow rate into the dry scrubber is set by the
scrubber exit temperature, liquid to gas ratio is not a parameter that can be varied to
improve S>02 removal efficiency as it is with wet scrubbers. However, the
concentration of lime in the solution can be varied. In wet scrubbing, less than 1.2
molecules of calcium can be injected for every molecule of SO 2 in the flue gas because
the solution pH must remain below 6.3. In dry scrubbers, the pH does not limit the
amount of calcium that can be injected, and the calcium to sorbent ratio can go as
high as 4.
Slide 26-13 illustrates the effect of calcium to sulfur ratio on 862 removal
efficiency. As can be seen, at calcium to sulfur ratios above 2, the amount of
improvement in 862 removal falls off. Typically, dry scmbber operators try to
minimize the amount of lime injected while still maintaining acceptable 862 removal
efficiency. This is done to minimize the costs of raw materials and disposal - the
more limestone injected, the more waste which must be disposed of.
It is interesting to note that when dry scrubbing is combined with baghouses,
862 at the exit of the baghouse is lower than at the inlet. Apparently the unreacted
lime in the layer of ash on the bags reacts with the uncaptured S02 and removes it.
On the other hand, ESP manufacturers point out that the scrubber exit temperature
is allowed to be lower for ESPs than for baghouses, thus enhancing SO 2 removal
efficiency. Therefore, neither system has a clear advantage over the other.
26-16
-------
Dry Scrubber Advantages/Disadvantages: The principle advantages of dry
scrubbing over wet scrubbing include:
1. Simpler operation
2. Dry waste products
3. Less expensive
Perhaps the most important advantage is the dry waste. This eliminates the need for
a costly sludge handling system. Capital costs are lower than wet scrubber costs
because less equipment is needed (thickeners, centrifuges, mixers, etc). Operating
costs are lower because less maintenance is required.
The principle disadvantages of dry scrubbing are that more reagent is required,
and thus the amount of collected solids to dispose of is higher. In addition, if sodium is
used as the reagent, it can leach into ground water supplies after it is landfilled
because it is very water soluble.
Effect of calcium to sulfur ratio on SO2 removal efficiency
100
— so
«
o
o
C/3
.*->
I
60
40
20 -
_L
_L
1 2
Calcium to Sulfur Ratio
Slide 26-13
Operating and Maintenance: Operational experience with spray dryer systems
indicates that only a few problems may typically be associated with these systems.
Some problems encountered include:
26-17
-------
Acid attack of the downstream particulate collection equipment. This is
due to acid condensation at some small, cornered areas in the baghouse
or the ESP not exposed to the flue gas. Acid condensate usually
corrodes the equipment supporting cages or fractures the bag cloth.
Wall deposits in the spray absorber. This is caused by fluctuations in
the solids contents (caused by plugging in the recycled solids preparation
system) to the atomizers. During operation, wall deposits automatically
fall down which causes plugging in the bottom of the spray dryer
absorber.
Dry (Duct) Injection
In the dry injection process, a dry, hydrated lime sorbent is injected directly in
to the flue gas downstream of the air preheater. Recycled solids, which are collected
from the ESP can be injected with the fresh lime to improve sorbent utilization.Water
is injected separately from the sorbent to cool and humidify the gas to the optimum
temperature and to wet the sorbent to enhance the sorbent-S02 reactions.
Optimum performance occurs in the dry injection process when the water is injected
in the same plane as the sorbent. The fly ash, reaction products, and unused sorbent
are collected in the ESP, a portion can be recycled, and the remaining solids are taken
to the plant's disposal area. A process flow diagram of the dry sorbent injection
process is shown in Slide 26-14.
Dry FGD Scrubber System Schematic «
tion Point
(Lime Sorbent)
Sorbwt & fly Ajh
Slide 26-14
26-18
-------
Unlike the FGD scrubber technologies, duct injection technology in relative new
and full scale application is still very limited. Duct sorbent injection technology
offers a low capital cost alternative to the conventional scrubber systems that are
currently in use. This is offset by higher operating costs; but for may older plants
that have very limited space for retrofitting SO 2 control technology and have a short
remaining plant life, lower life-cycle SC>2 control cost are anticipated. Other benefits
include process simplicity, minimal operation and maintenance requirements, and
non-hazardous solid waste product that can be disposed of easily. In addition, duct
injection technology, by using existing ductwork, requires very little additional space
for installation and results in few changes to the existing flue gas system. The time
required to install this technology should be significant shorter than that required for
conventional FGD scrubbers.
Because of the limited contact time and moisture available for the
sorbent-S02 reactions, SO2 removal via dry injection is limited to 50 to 75%.
Significant reaction rates between lime hydrate and S02 occur only if adequate
moisture is present on the sorbent particles. Therefore, the relative humidity of the
flue gas and the sorbent concentration are the most significant parameters
impacting S02 removal.
The waste solids generated from duct sorbent injection process have been
conducted extensively in laboratories for their physical, chemical and mineralogical
characteristics. Leaching tests show that the concentration of relevant elements in
the leachates does not exceed Resource Conservation and Recovery Act (RCRA)
limits. Therefore, under U.S. Environmental Protection Agency definitions, these
materials would not be classified as hazardous. Instead, these materials should be
classified as solid wastes under RCRA Subtitle D, and disposal will likely regulated by
the states.
26.4 Furnace Sorbent Injection
In a furnace sorbent injection process, a dry calcium based sorbent material
(CaCOa or Ca (OH>2) is injected into the upper region of a boiler furnace firing high to
medium sulfur fuels. The optimum temperature location has been shown to be where
flue gas temperatures are on the order of 2250°F. Under these conditions, the
injected sorbent decomposes to form CaO, which subsequently reacts with 862 to
form a solid, dry CaSO4. The dry product, which consists of CaSO4 and unreacted
CaO, mixed with the fuel ash, is removed in downstream particulate collection
equipment. The basic furnace sorbent process is shown conceptually in Slide 26-15.
26-19
-------
Furnace Sorbent Injection
Slide 26-15
Although the basic furnace sorbent injection process is well known, and has
been demonstrated and applied in many full scale utility boilers world wide, major
impediments to its commercial acceptance have been relatively low utilization of the
sorbent (typically 25% for Ca(OH)2) and an inability to achieve high rates of S02
removal (greater than 60%) without adverse impacts on boiler operation.
Like dry sorbent injection process, furnace sorbent injection is a simple process
and is most suitable for older boiler units having limited space around the boilers and
moderate SC>2 removal requirements.
The most impacts that furnace sorbent injection have on the boiler operation
are in the area of sootblowing and particulate removal equipment. Since the sorbent
material is injected upstream of the superheater and reheater platens, it tends to
increase the deposit (fouling) on these surfaces, thus requiring more frequent
sootblowing to keep them clean. In addition, sorbent injection increases the
particulate loading and changes the fly ash characteristics in the flue gas, thus
affecting the removal performance of the particulate collection equipment. In some
26-20
-------
furnace sorbent injection applications, a humidification system was added upstream
of the particulate collector (usually electrostatic precipitator) to enhance collection
efficiency.
Similar to duct injection process, the waste solids produced by the furnace
sorbent injection process would not be considered hazardous, and their disposal would
also be regulated by the states.
26-21
-------
REFERENCES
1. "Fossil Fuel Fired Industrial Boilers - Background Information Volume 1",
EPA-450/3-82-006a, U.S. Environmental Protection Agency, March, 1982.
2. "Overview of the Regulatory Baseline, Technical Basis, and Alternative
Control Levels for Sulfur Dioxide (SO 2) Emission Standards for Small Steam
Generating Units", EPA-450/3-89-12, May, 1989.
3. Steam, It's Generation and Use, 40th Edition, Babcock and Wilcox, 1992.
4. M. Satriana, New Developments in Flue Gas Desulfurization Technology, Noyes
Data Corporation, Park Ridge, New Jersey, 1981.
5. D.S. Henzel and B.A. Laseke, Handbook for Flue Gas Desulfurization
Scrubbing with Limestone, Noyes Data Corporation, Park Ridge, New Jersey,
1982.
6. Duct Injection Technology Approaches Commercialization, PECT Review, Issue
8, Spring 1993, Pittsburgh Energy Technology Center, Office of Fossil Energy,
U.S. Department of Energy.
7. Felsvang, K., H. Spannbauer, and P. Gedbjerg. "Scrubbing of Medium to High
Sulfur Coal - Industrial Operation Experience with Spray Dryer Absorbers."
1990 SO2 Control Symposium, Vol. 2. Sponsored by U.S. EPA/EPRI, New
Orleans, LA, May 8-11, 1990.
26-;
-------
CHAPTER 27. WATER POLLUTION
Slide 27-1
-------
27. WATER POLLUTION
An issue of increasing concern over the past decade has been pollution of rivers
and lakes from industrial processes and utility boilers. Normal operation of a boiler
requires aqueous discharges, such as boiler blowdown. In addition, for some air
pollution control technologies aqueous and solid wastes are generated which may pose
a threat to water quality if proper operation and procedures are not followed. The
Federal Water Control Act of 1972, the Clean Water Act of 1977, and the 1982
Amendments to the Clean Water Act authorize the Environmental Protection
Agency (EPA) to control discharges of 129 toxic chemicals into U.S. waterways by 21
different industrial categories, including boilers. The typical aqueous discharge
streams from a coal-fired utility boiler are shown in Slide 27-2. Oil fired boilers are
regulated on the operation and monitoring of the oil storage tanks to prevent
discharge of oil from reaching water.
Aqueous Discharge Streams From Utility Boilers
Coal Pile
Cooling Tower
and Condenser
Blowdown
Blowdown Water \
Chemical Cleaning
Waste Liquid .,. ^
M Water
FGD
Waste
Water
Settling
Pond
Slide 27-2
For regulatory purposes, the EPA has grouped the coal-fired boiler discharges into
several categories as follows:
1. Low volume wastes 6.
2. Non-chemical metal cleaning wastes 7.
3. Flue gas desulfurization 8.
4. Flyash transport water 9.
5. Bottom ash transport water 10.
Chemical metal cleaning wastes
Coal pile runoff
Once through cooling water
Cooling tower blowdown
Thermal discharges
27-1
-------
Four of these types of waste discharges have not yet been regulated: non-chemical
cleaning wastes, flue gas desulfurization (FGD) wastes, runoff from materials other
than coal pile, and thermal wastes. However, local water district and storm water
regulations do apply to any substance disposed of through these means.
TABLE 1. ALLOWABLE CONCENTRATIONS OF POLLUTANTS
Waste Streams and Pollutants
All Discharges
pH (except once through cooling)
PCBs
Low Volume Waste*
Total Suspended Solids
Oil and Grease
Bottom and Flyash Transport Water
Total Suspended Solids
Oil and Grease
Chemical Metal Cleaning Waste
Total Suspended Solids
Oil and Grease
Copper
Iron
Once Through Cooling Water
Total Residual Chlorine
Cooling Tower Blowdown
Free Available Chlorine
Zinc
Chromium
Other 126 Priority Pollutants
Coal Pile Runoff
Total Suspended Solids
Concentration Limits (mg/liter)
Daily
Maximum
6-9
0
100
20
100
20
100
20
1.0
1.0
0.2
0.5
1.0
0.2
0
50
30 Day Rolling
Average
6-9
0
30
15
30
15
30
15
—
—
—
0.2
1.0
0.2
0.0
—
* Includes: water treatment, evaporator and boiler blowdown,
lab and floor drains, FGD waste water.
Slide 27-3
Table 1 summarizes the allowable concentrations of pollutants in the seven
different discharge categories. The emissions from each of the discharge categories
are explained in more detail in the following paragraphs.
27-2
-------
Low Volume Wastes
Low volume wastes are defined as the collective discharges from sources that
are not individually regulated. These are discharges from:
1. Ion exchange water treatment
2. Evaporator and boiler blowdown
3. Laboratory and floor drains
4. Cooling tower basin cleaning wastes
5. House water system
The total amount of waste discharge in this category is very low compared to other
sources. Within the category, the biggest sources of pollutants are water treatment
and blowdown discharges. To demineralize and polish boiler makeup and condensate,
processes such as ion exchange regeneration, fixed bed polishing, and powdered resin
are used. In these processes, sodium, calcium and magnesium chlorides, ammonia,
iron, copper and zinc are waste products.
The amount and composition of evaporator and boiler blowdown water depends
upon many factors including boiler size, age, operating pressure and the composition
of the feedwater. Iron, copper, nickel and chromium may be present in small
amounts in the blowdown water since these metals can become entrained in the
boiler water as it travels through the tubes. Some boilers using phosphates for
cleaning may discharge very small amounts of phosphate.
Non-Chemical Metal Cleaning Wastes
One to four times a year, boiler tube deposits on the fireside are cleaned with
high pressure water hoses. The deposits are contained in the wash water discharge
which is approximately 6 million gallons per wash for a 500 MW coal fired boiler.
Since non-chemical metal cleaning is not currently specifically regulated, it is
classified under low volume wastes. Deposits from the furnace walls resemble
bottom ash while deposits from the superheater region are similar to flyash.
Flue Gas Desulfurization Waste Water
As described in Chapter 26, most wet scrubbers are designed to have no
aqueous discharge streams. The water that is removed in the drying step is typically
recycled back to the scrubber reaction tank. However, chlorides and flyash that
escape the dust collector can buildup in the slurry, and upset the delicately balanced
scrubber chemistry. These contaminants are removed by blowdown. The blowdown
stream contains calcium sulfate, calcium sulfite, and sodium chloride and trace
amounts of metal. Since FGD waste water is not currently specifically regulated, it is
commonly included in the low volume waste category. After the coal ash, the solids
byproduct from the FGD scrubbing process is the second major source of solids for
coal-fired boilers.
27-3
-------
Bottom and Fly Ash Transport Water
Bottom and fly ash become sources of pollution when they are transported
from their respective hoppers to a settling pond. Bottom ash is typically coarse and
tends to settle rapidly and not to dissolve. Flyash, is finer than bottom ash and can
dissolve into the water. Pollutants of concern are: calcium, magnesium, potassium,
sodium, iron sulfates and hydrous oxides.
Chemical Metal Cleaning Wastes
Every three to five years, the water side of the boiler tubes are cleaned with
chemical solvents to remove any corroded metal. Between 80,000 and 400,000
gallons of waste water are generated during a cleaning depending upon boiler size.
Iron, copper, nickel, zinc, chromium, calcium and magnesium are typically found in
the waste water. The concentrations of these pollutants in the discharge stream will
depend upon the cleaning system used, the materials that the boiler tubes are made
of and the age and condition of the boiler.
Coal Pile Runoff
Coal pile runoff is a result of rain water which falls on the coal storage piles and
travels to a drain, carrying coal particles with it. Total suspended solids are regulated.
27-4
-------
Once Through Cooling
After the steam exits the turbine, it needs to be condensed back to water
before it starts the cycle over again. Slide 27-4 illustrates a once through cooling
system used to condense the boiler water. The turbine discharge enters the
condenser where it is cooled and exits to the feedwater pump. The cooling water is
pumped from a river or lake. It passes through the condenser, cooling the boiler
water and heating up in the process. The heated water is injected back into the river.
Schematic of Once Through Cooling System
Turbine ,
Discharge i
i Boiler
1 Feedwater
Cooling Water
Boiler Water
Condenser
Slide 27-4
The pollutant of primary concern with a once through cooling system is
chlorine. Chlorine is typically added to the cooling water at the inlet of the boiler to
prevent biological growth (fungus and algae) on the tubes of the condenser which
would hamper the heat transfer. Typically, chlorine is injected into the condenser
inlet for less than 2 hours each day. When the hot chlorinated water is exhausted
back into the river or lake, it is very toxic to the plant and animal life in the area.
27-5
-------
Schematic of Cooling Tower Water Circulation
Turbine
Discharge
Boiler Water
Condenser
f Makeup Water
D
>PPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPP.
Slide 27-5
Cooling Tower Blowdown
Perhaps the single biggest contributor to aqueous pollution discharge is cooling
tower blowdown. In areas where water is scarce, the condenser cooling water must
be recycled. In this case, cooling towers are used rather than the once through
system. A cooling tower is shown in Slide 27-5.
The primary sources of pollutants in the cooling tower blowdown include:
1. Contaminants already present in makeup water
2. Chemicals added to control corrosion and deposits
3. Tower materials.
Contaminants present in the fresh makeup water to the cooling tower may include a
variety of compounds including pesticides and herbicides added to the water from
upstream discharges. Small amounts of these compounds may become significant
over time when they become concentrated in the blowdown.
Chlorine is typically added to inhibit biological growth in the cooling tower due
to organisms in the makeup water. To inhibit tube corrosion, combinations of
chromate and zinc or zinc and polyphosphates can be added to the cooling water.
However, since the discharge regulations are very stringent, only cooling towers in
very arid climates that must utilize zero discharge systems are able to use chromate
or zinc. One alternative to using additives is to use corrosion resistant materials for
the tubes.
27-6
-------
Cooling towers are often built of wood that is treated with acid copper
chromate, chromated copper, arsenate creosote, or pentachlorophenol to prevent
fungus attack. These wood preservatives may leach into the cooling water -
especially when they have been recently treated.
Asbestos has been used as a packing material inside cooling towers, and
asbestos fibers can be released to the water through disintegration due to severe
temperature swings, overly acidic cooling water and by biological causes.
Thermal Pollution
Thermal pollution is the heating up of natural water sources such as rivers and
lakes due to discharge of hot cooling water. The elevated temperatures can change
the natural ecological balance of the water source. For example, certain species of
fish may perish if the temperatures are too high, and vegetation can grow rapidly,
choking small offshoot streams. Thermal pollution has not been regulated to date.
Fuel Oil Supply Tanks
For oil fired boilers, the oil storage tanks general operating procedures and leak
detection are required to prevent contamination of water. Procedures to prevent
spilling and overfilling must be followed. Depending on the local requirements, a
secondary barrier is often required to contain any release from the tank. Accurate oil
inventory records must be kept to determine the fuel oil consumption by the boiler
and to alert the operator to any loss of oil through a leak in the tank or piping. In
addition, manual or automatic tank gauging, vapor monitoring in the surrounding soil,
and ground-water monitoring may be incorporated into the release monitoring
system. In addition, the facility must have a plan in place to deal with releases. This
plan should include corrective actions to be taken and specific reporting and
investigation procedures.
27-7
-------
REFERENCES
1. "Steam, Its Generation and Use", 4Qth Edition, Edited by S.C. Stultz and J.B.
Kitto. The Babcock and Wilcox Company, Barberton, Ohio, 1992.
2. T.C. Elliot, "Standard Handbook of Power Plant Engineering", McGraw Hill
Publishing Company, 1989.
27-8
-------
CHAPTER 28. WASTEWATER TREATMENT
28.1 Removal of Suspended Solids
28.2 Neutralization
28.3 Dechlorination
Slide 28-1
-------
28. WASTEWATER TREATMENT
In Chapter 27, the sources of waste water from utility boilers were identified.
The current federal regulations governing aqueous discharges were also discussed,
and it was noted that the pollutants of primary concern are total suspended solids,
toxic metals, and chlorine. In addition, the pH of the discharge is controlled. The
methods commonly employed to ensure that discharges are within the bounds of the
applicable regulations are discussed in the following sections.
28.1 Removal of Suspended Solids
Suspended solids are typically removed through two process: clarification and
. filtration. Clarification is the removal of sediments through sedimentation. Large
suspended particles settle out of the water stream leaving the remaining water clear.
Filtration is commonly used after clarification to remove fine suspended solids. The
combination of clarification and filtration can result in part per billion levels of
suspended solids. Each of theses solid removal systems are described in more detail in
the following paragraphs.
Clarification
Settling basins or ponds are used to remove suspended solids in the
clarification process. Sedimentation is generally classified into either plain or
chemical sedimentation. When gravity is relied upon to separate the heavy particles
from the water, the process is termed plain sedimentation. When chemicals
(coagulants) are added to force the particles to join and form heavier/bigger particles,
the process is called chemical sedimentation. The settling basins may be either of the
horizontal or vertical flow design. Horizontal flow basins are more commonly used in
the United States.
Slide 28-2 shows a circular settling basin. The water containing suspended
solids enters at the bottom and travels up the central passageway. After a series of
180° turns, the fluid enters the main compartment and remains a sufficient amount
of time to ensure that the particles drop to the bottom. The sludge that forms on the
bottom is scraped and removed through an exit passage. The particle free water exits
at the top of the basin.
28-1
-------
Circular Settling Basin*
Peripheral
overflow weir Skimming scraper
'V -JL
Skimming trough
\
Sludge
scraper
Effluent
Skimmings
removal
Influent
Sludge removal
Slide 28-2
Rectangular basins, shown in Slide 28-3, are also widely used. The fluid to be
treated enters horizontally from the side at the top of the basin. A chain is typically
used to move the sludge deposited on the bottom to the exit passage. The clean water
exits at the top of the basin on the side opposite to the inlet duct.
Horizontal Settling Basin.1
.Baffle
Influent
Rotary skimmer
trough. Overflow weir
•V*-,
Effluent
Chain and flight skimmer
and sludge collector
Sludge removal
Slide 28-3
28-2
-------
The design of settling basins must provide for effective removal of suspended
solids from the wastewater, and effective collection and removal of the collected solids
(sludge) from the basin. To yield high particle removal efficiencies, the design must
minimize "short circuiting". The term short circuiting refers to fast pathways from
the inlet to the outlet, not allowing sufficient time for the solids to settle out. To
minimize short circuiting, four main design principles are followed:
BASIN DESIGN PRINCIPLES
1. Inlet Design
Minimize inlet velocities to avoid turbulence and short circuiting.
2. Settling Zone
Provide for calm conditions.
3. Sludge Zone
Allow sufficient depth to allow sludge thickening.
4. Exit Design
Minimize exit velocities to prevent short circuiting.
Slide 28-4
Chemical coagulants are used to enhance the settling characteristics of
suspended solids, since bigger particles will settle out more rapidly than smaller
particles. Some commonly used coagulants include: Alum, ferric chloride, sulfate,
ferrous chloride, ferrous sulfate, lime and sodium aluminate.
Filtration
The oldest technique for treating wastewater is filtration with screens.
Typically, a combination of coarse and fine screens are used to filter wastewater. The
coarse screens are used to filter out larger particles while the fine screens are later
used to remove the finer particles.
The most common type of coarse screen is the bar screen. Bar screens simply
consist of a series of equally spaced steel bars placed across the channel. The screen
is either vertical or sloped. The debris is captured by the screen and removed with
rakes. The spacing of the bars can range from 1 to 6 inches and is determined by
expected materials in stream.
28-3
-------
Traveling screens are most commonly used for coarse screening. In particular,
traveling screens may be used for influent screening or effluent polishing. In this
process, an endless belt of stainless steel (or other noncorrosive material) is extended
perpendicular to the wastewater flow. The screens are cleaned by mechanical trays
which collect and remove the collected solids.
Vibrating screens can also be used to filter wastewater consisting of coarse or
fine particles. Common uses for these filters are for pretreatment and by-product
recovery in the food industry (and other industries). These circular, rectangular, and
square shaped screens can be used in place of static and rotary wedge wire screens
when there is little or no grease present in the wastewater stream.
Wedge wire screens can be used to filtrate wastewater for pretreatment or
removal of coarse or fine particles. Removal of finer particles requires screens with
smaller openings. Slides 28-5 and 28-6 display the static and rotary screens designs
that are available for this process.
Static screen schematic1
Triangled
screen ^^
Influent
Effluent
Slide 28-5
28-4
-------
Fine solids can be removed using static or rotary schematics with fine screens.
The screen openings can be as small as 0.01 to 0.06 mm, consisting of materials such
as stainless steel or fabric. Rotary microscreens are also available for removing
residual suspended solids such as from a biological treatment process.
Rotary screen schematic1
Spray nozzles
Water level
Influent.
\ Effluent ~/
Slide 28-6
28-5
-------
28.2
Neutralization
A very common requirement for chemical treatment is neutralizing excess
acidity or alkalinity in a wastewater stream. The pH level indicates the acidity or the
alkalinity. Streams consisting of a pH below 7 are considered acidic, streams above 7
are alkaline. Corrosive problems to equipment are expected to occur if the pH value is
outside the range of 6 to 10. Wastewater discharges to the environment must usually
range between 6 and 9.
In order to neutralize a given wastewater stream, the nature of the ions
causing the acidity or alkalinity must be determined. Titration curves prepared in a
laboratory can be used to determine the quality of the neutralizing material needed to
adjust the pH of the non-neutralized wastewater. Slide 28-7 shows the titration
curve for acidic wastewater. The shape of this curve will vary with wastewater
composition. Some wastewaters will require more of the neutralizing chemical to
reach a desired pH (this would be a highly buffered wastewater). Others will change
dramatically with little chemical addition. When close control of pH is required (±1
pH), and the wastewater is extremely sensitive to neutralizing agent addition, longer
residence times and multistage neutralization systems may be required.
Titration curve for acidic wastewater1
12 -
20 30
mlo(0 INNaOH
Slide 28-7
28-6
-------
A typical system utilizes one to three stages for the neutralization process.
The mixing characteristics of the reaction stages vary; some tanks are well-mixed
and some are not. This process depends on the reaction characteristics of the
reagents and the desired fluctuations in pH. Laboratory experiments can aid in the
design of a given neutralization system.
When good mixing is required, the influent and effluent devices are commonly
placed on opposite sides of the reaction tank. Sidewall baffles are often included in
circular tanks to improve mixing. In all cases, the pH probe should be located at the
outflow of the reactor for the most representative sample.
Selection of the neutralizing agent depends on the required cost, quantity,
by-product formation and availability. Common neutralizing agents for acid wastes
are caustic soda, lime, calcium or sodium carbonate, and limestone. For alkaline
wastes, nitric, sulfuric, and hydrochloric acids are commonly used. Slide 28-8
summarizes some characteristics of some common neutralization agents.
Chemical Reagent
NEUTRALIZATION AGENTS
Neutralization
Requirements,
Formula mg/L* Neutralization Factort
Basicity
Calcium carbonate
Calcium oxide
Calcium hydroxide
Magnesium oxide
Magnesium hydroxide
Dolomitic quicklime
Dolomitic hydrated
lime
Sodium hydroxide
Sodium carbonate
CaCO3
CaO
Ca(OH)2
MgO
Mg(OH)2
[(CaO)o.6(MgO)0.4]
{[Ca(OH)2]06
[Mg(OH)2]0.4}
NaOH
Na2CO3
1.0
0.560
0.740
0.403
0.583
0.497
0.677
0.799
1.059
1.0/0.56 = 1.786
0.56/0.56 = 1.000
0.74/0.56 = 1.321
0.403/0.56 = 0.720
0.583/0.56= 1.041
0.497/0.56 = 0.888
0.677/0.56 = 1.209
0.799/0.56 = 1.427
1.059/0.56= 1.891
Acidity
Sulfuric acid
Hydrochloric acid
Nitric acid
H2S04
HC1
HNO3
* The quantity of reagent required to neutralize 1
calcium carbonate.
f Assumes 100 percent purity of all compounds.
0.98
0.72
0.63
mg/L of acidity
0.98/0.56 = 1.750
0.72/0.56 = 1.285
0.63/0.56 =1.125
or alkalinity, expressed as
Slide 28-8
28-7
-------
A typical two-stage, continuous neutralization system is shown in Slide 28-9.
The performance of such a system depends highly upon the condition of the primary
elements (pH probe, etc.) and other instruments. Proper maintenance and system
design are critical in insuring that the set-point pH is achieved. The key parameters
in the system design include selecting the appropriate: neutralizing agent, reactor
retention time, number of reaction stages, control concept, and hydraulic design of the
system to assure proper mixing.
Two-stage, continuous neutralization system*
Neutralizing.
chemical
pH controller
Influent-
• Neutralized
effluent
Slide 28-9
28.3
Dechlorination of Wastewater
De-chlorination systems have become more popular since the discovery that
compounds formed through chlorinated water supplies and wastewater effluents may
be toxic to humans and aquatic life. Dechlorination is performed using one of several
reducing agents, such as sodium sulfite, sulfur dioxide, activated carbon, sunlight,
prolonged storage, or aeration for certain volatile forms of chlorine.
Sulfur dioxide is useful for dechlorinating large volumes. This method currently
has the most development and is the least expensive. Sulfur dioxide is fed to the
wastewater as a gas, where it immediately forms sulfurous acid. This acid reacts with
free and combined chlorine almost instantaneously. The product is small amounts of
sulfuric and hydrochloric acid which are neutralized by the v/astewater's buffering
capacity.
28-8
-------
Sulfttes are used for dechlorination primarily at treatment facilities with flows
less than one million gallons per day. Sulfite salts can be added as a solid or liquid. The
most commonly used sulfites are sodium sulfite (Na2S03), sodium bisulfite
(NaHSOs), and sodium metabisulfite (^28205).
Activated carbon physically removes free chlorine, chlorinated amines, and
chlorinated organics through sorption. This process is easy to operate and is very
effective and reliable. It also has the added benefit of removing residual refractory
organics and possibly toxic chlorinated organics. Activated carbon dechlorination beds
are typically designed to handle 9.5 ft3 / (ft2-min) with a contact time of 15 to 20
minutes.
REFERENCE
1. R. A. Corbitt, "Standard Handbook of Environmental Engineering", McGraw
Hill Publishing Company, 1990.
28-9
-------
CHAPTER 29. SOLID WASTES
29.1 Introducti on
29.2 Bottom Ash and Fly Ash
29.3 Ash Removal and Handling Techniques
A. Bottom Ash Removal and Handling
B. Boiler Back Pass Ash Handling
C. Fly Ash Removal and Handling
29.4 Ash Characterization and Testing
A. Classification of Coal Ash
B. Elemental Analysis
C. Fusion Temperatures
D. Fuel Oil Ash Characteristics
29.5 Flue Gas Desulfurization Wastes
29.6 Handling of FGD Wastes
A. Wet Scrubbing Waste Handling
B. Dry Scrubbing Waste Handling
C. Sorbent Injection Waste Handling
29.7 Groundwater Contamination from Ponds and Landfills
Slide 29-1
-------
29. SOLID WASTES
29.1
Introduction
SOURCE OF SOLID WASTES
Fuel Ash
Flue Gas Desulfurization Waste
Slide 29-2
The principal sources of solid waste from boilers are from the combustion of
coal and fuel oil and the use of lime/limestone for sulfur dioxide removal. During
combustion of coal and fuel oil, the inert portion (ash content) of the fuels become un-
reacted and emitted from the boiler systems in solid forms commonly known as ash.
Depending on its physical and chemical properties, ash is collected at several places
along the boiler system. Significant amounts of ash are normally collected at the
furnace bottom hopper and at the participate control device.
Lime and limestone are commonly used as flue gas desulfurization (FGD)
reagents to reduce sulfur dioxide emissions in the flue gas. FGD processes typically
yield a calcium-based solid volume, which is either discarded or utilized.
This chapter presents a discussion about the solids wastes that are generated
from the boiler system. It will provide a brief summary of the solid wastes'
characteristics and their handling techniques. It also presents a short discussion on
the impacts of solid waste on water contamination. Approaches to solid waste
management including disposal, treatment and utilization are discussed in Chapter
30.
29.2
Bottom Ash and Flv Ash
BOTTOM ASH AND FLY ASH
Source of Ash
Definition of Bottom Ash
Definition of Fly Ash
Slide
The use of fossil fuels in the generation of steam/power depends on the
effectiveness of the steam generating equipment's ability to handle the inert residuals
29-1
-------
of combustion commonly known as ash. Fossil fuels such as coal and oil can contain
up to 40 percent ash by mass but this can very considerably from region to region.
The characteristics of the ash are major concerns not only to the designer but also to
operators interested in evaluating different fuel sources. Natural gas has the
advantage that it contains little if any amounts of ash.
In the combustion process, the ash is released from the fuel at temperatures
exceeding the melting temperature of most compounds in the ash. These high
temperatures produce a soft slag type material which can adhere to heat transfer
surfaces such as furnace walls or pendant superheaters (see Chapter 2). This slag
either is removed from the surfaces with the use of sootblowers or eventually falls off
by its own weight as a result of load changes. The ash and slag that falls from the
walls pass through the bottom opening of the furnace into an ash hopper or into a
submerged scraper conveyor. Ash that is collected in the hopper directly under the
furnace is referred to as bottom ash.
ASH DISTRIBUTION FROM A COAL-FIRED BOILER
Pulverizers
Pyrite
Bottom Ash Backpass Air Heater Flyash
20 to 40% Ash Flyash 50 to 70%
-5% - 5%
Slide 29-4
The ash that is entrained with the combustion products passes through the unit's
convective pass and is referred to as fly ash. A small portion of the fly ash is typically
collected in an economizer or air heater hopper. Further downstream a majority of the
fly ash is collected in dust collection equipment such as baghouses or electrostatic
precipitators (ESP). Some fly ash may adhere to the heat absorbing surfaces in the
convective pass and need to be removed with sootblowers. This ash is reentrained
with the combustion products and collected in the economizer hopper or dust
collection device. The distribution of the ash in a pulverized coal fired boiler is shown
in Slide
29-2
-------
29.3
Ash Removal and Handling Techniques
ASH REMOVAL AND HANDLING
Bottom Ash Removal
Wet Bottom Systems
Dry Bottom Systems
Fly Ash Removal
Vacuum Pneumatic Systems
Pressure Pneumatic Systems
Slide 29-5
In the design of coal and oil fired boilers, special consideration is given to the
ash content of the fuel to determine the most efficient collection and handling
procedures. Three methods of removing ash from its collection point to their
respective storage or disposal areas are currently utilized at fossil fuel—fired plants:
hydraulic, pneumatic, and mechanical. Hydraulic systems utilize streams of water
as the carrier fluid to convey the material in a closed pipeline or open sluiceway and is
known as sluicing. In pneumatic systems, air is used as the carrier fluid in a closed
pipeline. The third method, mechanical, can very from its simplest form consisting of
a shovel to the more sophisticated type being the conveyor.
Bottom Ash Removal and Handling
TYPICAL WET BOTTOM ASH SYSTEM
\
Drip Shield
Boiler Seal Plate
Water-Seal Trough
Overflow Boxes
Access Door
Sluice Gate
Enclosure
Vacuum/Pressure
Relief Assembly
Slope Nozzles
Rear Slope Nozzle
Slide 29-6
29-3
-------
The removal of bottom ash can be through a wet bottom system or through a
dry bottom system. In wet bottom systems, the ash drops from the furnace into a
water impounded hopper where the ash is received, quenched, and stored until there is
sufficient ash to convey to the disposal site or settling tank. Slide 29—6 shows a
schematic of a typical wet bottom system. The hopper floors are sloped so that
gravity will help remove the ash from the hopper. Gravity alone will not remove all of
the ash from the sides of the hopper. Some of the ash will tend to stick to the sides,
therefore jet nozzles are used on the side of the hoppers to assist in dislodging the
material. From the hopper discharge, the ash passes through a clinker grinder to
reduce the size of the ash particles to facilitate transport to the disposal or storage
site. Jet pumps or centrifugal pumps are then used to convey the ash water mixture
(sluice) to the disposal site.
SUBMERGED SCRAPER CONVEYOR FOR BOTTOM ASH1
Dewatering Slope
Transfer
Chute
Clinker
Grinder
Scraper Flights
Dry Return Trough
Slide 29-7
Submerged conveyor systems can also be used in units designed for water
impoundment systems. The submerged conveyor, shown schematically in Slide 29—7,
consists of a water, at 140°F, filled upper trough and a dry lower trough. Seal plates
are attached to the bottom of the furnace and immersed in the water of the upper
trough to maintain the gas seal. Ash is conveyed by a series of flights which pull the
ash up an incline and out of the water. Ash is continually evacuated and is
transported to trucks or a holding area on belt conveyors for disposal.
Dry bottom systems are used when there is no need for water impoundment and
automation is not necessary or required. Like the hoppers used for wet bottom
systems, dry bottom hoppers use flushing nozzles but unlike wet bottom hoppers use
a greater slope on the walls of the hopper to insure that the dry ash flows through the
discharge opening. Ash is removed from the hopper through a series of water cooled
discharge gates. Clinker grinders are sometimes used to reduce the size of larger
clinkers and facilitate the flow of the ash through a pneumatic or hydraulic conveying
system. Sizing grids for manual handling of the bottom ash may be placed at the
discharge gate outlet.
29-4
-------
Boiler Back Pass Ash
Ash that is collected below the economizer section of the boiler where the
combustion gases usually make a 90-degree turn is referred to as economizer hopper
ash. Economizer hopper ash is usually at a temperature of about 700°F, are neither
fine like fly ash or coarse like bottom ash and is sometimes transported along with
the bottom ash or the fly ash. Some units will transport the economizer hopper ash
separate from the bottom ash or the fly ash using a pneumatic or hydraulic
conveying system. Removal of the economizer ash should be continual since it may
contain unburnt carbon which may combust. Ashes that are low in calcium content
may be stored in water filled tanks beneath the economizer hopper outlet. Certain
ashes that are high in calcium content show cementitious properties when dropped
into or mixed with water. High calcium ashes have used dry transfer tanks below the
economizer hopper outlet for continuous removal.
Fly Ash Removal and Handling
Ash that is collected in air heater hoppers, precipitator hoppers, or baghouse
hoppers is referred to as flyash and is removed intermittently by either vacuum or
pressure type pneumatic systems. Because of the dusty nature of fly ash, these
systems need to be totally enclosed and air tight. In general, pneumatic conveying
systems utilize air streams as the carrier fluid through a piping system to transport
the ash from the hoppers to a storage silo or holding tank.
DRY PNEUMATIC VACUUM FLYASH SYSTEM
Precipitator
or Fabric Filter
Cyclone
Separators
Bag Filter
Flyash IntakesK^V V V V
nil
Air Inlet-
Mechanical
Exhauster
->• Discharge
tary Ash Conditioner
Slide 29-8
In a vacuum type conveying system, a negative pressure is produced in the
pipeline network by locating a mechanical, water or steam exhauster at the discharge
end of the fly ash silo or other storage area. A fly ash intake valve is used at the
outlet of each hopper to regulate the flow of ash. Manual isolation valves are provided
for maintenance purposes at the outlet of each hopper. A logic control system
29-5
-------
insures the proper sequence of events and positioning of the valves. Since the system
operates on a vacuum, only one hopper valve is actuated at a time to avoid plugging
the discharge line. Each fly ash intake valve is actuated automatically by the
system logic. To protect the mechanical blower from the abrasive nature of the fly
ash, most of the ash must be collected. A cyclone separator amd a bag filter are used
in series to separate the air-ash mixture and reduce the possibility of damage to the
blower. The ash is then emptied from the silos into enclosed trucks or rail cars. A dry
vacuum fly ash conveying system is shown schematically in Slide 29-8.
A water exhauster is another method of transporting fly ash through the
conveying line. High-pressure water supplied to the water-exhauster inlet nozzles
creates the transport vacuum; fly ash, air and water are mixed in the exhaust
venturi. Water exhausters normally have hardened ductile iron bodies,
wear-resistant liners and stainless-steel nozzles.
Following the water exhausters, an air separator is provided to separate and
vent the air from the fly ash-water-air mixture. Separators are made of cast iron or
carbon steel with an abrasion-resistant basalt or ceramic liner. The separator
discharge is elevated sufficiently to allow the ash-water slurry to flow by gravity to a
pond or disposal area. Fly ash slurry is never discharged to a dewatering bin because
it is very difficult to settle out the fine fly ash particles in the dewatering bin; most
fine particles would pass over the overflow weir. A dry pneumatic transport fly ash
system using water exhausters as vacuum producers is shown schematically in Slide
29-9.
DRY PNEUMATIC FLYASH TRANSPORT SYSTEM
USING WATER EXHAUSTERS AS VACUUM PRODUCERS
Air Heater Hoppers
Maintenance
Gates
Air Intake
Preciprtator
Hoppers -
Fluidizing
C~Y~) I Air Blowers
Maintenance
Gates
Flyash Intakes
Air Intakes
Air Separator
Water Exhausters
High-Pressure Water
To Ash Storage Pond
Slide 29-9
29-6
-------
Pressure systems, shown in Slide 29-10, utilize compressors or blowers
upstream of the hoppers to create the high pressure necessary to transport the ash.
Air-lock feeders regulate the transfer of the fly ash from the low pressure hoppers to
the high pressure transport line. Fluidizing air is provided at the inlet and outlet of
each feeder to ensure ash flow through the feeder. Uniform loading of ash is
accomplished by automatically controlling the air-lock feeders. The air-lock feeders
are volumetric feeders which are controlled to empty selected groups of hoppers thus
providing a uniform flow to the conveyor system.
DRY PNEUMATIC-PRESSURE FLYASH SYSTEM
1
(Alternate Bag FilterX •
Vent to Precipitator Inlet
Air Inlet
Mechanical
Blower or
Compressor
Precipitator
or Fabric Filter
Air-Lock
Feeders
Rotary Ash Conditioner
Slide 29-10
When the number of fly ash collection hoppers is relatively high, a combination
of the two systems described above is utilized. In a vacuum /pressure system the fly
ash moves by vacuum from the hoppers to a nearby transfer silo as shown in Slide
29-11. From the transfer silo the fly ash transported to the main ash silos for
disposal.
29-7
-------
VACUUM-TO-PRESSURE DRY PNEUMATIC FLYASH SYSTEM l
Air c
Intake \
LJ
Precipitator |~
>r Fabric Filter
(j¥YY ft.
Flyash Intakes — '
Air In n
Mechnical C\l} \ 1
Blower MM TT
x^y
Air- Lock Feeders-^
^^-— Bag Filter
^s- Primary &
^ Secondary
Cyclones
Surge ^4
Transfer ( ft
i Tank /\ A
Air
i
i
xJ
Out
i
Mechanical
Exhauster
? _
X— v,
Vent
|
1 r
Flyash
Silo
«
^ Spray Alternate:
To Fill Area
Slide 29-11
29.4
Ash Characterization and Testing
ASH CHARACTERIZATION AND TESTING
Classification of Coal Ash
Elemental Analysis
Fusion Temperatures
Fuel Oil Ash
Slide 29-12
Classification of Coal Ash
The nature, composition, and properties of ash should be studied in order to
determine their effect on boiler performance. The behavior of ash once the fuel has
been fired in the boiler can be determined from an elemental analysis of the ash which
often helps designers to determine the slagging and fouling potential of a specific ash.
Classification of coal ash is often based on the elemental analysis, in
particular, the presence of iron, calcium, and magnesium compounds. Lignitic ash is
described when the total percentage of the calcium and magnesium compounds (CaO
+ MgO) is greater than the percentage of the iron compound Fe2Oa. On the other
hand, if the amount of the iron compound is greater than the calcium and magnesium
compounds then the coal ash is described as being Bituminous. In general, eastern
coals tend to be bituminous while western coals tend to have lignitic ash although
there are exceptions.
29-8
-------
Elemental analysis
EXAMPLE ELEMENTAL ANALYSIS OF COAL ASH
Analysis of ash, % by wt.
Si02 46.34
A1203 33.34
Ti02 1.24
Fe203 11.62
CaO ...
MgO.,
Na20.
K2O ...
S03
P205..
MnaO,
1.76
1.75
0.25
1.27
2.08
0.17
0.11
Other 0.07
Total 100.00
Slide 29-13
In general, an elemental analysis of ash will report the constituents listed in
Slide 29-13 . The ash is prepared by the ashing technique described by the American
Society of Testing and Materials (ASTM) D 3174. The elemental analysis report will
specify the weight percent for each constituent present as an oxide.
Fusion Temperatures
INFLUENCE OF TEMPERATURE ON SPECIFIC ASH SHAPES
1.
2. IT
3. ST
4. HT
5. FT
n
r\
2
IT
3
ST
4
HT
5
FT
Cone before heating
Initial deformation temperature
Softening temperature (H=W)
Hemisherical temperature (H=0.5W)
Fluid temperature
Slide 29-14
29-9
-------
The behavior of the ash at elevated temperatures can be determined by
measuring the ash fusibility temperature. Fusibility temperatures of ash can have
many uses for boiler operators. Fusion temperatures can provide an indication of the
temperature range over which a certain ash will be in the molten state. High fusion
temperatures will generally indicate a low slagging potential which is advantageous
for a dry bottom furnace. Low fusion temperatures would indicate a higher potential
for slagging since the ash will remain in a molten state over a wider temperature
range.
The procedure is referred to as ASTM D 1857, Fusibility of Coal and Coke Ash.
This test involves observing the shape of an ash sample that is pressed into a mold.
The ash sample is prepared by burning coal under oxidizing conditions at
temperatures of 1,470 to 1,650°F. The ash that is produced is then pressed into a
triangular mold. The cone is heated in a oxidizing or reducing furnace at a controlled
rate of 15°F per minute. As the cone deforms, the temperature at which the cone
deforms to a specific shape as shown in Slide 29-13, is recorded.
Other measures also give an indication of the behavior of the ash. For example
the iron content of bituminous ashes can have a significant influence on the slagging
and fouling potential of the ash. Other measures are also considered in the slagging
potential of the ash such as the Base to Acid ratio, Silica to Alumina ratio and the
iron to calcium ratio.
Fuel Oil Ash Characteristics
FUEL OIL ASH CHARACTERISTICS
Vanadium
Sulfur
Sodium
Slide 29-15
29-10
-------
Even though fuel oil contains very small amounts of ash compared to coal, the
characterization of the ash is very important to the designer as well as to the
operator. The most important compounds that may appear in fuel oil ash are those
of vanadium, sodium, and sulfur. These elements are significant because they tend to
form complex compounds that have low fusion temperatures. The low fusion
temperatures can lead to significant slagging and fouling.
29.5
Flue Gas Desulfurization Wastes
FLUE GAS DESULFURIZATION WASTES
Wet Scrubbing
Wet sludge
Gypsum
Dry Scrubbing
Dry sludge
Sorbent Injection
Dry waste
Slide 29-16
FGD solid waste characteristics vary depending on the particular technology
employed (see Chapter 26 for discussions of FGD technologies):
Wet Scrubbing: Using natural oxidation produces a wet sludge containing a
mixture of calcium sulfite (CaSOa) and calcium sulfate (CaSC^) reaction products,
trace amount of flyash and un-reacted limestone. In a forced oxidation, the main
difference in the waste is that the reaction product is almost totally in the form of
CaSC>4 or gypsum, which is more easily dewatered to a filter cake for landfill or other
use.
Dry Scrubbing: Waste is dry and contains CaSOs, CaS04, flyash, and un-
reacted sorbent.
Sorbent Injection: Waste is dry and contains calcium sulfate, a large
proportion of calcium oxide (CaO), and fly ash.
29-11
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29.6
Handling of FGD Wastes
Wet Scrubbing Waste Handling
Different types of handling equipment are employed depending on whether the
solid waste is disposable sludge or by-product gypsum.
Disposable Sludge: The wet sludge is typically treated first before being
disposed to a landfill. The underflow slurry from a thickener is pumped to a slurry
tank, then pumped to a rotary vacuum filter which produces a gypsum (disposable)
filter cake with higher solid content. The filter cake is transported by means of a
conveyor belt to a temporary storage area and then trucked directly to a landfill site.
The thickener overflow and vacuum filtrate are pumped to a storage tank and
returned to the process.
By-Product Gypsum: The forced-oxidation product containing high percentage
of CaSC>4 is typically dewatered before being removed from the plant for sale. The
bleed stream from a recirculation tank is pumped to a thickener. The thickener
overflow is recycled to a process water storage tank, where a polymer is usually
added to help control fine gypsum particle concentrations. The thickener underflow is
pumped to a gypsum slurry tank, then to belt filters where the required solid content
is obtained. The gypsum cake is washed with fresh water to remove any residual
chlorides. The dewatered gypsum is discharged from the belt filters onto belt
conveyors which transfer the gypsum to a storage area via a propelled tripper. A
portal reclaimer is used in conjunction with several belt conveyors to reclaim and
transfer gypsum from the storage area to a truck load-out bin prior to removal from
the plant.
Dry Scrubbing Waste Handling
Positive pressure pneumatic conveying systems are typically used to transfer
the solids from hoppers of the APCD to disposal silos. The solid material is wetted
with water for dust control and loaded into off-highway trucks by either a shuttle
loader (belt conveyor) or a front-end loader. The trucks transport the solids to a
landfill disposal area.
FGD WASTE HANDLING
Pneumatic Systems
Hydraulic Systems
Pipelines
Conveyors, Aerial Trams
Trucks, Off-Road Vehicles
Railroads
Slide 29-17
29-12
-------
Dry Sorbent Injection Waste Handling
Similar to the techniques employed for dry scrubbing, solid waste handling in
sorbent injection typically uses positive pressure pneumatic conveying system to
transport solids from the APCD hopper to disposal silos. The solids is wetted and
transported to a disposal landfill via trucks.
In some cases, however, disposal regulations require the waste solid to be
treated first before being disposed due to high amounts of CaO content. A hydraulic
conveying system is typically used for these situations. The solid waste is mixed with
water and sluiced in a pipeline system, along which several locations are provided for
carbon dioxide or sulfuric acid injection to adjust the pH level of the waste material.
29.7 Groundwater Contamination From Ponds or Landfills
GROUNDWATER CONTAMINATION
/"Rain//'
' / , //, ' /
Leachate
Ground '/'5)X. \ and
Runoff
Leaching
Groundwater
Slide 29-18
The disposal of solid wastes can be handled through an on-site settling pond, or
the material can be transported from the plant to a landfill. In either case, potential
leaching of pollutants contained in the waste is of concern. In a landfill, pollutants are
leached from the materials when rain water infiltrates the landfill and leaches the
pollutants from the waste into an aqueous solution which can than seep into the
groundwater. To avoid contamination of the groundwater, many landfills and ponds,
use liners to contain the leachate and surface runoff, use collection system to remove
leachate, and monitor the groundwater for pH level.
29-13
-------
REFERENCES
1. Singer, J. G., Combustion: Fossil Power Systems, 3rd edition, Combustion
Engineering, Inc., 1981.
2. Steam, Its Generation and Use, 40th Edition, Babcock and Wilcox Company,
1992.
3. Elliot, C.T., Standard Handbook of Powerplant Engineering, McGraw Hill
Publishing Company, New York, 1989.
4. Hanzel, D.S., Laseke, B.A., Smith, E.G., Swenson, D.O., Handbook for Flue Gas
Desulfurization Scrubbing with Limestone, Noyes Data Corporation, New
Jersey, 1992.
5. Economic Evaluation of Flue Gas Desulfurization Systems, Electric Power
Research Institute, GS-7193 Volume 1, Research Project 1610-6, Final
Report, February 1991.
29-14
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CHAPTER 30. SOLID WASTE MANAGEMENT
30.1 Introduction
30.2 Disposal Methods
30.3 Wet Disposal — Ponds
A. Pond Configurations
30.4 Dry Disposal — Landfills
A. Landfill Configurations
30.5 Treatment Methods
30.6 De watering
A. Settling Ponds
B. De watering Bins
C. Thickeners
D. Cyclones
E. Centrifuges
F. Vacuum Filters
30.7 Stabilization
30.8 Fixation
30.9 Utilization
A. Ash Utilization
B. FGD By-Product Utilization
C. Site Utilization
Slide 30-1
-------
30. SOLID WASTE MANAGEMENT
30.1
Introduction
SOLID WASTE MANAGEMENT
Disposal
Treatment
Utilization
Slide 30-2
This chapter addresses the management of large—volume solid wastes such as
bottom ash, flyash, and scrubber by-products at coal-fired plants. The approaches
to solid-waste management include disposal, treatment or utilization of the wastes.
In some cases, the wastes can be disposed to a landfill or a reservoir. In other cases,
the wastes require treatment to satisfy regulations before disposal. In addition,
utilization is an attractive option for managing the solid wastes.
30.2
Disposal Methods
DISPOSAL METHODS
Wet Disposal
Ponds or Reservoirs
Dry Disposal
Landfills
Slide 30-3
In simple terms, all disposal methods are either wet or dry depending on the
physical condition of the material delivered to the disposal area. Wet disposal
involves the handling and placement of the material in slurry or liquid form while dry
disposal involves receiving and placement of the material as a bulk solid. Wet
disposal systems are generally referred to as ponds or reservoirs; dry disposal systems
as landfills.
Complete design of any wet disposal systems must include facilities for
removal, treatment, and either recycle or release of inevitable supernatant (small
solid particle floating on surface of a liquid). Both wet and dry systems must provide
for the management of precipitation falling on the disposal area.
30-1
-------
30.3 Wet Disposal —Ponds
Pond Configurations
POND CONFIGURATIONS
Diked Disposal Ponds
Incised Disposal Ponds
Sidehill Disposal Ponds
Cross-Valley Disposal Ponds
Slide 30-4
Wet disposal requires the safe containment of the waste slurry until it has
settled, stabilized and fixated. Impermeable barriers must be provided to contain the
full volume of waste slurry anticipated during the life of the disposal site.
The configuration and general arrangement are controlled by the terrain,
geology, hydrology, and other features of the site. The simplest approach is to
construct a dike around the perimeter of the site. Where the geology and hydrology of
the site permit, it is often less costly to excavate the dike material within the future
disposal area, creating a site that is partially diked and partially excavated or incised
in the site. Another option is to excavate for the entire disposal volume and to use the
removed soil for other purposes. Sloping sites offer the possibility of taking
advantage of the terrain to provide portions of the containment, as with a sidehill
disposal area diked on three sides or a valley impoundment (diked only on one side.
Graphical illustrations of the pond configurations are shown Slide 30-5.
GRAPHICAL ILLUSTRATION OF POND CONFIGURATIONS
Diked pond constructed above grade.
Diked pond partially excavated below grade.
An incised disposal pond.
A sidehill disposal pond.
A cross-valley pond configuration.
Slide 30-5
30-2
-------
30.4 Dry Disposal — Landfills
Landfill Configurations
LANDFILL CONFIGURATIONS
Heaped Landfill Configuration
Sidehill Landfill Configuration
Valley-fill Disposal Configuration
Slide 30-6
The simplest method of landfill construction is a heaped fill in which the waste
material is placed and compacted in lifts to form a mound or artificial hill. This
approach is generally used in flat terrains. For greater stability and reduced visual
impact, sloping terrain is usually utilized. A sloping site allows the construction of a
sidehill landfill, and a valley site leads naturally to a valley-fill configuration.
Graphical illustrations of the landfill configurations are shown in Slide 30-7.
GRAPHICAL ILLUSTRATION OF LANDFILL CONFIGURATIONSJ
A heaped landfill configuration.
A sidehill landfill.
A valley-fill disposal configuration.
Slide 30-7
In practice, a landfill site may employ more than one of these configurations as
it is developed over the life of the power plant. In the new waste disposal facilities,
there is a trend toward dry disposal. This technique leads to smaller volumes for the
same useful life, more options for site or material reclamation, and higher reliability.
30-3
-------
30.5
Treatment Methods
WASTE TREATMENT METHODS
Dewatering
Stabilizing
Fixating
Slide 30-8
The treatment method can be considered in three broad categories:
Dewatering: Physically separating water and solids to recover the water and/or
increase the solids content of the product.
Stabilizing: Adding dry solids to the slurry to increase the solids content of the
product.
Fixating: Adding an agent to cause a chemical change in the product to bind
the water into the solids to produce a physically dry solid.
30-4
-------
30.6
Dewatering
DEWATERING METHODS
Settling Ponds
Dewatering Bins
Thickeners
Cyclones
Centrifuges
Vacuum Filters
Slide 30-9
Dewatering encompasses a wide range of mechanical devices to separate
water and participate solids. Among the separation techniques are settling ponds,
dewatering bins, thickeners, cyclones, centrifuges, and vacuum filters. Each of these
techniques will be briefly described below.
Settling Ponds
SETTLING PONDS
Range of solid concentrations
10-50% FGD slurry
20-70% ash
Advantages
Simple operation
Not sensitive to inlet solid content
Low maintenance costs
High reliability
Disadvantages
Substantial land area
Unpopular with regulatory agencies
Solid removal difficult
Slide 30-10
Often used alone with ash or limestone scrubber slurries, settling ponds are the
simplest dewatering method. The pond is sized to provide a large volume so that flow
velocities are very slow and gravity acts to settle the solids. The liquid fraction is
drawn off at a clear well and the solids are collected during periodic cleaning of the
pond bottom.
30-5
-------
Dewatering Bins
DEWATERING BINS
Range of solid concentrations
15-25% FGD slurry
25-75% ash
Advantages
Reduced land area
Relatively simple maintenance
Clear water produced
Attractive first-stage treatment
Disadvantages
Low slurry product solids
Sensitive to inflow characteristics
New technology
Complicated operation controls
Slide 30-11
Dewatering bins includes a wide variety of devices ranging from the simple to
the complex. The simplest are the hoppers with a simple sloping, perforated plate to
separate granular materials such as bottom ash from the slurry water fraction. In
more complex units, multiple plates collect the heavy solids from scrubber sludges on
a moving belt at the bottom of the bin. The plates provide a large surface area in a
small volume to settle the solids and to separate particles from the moving fluid.
Thickeners
THICKENERS
Range of solid concentrations
20-45% FGD slurry
Advantages
Reduced land area
High throughput rates
Established technology
Disadvantages
Higher capital cost
Higher maintenance cost
More complicated operation
Slide 30-12
Thickeners operate much as ponds or bins, relying on gravity to separate
high-specific-gravity solids from water. Typical thickeners are large cylindrical
tanks with a center column, which supports the drive mechanism for two or more
long radial raking arms extending from the bottom of the shaft. These carry a series
of plows to stir the material at the bottom of the tank which slopes toward the center.
30-6
-------
The plows push the settled solids toward the underflow discharge point.
The center column also contains a feedwell that delivers the inflow slurry to the
midpoint of tank depth. The initial separation is made by gravity, and the clear flow
exists over a weir around the top perimeter of the tank. The thickened solids are
compacted by the rakes and discharged by a pipe at the bottom center of the tank.
Thickeners are sized according inflow volume, solids, loading, settling characteristics,
and target outflow solid concentrations.
A cross-section view of a conventional thickener is shown in Slide 30-13.
A CONVENTIONAL GRAVITY THICKENER
cant
WIT MB urn
MVICt
Win WTOR MB
-KM H5SOW.Y
HMJCWT
Lin
IMHCATW
01SOMK TOO
Slide 30-13
Cyclones
CYCLONES
Range of solid concentrations
35-65% FGD slurry
Advantages
Low space requirements
Relatively low cost
Recover high portion of large particles
Low solid content in liquid fraction
Disadvantages
Do not recover fine particles
Inefficient with feeds over 15% solids
Susceptible to abrasion and corrosion
High liquid content in solid fraction
Slide 30-14
30-7
-------
Cyclones promote free vortex separation that removes solids from slurries by the
combined effects of centrifugal force and liquid shear. The pressure energy of the
liquid slurry pumped into the cyclone changes to velocity energy at the inlets and into
rotational energy as the liquid moves down and through the cyclone. This rotation
causes a natural vortex that moves the heavier solids particles to the outside of the
vortex and the lighter liquid particles to the center. The heavier solids are discharged
from an orifice in the cyclone's tip. Slide 30-15 shows a schematic of a cyclone.
A CYCLONE 3
FEED
FEED INLET
^-OVERFLOW
VORTEX FINDER
CYCLONE DIAMETER
CONE SECTION
CROSS SECTION
FEED CHWBER
APEX OPENING
UNDERFLOW
Slide 30-15
30-8
-------
Centrifuges
CENTRIFUGES
Range of solid concentrations
40-65% FGD slurry
Advantages
Low space requirements
Accept variation in inflow
High product solid content
Established technology
Disadvantages
Do not produce clear liquid
High cost
High maintenance
Subject to abrasion and corrosion
Slide 30-16
Centrifuges are normally a secondary dewatering step that follows an
upstream thickener. They are basically compact, high-intensity settling basis;
centrifugal force is the principal cause of solid-liquid separation. Centrifuges can
produce 1,500 to 4,000 times the acceleration force of gravity—the limiting force in
settling basis. Centrifuge reliability and efficiency are improving. The solid fraction is
consistent and can reach 65 percent solid concentration. Centrifuges are not
effective in producing a clear liquid fraction and are subject to abrasion and corrosion.
The major problem in centrifuge operation is the disposal of the liquid fraction, which
is high in solid content. Slide 30-17 shows a schematic of a centrifuge.
A SOLID-BOWL CENTRIFUGE 3
Dffftut»««. •««•
OIM MI
MiMowvf MUTT
/
fJ±MW-»_
.|_Q » nIB nn
U MM MOt (MOWN
Slide 30-17
30-9
-------
Vacuum Filters
VACUUM FILTERS
Range of solid concentrations
35-65% FGD slurry
60-75% ash
Advantages
Low space requirements
High product solid content
Consistent product quality
Established technology
Dis advantages
High cost
High maintenance
Complicated operation
Do not produce clear liquid
Slide 30-18
Two types of vacuum filters, drum and belt, are commonly selected for
second-stage dewatering of slurries in fossil fuel-fired plants. The rotary-drum filter
is the most popular type since it is usually the least expensive. The drum carrying
the filter media is divided into sections. Feed is held in the tank at the bottom of the
unit. As the drum rotates, each section passes in turn through the feed holding tanks.
From within the drum the vacuum draws slurry to the drum's face. As the drum
rotates, the vacuum draws the filtrate through the filter media until a high-solid filter
cake remains on the outside of the filter. The drum continues to turn past a scraper,
which removes the filter cake so that the process can repeat. Slide 30-19 shows a
cutaway view of a rotary drum vacuum filter.
A ROTARY DRUM VACUUM FILTER
Goth eauiktnq
rtnpi
Filtritt piping
Automatic v*lvt
Air «nd ftltntff
Air MO«v-bKh line
Slurry f
Slide 30-19
30-10
-------
Belt filters are improved versions of the rotary-drum filter. The filter medium
lifts from the drum after the dewatering portion of the cycle and passes over a
small-diameter roller to remove the cake. This small roller completely discharges the
cake without a scraper, thus increasing filter cloth life. Since the belt is lifted from
the drum, the drying time is only a fraction of the total cycle.
30.7
Stabilization
STABILIZATION
• Addition of dry solids
• Increase shear strength
• Lower permeability
• Lower volume
• Can be rewetted
Slide 30-20
Stabilization is a simple mixing of a relatively dry solid such as soil or flyash
with the slurry material to be treated. Physical stabilization is most applicable
where dry disposal is advantageous. The proportions are chosen to optimize the
moisture content of the resulting mixture so that it is a stable solid and can be
compacted to a maximum density in the landfill. The addition of the dry material
spreads the water entrained in the slurry through a larger weight of solids and
improves the particle size distribution so that closer packing can be obtained in the
disposal area. These produce increased shear strength, lower permeability, and lower
combined volume. However, the material is subjected to erosion, saturation, and
leaching.
Stabilization can be reversed since it is not a chemical process. If a mixture is
rewetted or saturated, it may fluidize, causing a rapid decrease in shear strength and
possible structural failure.
30.8
Fixation
FIXATION
Mixing with alkaline flyash
Mixing with lime and flyash
Mixing with blast furnace slag
Mixing with portland cement
Slide 30-21
Many powerplants burn coal that produces alkaline flyash. Mixing this ash
with the wet scrubber product yields a chemical reaction combining stabilization and
fixation. So far, four fixation processes have been identified:
30-11
-------
Mixing with alkaline flyash: Depending on the chemistry of the coal, the flyash
may contain sufficient calcium oxide (CaO) to produce a chemical reaction when dry
ash is mixed with scrubber slurry. Western utilities use this method with brown coals
and lignite. When adequate CaO is present and ash and sludge are mixed in a suitable
ratio, compressive strength close to that of concrete can be obtained. This method
reduces product permeability, which enhances placement efficiency and minimizes
water-related problems.
Mixing with lime and flyash: When the coal does not produce an alkaline
flyash, lime may be added with the flyash to provide the CaO needed for the fixation
reaction. The lime is added at about 4 percent of the weight of the combined ash and
sludge solids. Generally, the ash and sludge are mixed in equal proportions by weight
of solids. The resulting cementitious reaction provides the necessary physical
properties for disposal and utilization.
Mixing with blast furnace slag: Ground and basic blast furnace slag may
produce the cementitious reaction needed to fix the scrubber sludge. This process
works under water, so the slurry can be pumped to a pond or an interim pond where
the reaction will continue. At the pond, the material is allowed to cure, the
supernatant is removed, and the material is excavated as a diy solid and taken to a
landfill. In other cases, the slurry is mixed with flyash and ground slag to produce a
table, fixed material suitable for immediate placement on a structural fill.
Mixing with portland cement: A group of utilities have experimented with the
use of portland cement to fix both scrubber sludges and flyash slurries. When
Portland cement is added at about 5 percent of the sludge solid weight, the process
may be cost-competitive in some areas. The resulting materials cure under water
and produce material suitable for structural fills.
30.9
Utilization
UTILIZATION
Ash Utilization
Cement manufacturing
Concrete materials
Substituted for sand or gravel
FGD By-Product Utilization
Agriculture
Metals recovery
Sulfur recovery
Gypsum
Site Utilization
Landfill construction material
Slide 30-22
30-12
-------
One of the attractive options to waste management is to utilize the waste
material. Plant personnel find this option attractive since it improve the plant
economics and also reduces the burden of disposal cost and landfill requirements.
Ash Utilization
Only bottom ash and flyash are utilized in any significant quantities. The
actual uses are mainly bulk consumption of the wastes with minimum processing.
As a result, the material values derived from utilization are very low, and the
principal advantage is avoidance of disposal costs. Utilization is also limited by the
cost of transportation. The product values are typically so low that transportation
distances are limited to areas where the plant is the closest source.
The major areas of ash utilization are ones in which the ash material can be
substituted for sand or gravel. Because its strong, granular nature, bottom ash is an
attractive material for use as blasting grit, controlled fills, and roofing granules.
Flyash is typically used in the manufacture of portland cement and in the
preparation of concrete mixes.
FGD By-Product Utilization
Some of the methods that have been studied for FGD by-product utilization
are as follows::
Agriculture: Generally, FGD by-products contain large amounts of lime and
thus may be suitable for substitution for natural agricultural lime. However, such
use has been blocked in practice by two facts: (1) available lime is lower in the FGD
by-product than in the natural material, so more is required for similar effectiveness,
and (2) trace elements in the FGD byproducts may have an unacceptable impact.
Metals recovery: FGD by-products usually contain aluminum, iron, silica, and
other metals in very low concentrations. The technology is not fully developed yet for
recovery of trace elements, so this approach does not appear cost-effective at
current metal prices. Furthermore, the final waste volume is not significantly
reduced by the extraction of the trace metals.
Sulfur recovery: FGD by-products are also rich in sulfur which can be
recovered for sale. The obstacles are the incomplete development of the recovery
technology, the low price of elemental sulfur, and the large volume of waste still
remaining after the recovery of sulfur.
Gypsum: Many FGD systems that are operated with forced oxidation can be
made to produce gypsum suitable for drywall and other construction uses. This is a
very effective utilization, but actual application has been limited by the price of
natural gypsum and by the trace materials in the by-product gypsum that may
bleed through to the finished wall surfaces.
30-13
-------
Site Utilization
The solid waste products are sometimes used on-site at the plant. Most uses
are in the area of landfill preparation. Some disposal sites which could not be chosen
because of terrain problems. The by-products are placed in systematic, compacted
lifts designed to recontour the site to correct the terrain problems.
30-14
-------
REFERENCES
1. Elliott, C.T., Standard Handbook of Plant Engineering, McGraw Hill Publishing
Company, New York, 1989.
2. Corbitt, A.R., Standard Handbook of Environment Engineering, McGraw Hill
Publishing Company, New York, 1990.
3. Hanzel, D.S., Laseke, B.A., Smith, E.G., Swenson, D.O., Handbook for Flue Gas
Desulfurization Scrubbing with Limestone, Noyes Data Corporation, New
Jersey, 1992.
30-15
-------
CHAPTER 31. GLOSSARY
-------
31. GLOSSARY
Note: Terms in this glossary are defined as they relate to boilers.
absolute pressure: Pressure above a perfect
vacuum. See vacuum,
absolute temperature: Degrees in
Fahrenheit above absolute zero. See absolute
zero.
absolute zero: Theoretical temperature at
which it is so cold that all molecular movement
ceases (-460°F).
acid dew point: Temperature at which acids
begin to settle out of flue gases. See^as.
after-treatment: Water treatment processes
that occur after steam is generated.
alloy: Blend of two or more different metals.
alternating current: Electric current that
reverses direction periodically, usually many
times per second.
ambient temperature: Temperature of the
surrounding air.
amine: Chemical that prevents corrosion in
condensate and steam piping. See filming
amine and neutralizing amine.
ampere: Unit of measure for electric current.
analog signal: A continuous electrical signal
that varies in amplitude or frequency in
response to changes in sound, light, heat,
position, or pressure.
anion: Ion that has a negative electrical
charge. See ion.
annunciator: Audible alarm that is created
electronically.
anthracite coal: Coal that contains a high
percentage of fixed carbon and a low percentage
of volatiles. Also called hard coal. See fixed
carbon and volatiles.
anthracite (coal) filter: Filter that removes
sludge suspended in water before the water is
used in the boiler.
APCD: Air Pollution Control Device
area: The number of unit squares equal to the
surface of an object.
ash fusion temperature: Temperature at
which ash begins to become molten.
AS ME: American Society of Mechanical
Engineers.
aspirating pump: Pump that automatically
removes air from a process liquid and
discharges the air to the atmosphere. See
pump.
attemperator: See desuperheater.
"A" style boiler: Watertube boiler with a top
steam and water drum and two bottom mud
drums. See boiler.
atmospheric pressure: Force exerted by the
weight of the atmosphere on the earth's surface.
See force.
atomization: Process of breaking a liquid fuel
stream into a mist of tiny droplets.
attemperator: See desuperheater.
available NPSH: Pressure, in feet absolute,
available at the pump datum exerted by weight
of the column of liquid pushing down on the
pump and process pressure, minus vapor
pressure of the liquid in feet absolute. See net
positive suction head.
B
backflow: Condition in which there is not
enough pressure to maintain flow in forward
direction. This drop in pressure causes a
reverse in flow direction. See pressure.
backpass: Region of boiler convective section
downstream of 90° turn away from furnace.
backwash: In a water softener, the upward
flow of water through resin beads that flushes
out impurities through the top of the softener.
baffle: Plate that directs the flow of gases of
combustion for maximum boiler heating surface
contact.
ball valve: Quick-acting, two position shutofT
valve. See valve.
banking: Process that greatly slows the
combustion of coal or some other solid fuel.
battery of boilers: Group of boilers that feeds
steam into the same header.
bituminous coal: Coal that contains a high
percentage of volatiles and a low percentage of
fixed carbon. Also called soft coal. See volatiles
and fixed carbon.
blast furnace gas: Gas recovered as a by-
product from a gas furnace.
blended fuel oil: Mixtures of distillate oils
and residual oils that may contain some crude
oil.
blowback: See blowdown.
blowdown: Pressure in a pressure vessel that
must be reduced before the safety valve will
reseat. Should not exceed 4% of the popping
pressure. Also called blowback. See popping
pressure.
31-1
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boiler: Closed vessel in which water under
pressure is transformed into steam by
application of heat.
boiler horsepower (BHP): Evaporation of
34.5 Ib of water at 212°F into steam at 212°F
in 1 hour.
boiler load: Amount of steam being produced
by a boiler.
boiler bent valve: See air cock.
boiling point: Temperature at which water
changes into steam.
bottom blowdown: Periodic draining of part
of the water in a boiler to remove heavy sludge
that settle to the bottom of a vessel.
Bourdon tube: Tube in side a mechanical
steam pressure gauge that converts the steam
pressure in the boiler into a reading on the
gauge.
breeching: Ductwork that carries spent flue
gases from the exit of the boiler to the stack.
bridge wall: Firebrick wall across a furnace
that supports and encloses the rear end of the
grates.
brine: Strong solution of salt and water. Used
to regenerate water softeners.
British thermal unit (Btu): Amount of heat
necessary to raise the temperature of 1 Ib of
water 1°F.
buckstay: Metal brace used to support a brick
or block wall to a steel framework.
butane: Gas that is derived from refining
crude oil into gasolines.
by-product: A product from a manufacturing
process that is not considered the principal
material.
C2H6: Ethane
CaHg: Propane
calcium (Ca): Metallic element that accounts
for much of the hardness in boiler water. See
element.
calibrate: To determine, by measurement or
comparison with a standard, the correct value of
each scale reading on a meter or other device, or
the correct value for each setting of a control
knob.
calorimeter: An apparatus for measuring
heat quantities generated in or emitted by
materials in processes such as chemical
reactions, changes of state, or formation of
solutions.
carbon (C): Nonmetallic element which is a
constituent of coal and petroleum products. See
element.
carbon dioxide (CC>2): Heavy, colorless gas
that does not support combustion. Formed
from the combustion of carbon and oxygen. See
carbon and oxygen.
carbon monoxide (CO): Colorless, odorless,
highly toxic gas that burns to carbon dioxide
with a blue flame. Formed from the incomplete
combustion of carbon. See carbon and carbon
dioxide.
carryover: Entrainment of small water
droplets with the steam leaving the boiler. See
entrainment.
cascade controller: An automatic control
system in which various control units are linked
in sequence, each control unit regulating the
operation of the next control unit in line.
cast iron sectional boiler: Boiler in which
hot gases of combustion pass through openings
in hollow cast iron sections that contain water.
See boiler.
cation: Ion with a positive electrical charge.
See ion.
cavitation: Condition caused when a portion
of water or other liquid entering the eye of a
pump impeller flashes into steam bubbles.
Causes pitting of pump impellers.
Celsius (Centigrade): Temperature scale
commonly used with the metric system of
measurements. The freezing point of water on
this scale is 0° and the boiling point of water is
100° at normal atmospheric pressure. See
Fahrenheit.
centrifugal pump: Pump that has a rotating
impeller that slings liquid from its vanes. See
pump.
CH4: Methane
chain-grate stoker: Mechanical stoker
designed for gravity-feeding of coal onto the
small grate segments. See stoker.
check valve: One-way flow valve for fluids.
See valve.
chelants: Chemicals that keep the hardness
in boiler water in solution so that it does not
settle on boiler surfaces.
chimney: See stack.
circumference: Outside boundary of a circle.
classifier: Spinning set of vanes located at the
coal and air outlet from the pulverizer that
allows very fine coal dust to pass through, but
throws out the larger coal particles. See
pulverizer.
clinker. Coal or other solid fuel that has fused
together during combustion.
clinker grinder: Large set of mechanical
steel rollers with heavy teeth that grind ash
and clinkers before they enter the ashpit. See
clinker.
31-2
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closed heat exchanger: Heating unit in
which heating medium and fluid being heated
do not mix but are separated by tube walls or
other heating surfaces.
closed heating system: Heating system in
which the condensate is recovered and returned
to the boiler. See condensate.
coal burned in suspension: Coal that is
burned as a dust as it is blown into the furnace.
coke oven gas: Gas consisting mainly of
hydrogen and methane. It is produced when
coke is made from coal in coke ovens.
combined-cycle boiler system: Waste heat
recovery boiler that uses hot exhaust gases as
its heat source. See boiler.
combustion: The burning of gas, liquid, or
solid, in which the fuel is oxidized, evolving heat
and often light.
combustion chamber: Area of boiler where
the burning of fuel occurs.
complete combustion: Burning fuel with the
proper amount of oxygen so that the fuel is
completely consumed without forming any
smoke. See incomplete combustion and perfect
combustion.
compression: Exertion of equal forces from
opposite sites of an object that push toward the
middle.
condensate: Steam that has lost its heat and
returned to water.
condensate polisher: Ion-exchange water
softener that uses resin that can withstand
high temperatures. See ion-exchange water
softener.
condensate receiver: Small vessel for
receiving condensate from the various steam-
using equipment. See condensate.
condenser: A heat transfer device that
reduces a fluid from its vapor phase to its liquid
phase.
conductance: Measurement of the ability of
an electric circuit to allow current to flow.
Letter symbol is G. See current and mho.
conduction: Transfer of heat by actual
physical contact, molecule to molecule.
conductor: A wire, cable, or other body or
medium that is suitable for carrying electric
current
continuous blowdown: Small stream of
water that constantly drains from a boiler to
control the quantities of impurities in a boiler
on a continuous basis.
control valve: Valve driven by an actuator
that receives a command signal from a
controller and converts the signal into a
movement of the valve. See valve.
convection: Transfer of heat by a conveying
medium, such as air.
cooling tower: Evaporative heat exchanger
that removes heat from water.
current: Flow of electrical charge.
cut-in pressure: Automatic pressure control
setting at which the boiler turns ON. See
differential setting.
cut-out pressure: Automatic pressure control
setting at which the boiler turns OFF. See
differential setting.
cycles of concentration: Number of times
solids in a particular volume of water are
concentrated as compared to concentration of
the solids in the original volume of water.
cyclone separator: Cylindrical separator
found in many watertube boilers that swirls the
steam and water mixture and throws water out
by centrifugal force.
D
damper: Device in the flue of a furnace that
controls draft.
deaerator: Pressure vessel that removes
oxygen from the feedwater going to a boiler.
dealkalizer: Ion-exchange unit that works
exactly like a sodium zeolite water softener, but
removes anions and replaces them with
chloride. See sodium zeolite water softener.
desuperheater: Mechanism located after the
superheater in the steam line that slightly cools
the superheated steam. Also called
attemperator.
dewatering: Removal of water from solid
material.
differential pressure: Difference between
two pressures at different points.
differential setting: Difference between the
pressure at which the automatic pressure
control turns the burner ON, and the pressure
at which the automatic pressure control turns
the burner OFF. See cut-in pressure and cut-out
pressure.
digital control: The use of digital or discrete
technology to maintain conditions in operating
systems.
diode: A two-electrode electron tube containing
an anode and cathode.
direct current; Electric current which flows in
one direction, as opposed to alternating current.
Abbreviated dc.
dispersants: Chemicals that prevent solids in
boiler water from sticking together and forming
deposits.
dissolved gases: Gases that have passed into
solution.
dissolved oxygen: Oxygen that has passed
into solution.
31-3
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dissolved solids: Impurities that have
passed into solution.
distillate fuel oil: Fuel oil produced by
distilling crude oil and containing the lighter,
more volatile hydrocarbons. See hydrocarbons.
distilled water: Water that has changed to
steam and then condensed. Distilled water
contains no impurities.
double seated valve: Valve that has two
discs on one stem and two valve seats. See
valve.
downcomer tubes: Tubes that contain cool,
descending water that replenish water supply
to riser tubes.
draft: Movement of air and/or gases of
combustion from a point of high pressure to a
point of low pressure.
drift: A gradual deviation from a set
adjustment.
drip leg: Downward extension of a steam line
that collects condensate.
drum vent valve: See air cock.
dry lay-up: Method of long-term boiler storage
that keeps the boiler free from moisture on the
inside, which prevents damage from corrosion.
See laying up.
D-slide vales: Valves that control the
admission and exhaust of steam to the steam
pistons in a duplex pump.
"D" style boiler: Watertube boiler with a top
steam and water drum and a bottom mud
drum. Similar to the "0" style boiler except
that steam-generating tubes on one side are
extended to leave an open D-shaped area close
to the center for combustion. See boiler.
ductility: Plasticity exhibited by a material
under tension loading and measured by the
amount the material can be permanently
elongated.
E
economizer: Series (bank) of boiler tubes
through which feedwater travels to the boiler
drum.
efficiency: Comparison of the power input to
the power output of a mechanical apparatus.
electric potential: The work which must be
done against electric forces to bring a unit
charge from a reference point to the point in
question.
element: Any of over 100 basic substances
consisting of atoms of one kind that individually
or collectively make up all matter.
embrittlement: Condition in which metal
becomes brittle due to crystalline cracking.
entrainment: Suspension of contaminant
particles carried along with the flow. See
carryover.
evaporator: Set of heat exchangers that
generates water suitable for boiler use from
water that contains large quantities of
impurities.
excess air (EA): Amount of air added to the
combustion process over and above that which
is theoretically necessary.
external header cast iron sectional boiler:
Boiler containing cast iron sections individually
connected to external manifolds (headers) with
screwed nipples.
externally-fired fire-tube boiler: Firetube
boiler with a separate furnace area built on
refractory brick.
Fahrenheit: Temperature scale commonly
used with the U.S. system of measurements.
The freezing point of water on this scale is 32°
and the boiling point of water is 212° at normal
atmospheric pressure. See Celsius.
feedwater: Water that is supplied to the
boiler.
feedwater regulator: Mechanism that
automatically maintains a constant safe water
level in a boiler.
filming amine: Chemical that forms a
protective coating on condensate piping. See
amine.
firebox boiler: Firetube boiler in which the
furnace is surround on the sides by a water leg
area. See boiler.
firetube boiler: Boiler in which hot gases of
combustion pass through the tubes and water
contacts the outside surfaces of the tubes. See
boiler.
fixed carbon: Portion of coal that remains in
a solid form when the coal is heated.
flame impingement: Flame from burning
fuel that strikes the boiler tubes or refractory
brick. See refractory.
flame scanner: Device that confirms that the
pilot and main burner flames exist.
flared: Spread outward.
flashback: Ignition of a small volume of
volatile vapors or gases that causes
pressurization of the furnace for a brief period.
flash point: Lowest temperature at which
vapors given off by a substance will make a
flash of flame, but not continue to burn when an
open flame is passed over it.
flash steam: Steam produced when water that
is saturated with heat is released to a lower
pressure.
. 31-4
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flue: 1. Pipe that increases heating surface
and carries flame or gases of combustion around
or through water in a firetube boiler. 2.
Channel in a stack for directing smoke and
gases of combustion out of the area.
flue furnace boiler: Firetube boiler in which
the furnace consists of a large tube or pipe that
passes the length of the shell. See boiler.
fluid: Any material that can flow from one
point to another.
flyash: Small particles of ash from the
combustion process that are carried along with
the draft through a boiler furnace and ductwork.
foaming: Development of froth on the surface
of boiler water.
foot-pound: Unit of measure that equals the
movement of an object by a constant force (in
pounds) to a specific distance (in feet).
force: Energy exerted or brought to bear on.
forced draft: Introduction of combustion air
into a furnace to combine with fuel for
combustion.
forced draft cooling tower: Cooling tower
with a fan located at the bottom to force a draft
through the tower. See cooling tower.
fossil fuel: Fuel derived from plants and other
organic matter that have decayed below the
earth's surface while subjected to great pressure
over millions of years.
fractions: Separation of individual materials
from the deposit crude oil in the refining
process.
fusibility temperature: The temperature at
which a material is liquified by heat.
gas: Fluid that has no particular shape or
volume.
gate valve: Valve used to shut off or admit
flow. See valve.
gauge glass: Glass connected to a water
column or directly to a boiler that allows an
operator to see the water level inside a boiler.
See flat gauge glass and tubular gauge glass.
gauge pressure: Pressure above atmospheric
pressure. Assumes atmospheric pressure as
being zero. See atmospheric pressure.
globe valve: Valve having a tapered, rounded,
or fiat disc held horizontally on the stem. See
valve.
grade of coal: Size of coal.
gravity: Natural force that makes objects on
earth fall to the lowest point possible.
H
Hg: Hydrogen
H2O: Water
H2S: Hydrogen Sulfide
hard coal: See anthracite coal.
header: Manifold that feeds several branch
pipes or takes in steam or water from several
smaller pipes.
heating surface: Any part of boiler metal that
has hot gases of combustion on one side and
water on the other.
HHV: Higher Heating Value = gross heating
value = the total heat obtained from combustion
of a specified amount of fuel at stoichiometric
conditions.
high water: Higher-than-acceptable water
level in a boiler.
horizontal return tubular (HRT) boiler:
Externally-fired firetube boiler consisting of a
horizontal shell set on a brick furnace. See
boiler.
horsepower (HP): Unit of measure that
equals 33,000 ft-lb (foot-pounds) of work in 1
minute.
hot process water softener: Pressure vessel
that uses steam to heat makeup water by
direct contact and remove hardness.
hot water boiler: Boiler that is completely full
of water that produces only hot water, not
steam. The water transports heat.
hydraulics: The brand of science and
technology concerned with the mechanics of
fluids.
hydrocarbons: Any number of compounds
composed of hydrogen and carbon atoms.
hydrostatic test: Water test for leaks in a
boiler. The boiler is filled with water and
pressurized to 1-1/2 its MAWP. See maximum
allowable working pressure.
hyperbolic cooling tower: Distinctively
shaped cooling tower that has no fan. See
cooling tower.
ignition arch: Curved arch where green coal
enters the furnace in a chain-grate stoker-fired
boiler.
impeller: Rotating part of centrifugal pump
that slings liquid from its vanes. See pump.
implosion: An inward collapse caused by
external pressure.
inches of mercury (in. Hg): Units of
measure for vacuum. See vacuum.
31-5
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incomplete combustion: Burning fuel
without proper amount of oxygen, adequate
mixing of fuel and oxygen, or a temperature
sufficient enough to cause satisfactory reaction
of the fuel and oxygen.
induced draft: Use of a fan or stack to create
a negative pressure in the furnace to keep
smoke and hot gases of combustion from
leaking out. See draft.
induced draft cooling tower: Cooling tower
with a fan located at the top to induce a draft in
the tower. See cooling tower.
in-line steam separator: Cylindrical vessel
that contains baffles or stationary vanes that
swirl the steam and water mixture as it passes
through the separator, which makes the water
drop out.
inside diameter (ID): Distance from inside
edge to inside edge of circle through the center of
the circle. See circle.
insulator: A device having high electrical
resistance and used for supporting or
separating conductors to prevent undesired flow
of current from them to other objects.
intercooler: Cooler located between two
compressing stages of an air compressor.
internally-fired firetube boiler: Firetube
boiler with a furnace area surrounded by the
pressure vessel. See boiler.
inverse solubility: Tendency of certain scale-
forming impurities in boiler water to settle out
as temperature of the boiler water increases.
ion: Atom with a positive or negative electrical
charge.
ion exchange: Reversible interchange of an
ion on an insoluble solid with another ion in a
solution surrounding the solid. See ion.
ion-exchange water softener: Device that
uses a brine solution and resin beads to soften
water.
joint: Area where metal is riveted or welded
together. Also called seam.
K
kW: Kilowatt
latent heat: Heat in Btu that is added so that
boiling water at a given temperature will
change into steam at the same temperature.
laying up: Taking a boiler out of service for
longer than a normal period of time. See dry
lay-up and wet lay-up.
leaching: The dissolving, by liquid solvent, of
soluble material from its mixture with an
insoluble solid.
lead and lag: Starting and stopping boilers in
a battery of boilers so that they meet the steam
demand without all the boilers running at once.
lean mixture: A fuel-air mixture containing a
low percentage of fuel and a high percentage of
air, as compared with stoichiometric conditions.
LHV: Lower Heating Value = net heating
value = the gross heating value minus the
latent heat of vaporization of the water vapor
formed by the combustion of the hydrogen in
the fuel. For a fuel with no hydrogen, net and
gross heating values are the same.
lift check valve: Type of check valve that
uses a piston, ball, or disc to stop backflow.
See check valve and backflow.
lift pump: A pump for lifting fluid to the
pump's own level.
light refraction: Deflection of light or an
energy wave from a straight path when it
passes from one medium (e.g., air) to another
medium (e.g., water) in which its velocity is
different.
lignite: Very soft coal that has a high moisture
content and low heat value.
longitudinal joint: Joint that runs along the
length of a boiler drum or shell.
low water: Lower-than-acceptable water level
in a boiler that is dangerous because it can
cause overheating of a boiler.
low water fuel cutoff: Device located slightly
below the NOWL of a boiler that shuts OFF the
boiler burner in the event of low water. See
normal operating water level.
M
main steam stop valve: Gate valve in the
main steam line between the boiler and the
steam header. See gate valve.
makeup water: Water that is added to the
system to replace water that is lost or drained.
manhole: Hole on the steam and water side of
a boiler used to clean, inspect, and repair a
boiler.
manometer: Instrument that measures draft.
See draft.
maximum allowable working pressure
(MAWP): Highest legal pressure at which a
pressure vessel may be operated.
maximum capacity: Maximum rating in
pounds of steam that a boiler is designed to
produce in 1 hour at a given pressure and
temperature.
mechanical draft: Draft created by one or
more fans. See draft.
31-6
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mechanical seal: Assembly installed around
a shaft to prevent leakage of process liquids.
metering orifice: A fluid nozzle designed to
accurately control fluid-flow rates.
mercury switch: Control device that uses the
movement of mercury in a glass tube to control
electrical flow in a circuit.
methane: Bacterial by-product gas formed in
waste-water treatment plants, landfills, and
other areas.
mho: Unit of conductance equal to the
reciprocal of an ohm. See conductance.
micromho: On-millionth (1/1,000,000) of a
mho. See mho.
microprocessor: A single silicon chip on
which the arithmetic and logic functions of a
computer are performed.
milliamp: One-thousandth (1/1000) of an
ampere. See ampere.
modulating pressure control: Control device
that regulates the burner for a higher or lower
fuel-burning rate depending on steam pressure
in the boiler.
MW: Megawatt
N
N2: Nitrogen
NAAQS: National Ambient Air Quality
Standards.
natural draft: Draft that occurs without
mechanical aid. See draft.
natural gas: Gas obtained from natural
sources in the earth. See gas.
negative-suction pump installation: Any
installation where a pump must draw liquid up
from a source below the pump. See pump.
NESHAPS: National Emission Standards for
Hazardous Air Pollutants (NESHAPs).
net positive suction head (NPSH):
Numerical value that equals the minimum
suction conditions that must be maintained to
prevent cavitation of a pump.
NHa: Ammonia
neutralizing amine: Chemical that raises the
pH level of the condensate. See amine.
noncondensable gas: Any gas that will not
change into a liquid when its temperature is
reduced.
nonreturn valve: Combination shutoff and
check valve that allows steam to pass out of the
boiler, but a backflow of steam from a drop in
pressure causes the valve to close. See value.
nonrising stem valve: Valve with a disc that
threads up onto the stem as the stem is turned.
The stem does not back out of the valve. See
valve.
normal operating water level (NOWL):
Level of the boiler water at normal operation.
NOx: Nitrogen Oxides
NSPS: New Source Performance Standards.
O
ohm: The unit of electrical resistance, equal to
the resistance through which a current of 1
ampere will flow when there is a potential
difference of 1 volt across it.
opacity: Quality of being opaque. See opaque.
open heat exchanger: Heating unit in which
steam or another heating medium and fluid
being heated come into direct contact.
open impeller: Impeller that has vanes that
are not enclosed or supported by a shroud (side
wall) on either side. See impeller.
optical pyrometer: An instrument which
determines the temperature of a very hot
surface from its incandescent brightness; the
image of the surface is focused in the plane of
an electrically heated wire, and current through
the wire is adjusted until the wire blends into
the image of the surface.
Orsat analyzer: Aspiring flue-gas analyzer
that measures the percentages of carbon
dioxide, carbon monoxide, and oxygen in flue
gases.
"O" style boiler: Watertube boiler with a top
steam and water drum and a bottom mud
drum. See boiler.
outside diameter (OD): Distance from
outside edge to outside edge of a circle through
the center of the circle.
overfire air: Secondary air in a boiler fired by
sold fuel. See secondary air.
oxidizing flame: A flame, or the portion of it,
that contains an excess of oxygen.
oxygen (02): Colorless, tasteless, odorless gas
that is approximately 21% of the air. Oxygen is
necessary for combustion.
package boiler: Boiler supplied complete
from the manufacturer with controls and
appliances attached.
particulate: Flyash particles carried along
with flue gases.
part per billion (ppb): One part in a billion.
part per million (ppm): One part in a
million.
passes: Number of times gases of combustion
flow the length of the pressure vessel as they
transfer heat to the water.
31-7
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perfect combustion: Burning fuel with
precisely the right quantity of oxygen so that no
fuel or oxygen remains. Attainable only in a
laboratory.
pH: Value representing how acidic or alkaline
water is.
phosphates: Chemicals that cause hardness
particles to settle out as a heavy sludge.
plenum: Area of furnace between combustion
chamber and stack.
o: Particulate Matter less than 10 microns
in size.
pneumatics: Fluid statics and behavior in
closed systems when the fluid is gas.
popping pressure: Lowest pressure that will
pop the safety valve.
positive-displacement pump: Reci-
procating or rotary pump in which every stroke
or revolution moves a predetermined amount of
liquid.
pounds of steam per hour (Ib/hr): Unit of
measure that expresses the amount of steam
produced by a boiler in 1 hour.
pounds per square inch (psi): Number of
pounds of pressure exerted on 1 sq. in. of a
given area. See pressure.
power: Unit of measure that equals the
amount of foot-pounds of work in a given period
of time. See foot-pound.
prenumericator: Air-actuated fuel level
device.
pressure: Application of force. Commonly
measured in psi. See force.
pressure gauge: An instrument having
metallic sensing element or a piezoelectric
crystal to measure pressure.
pretreatment: Water treatment processes
that occur before water enters the boiler.
primary air: Initial volume of air that enters
the furnace with the fuel for most of the
combustion process.
priming: Severe form of carryover in which
large slugs of water leave the boiler with the
steam. See carryover.
programming clock: Rotating cam sequencer
or microprocessor timing device that controls the
sequence and length of the programmed device.
propane: Liquefied hydrocarbon gas derived
from the petroleum refining process. See gas.
proximate analysis: Percentage of moisture,
volatiles, fixed carbon, and ash in coal.
pulverizer: Grinding mill that grinds coal to a
very fine powder.
pump: Device that moves or compresses fluids
or gases.
pyrometer: Instrument that measures
temperature above the temperature range of
mercury thermometers.
Q
quality of steam: Measure of steam
expressed as a percentage of its dryness.
quick-opening valve: Valve that requires
only a 90° turn of the lever to move from fully
closed to fully open. See valve.
R
radiation: Transfer of heat from a hot body to
a cold body without physical contact or a
conveying medium.
radius: One-half of the diameter of a circle.
See diameter and circle.
rank: Hardness of coal.
reagent: Chemical used in water treatment
test to show the presence of a particular
substance.
recirculation line: Line that provides a
minimum flow through a pump to prevent
overheating.
reducing flame: A flame having excess fuel
and being capable of chemical reduction, such
as extracting oxygen from other chemical
compounds.
rectifier: Electrical device that converts
alternating current (AC) to direct current (DC).
refractory: Brickwork used in boiler furnaces
and for boiler baffles.
representative sample: Sample that is
exactly the same as the sample being tested.
required NPSH: Net positive suction head
calculated by the manufacturer and supplied
with the pump. See net positive suction head.
reseat pressure: The pressure at which a
safety valve will reseat. It will pop above this
pressure.
residual fuel oil: Fuel oil that remains after
the lighter, more volatile hydrocarbons have
been distilled off.
resistance: Measure of the ability of an
electrical circuit to oppose current flow.
retort stoker: Mechanical stoker in which coal
in the retort chamber overflows onto tuyeres
and quickly set on fire. See stoker, retort
chamber, and tuyere.
rich mixture: an air-fuel mixture that is high
in its concentration of combustible component.
riser tubes: Tubes containing rising water
that are exposed to the highest temperatures in
the furnace area.
31-8
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rising stem valve: Valve in which the
handwheel and stem move outward from the
body of the valve as the valve is opened. See
valve.
root-mean-square: The square root of the
average of the squares of a series of related
values.
rotor: The rotating member of an electrical
machine or device.
rotary cup burner: Assembly that mixes fuel
oil with air.
safety valve: Valve that keeps the boiler from
exceeding its MAWP. See maximum allowable
working pressure and valve.
saturated steam: Steam that has absorbed
all the Btu per pound that the steam can hold
at its particular pressure.
scale: Mineral deposits formed on the heating
surfaces of a boiler.
scotch marine boiler: Internally-fired
firetube boiler that has a flue furnace and
horizontal shell. See boiler.
secondary air: Air added to fuel to ensure
that sufficient oxygen is available to complete
the combustion process.
sediment: Matter that settles to the bottom of
a liquid.
sensible heat: Heat that can be measured by
a change in temperature.
set point: The value selected to be maintained
by an automatic controller.
shear: Exertion of equal forces in opposite
directions in the same plane. See force.
sight glass: See gauge glass.
single-acting pump: Reciprocating pump
that moves fluid in only one direction. See
pump.
siphon: A loop or tube that holds water and is
placed between the steam gauge connection and
the steam gauge. A siphon protects the
Bourdon tube from the high temperature of the
steam. See Bourdon tube.
SIPs: State Implementation Plans
slag: Solid deposits that accumulate on furnace
walls and boiler tubes.
slag screen: Loosely spaced bank of water
tubes placed between the superheater and the
combustion area of the furnace.
slaker: Conveyor in which lime is mixed with
water to make a soluble paste.
slow-opening valve: Valve that requires five
or more full turns of the handwheel to move the
valve from fully closed to fully open. See valve.
SO2: Sulfur Dioxide
soft coal: See bituminous coal.
solubility: Relative ease with which a
material dissolves in a solution.
soot: Fine powder consisting primarily of
carbon that results from incomplete combustion.
spalling: Breaking up by chipping.
specific gravity: Weight of a given volume of
a material divided by the weight of an equal
volume of water measured at 60°F.
spray pond: Shallow pond with a network of
spray nozzles that spray the water into the air
for cooling.
stack: Outlet to the atmosphere for the gases
of combustion. Used to create draft. Also called
chimney.
static: Stationary, not moving, at rest.
static head pressure (SHP): Pressure at the
bottom, or at some specified point, of a column
of still liquid.
stator: The portion of a rotating machine that
contains the stationary parts of the magnetic
circuit and their associated windings.
steam: Gaseous form of water. Steam is
odorless, colorless, and tasteless.
steam scrubber: Series of corrugated plates
that force the steam and water mixture to
follow a zigzag pattern as the steam passes
through when leaving the boiler drum. Also
called chevron scrubber.
steam trap: Mechanical device used to remove
condensate from steam piping.
Stirling boiler: Watertube boiler with three
steam and water drums on the top and a mud
drum beneath, interconnected by a large
number of water tubes. See boiler.
stoichiometric: The ideal mixture of fuel and
air for complete combustion.
stoker: 1. Mechanical device that
automatically feeds green coal or other solid fuel
to a furnace. See green coal. 2. Bituminous
coal that is 3/4" to 1-1/4" in size. See
bituminous coal.
submerged conveyor: Heavy steel pan or
apron conveyor immersed in a water trough.
submerged-tube (wet-top) vertical boiler:
Fire-tube boiler with fire tubes completely
covered with water all the way to the tube
sheet. See boiler.
sump: Pit or reservoir serving as a drain for
liquids.
superheated steam: Steam that has been
raised in temperature above the temperature
that corresponds with its pressure.
superheater: Bank of boiler tues through
which only steam passes, not water. Steam is
given additional heat in a superheater.
31-9
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surge tank: Storage tank that holds a reserve
of water for periods when a boiler demands
feed water faster than the deaerator can provide
it.
suspended solids: Impurities that do not
pass into solution.
swell: Expansion of water when it is heated.
swing check valve: Type of check valve that
uses a disc to stop backflow. See check valve
and backflow.
synchroscope: A cathode-ray oscilloscope
designed to show a sort-duration pulse by using
a fast sweep that is synchronized with the
pulse signal to be observed.
turbulators: Devices that swirl hot gases from
combustion as the gases pass through fire tubes
to make more intimate contact with the tubes.
turndown: Ratio of the highest capacity of the
device to the lowest capacity.
tuyere: Air-admitting grate designed to rapidly
establish combustion of entering fuel.
U
ultimate analysis: Percentages of nitrogen,
oxygen, carbon, ash, sulfur, and hydrogen
(NOCASH) in coal.
tee: T-shaped restriction or fitting in piping
that changes the direction of flow.
test gauge: Gauge used for calibrating other
gauges.
THC: Total Hydrocarbons
therm: Unit of measure indicating 100,000
Btu. See British thermal unit.
thermal shock: Stress imposed on boiler
metal by sudden and drastic change in
temperature.
thermocouple: Temperature measuring
device consisting of two dissimilar metals
bonded together that produce a voltage
proportional to the temperature.
thermohydraulic feedwater regulator:
Continuously operating control that controls
feedwater flow in direct response to a change in
the NOWL. See feedwater regulator.
throttling: Controlling the amount of flow that
passes through a valve by partially closing it.
titration test: Test that determines the
concentration of a dissolved substance.
ton: Unit of measure that equals 2000 Ib.
total force: Area of a surface multiplied by
pressure (in psi) being exerted. Always
expressed in pounds, not psi. See psi.
total heat: Sum of sensible heat and latent
heat. See sensible heat and latent heat.
transformer: An electrical component
consisting of two or more multi-turn coils of wire
placed in close proximity to cause the magnetic
field of one to link the other.
transistor: An active component of an
electronic circuit consisting of a small block of
semiconducting material to which at least three
electrical contacts are made. It may be used as
an amplifier, detector, or switch.
transmitter: A device which move data from
one location to another.
tubular gauge glass: Gauge glass used for
pressures up to 400 psi. See gauge glass.
vacuum: Pressure lower than atmospheric
pressure.
vacuum breaker: Vent on top of a vessel that
allows air to be pulled into the tank to prevent
formation of a vacuum. See vacuum.
vacuum gauge: Pressure gauge used to
measure pressures blow atmospheric pressure.
valance: Degree of combining power of an
element or chemical group.
valve: Mechanical device that starts, stops, or
regulates the flow of a liquid, gas, or loose bulk
material.
vapor: Diffused matter in a gaseous state.
vapor pressure of water: Absolute pressure
at which water begins to form steam at a
certain temperature.
vent condenser: In-line heat exchanger
installed in the vent from the deaerator to the
roof.
venturi: Nozzle with a slight hourglass-
shaped taper.
vibrating-grate stoker: Mechanical stoker
with inclined grates that vibrate causing the
ashes to fall off of the grates. See stoker.
viscosity: Ability of liquid or semi-liquid to
resist flow.
viscous liquid: Liquid that maintains an
amount of shearing stress based on the velocity
of its flow. A viscous liquid offers continued
resistance to flow.
volatiles: Constituents that distill out of coal
and burn off as a gas when the coal is heated.
W
waste heat recovery boiler: Firetube or
water-tube boiler in which heat that would
otherwise be discarded is used to make steam.
See boiler.
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water column: Metal vessel installed on the
outside of a boiler shell or drum at the NOWL
that helps an operator determine the water
level in a boiler See normal operating water
level.
water conductivity: Degree to which a water
sample will conduct a small electrical current.
See conductance.
water hammer: Hydraulic shock that results
from water buildup in steam piping.
watertube boiler: Boiler in which water
passes through the tubes and hot gases of
combustion pass over the outside surfaces of the
tubes. See boiler.
waterwall: Large flat surface of many tubes
placed side by side against the furnace walls
that increases the heating surface of a boiler
and helps prevent refractory damage to furnace
walls because of overheating.
wet lay-up: Method of short-term boiler
storage that keeps the boiler free from oxygen
on the inside, which prevents damage from
corrosion. See laying up.
windbox: Plenum to which the forced draft fan
supplies air before the air enters the furnace.
See plenum.
work: The transference of energy that occurs
when a force is applied to a body that is moving
in such a way that the force has a component in
the direction of the body's motion.
working pressure: Maximum allowable
working pressure or the pressure at which the
boiler is normally operated. Caution: When
using this term, always clarify the way the term
is being used. See maximum allowable working
pressure.
zeolites: Synthetic sodium aluminosilicate
cation-exchange materials. See cation.
31-11
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TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
1. REPORT NO.
EPA-453/R-94-056
2.
4. TITLE AND SUBTITLE
High Capacity Fossil Fuel Fired Plant Operator Training
Program - Student Handbook
7. AUTHOR(S)
Shirley Pearson, Matt Gardner, Quang Nguyen
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Energy and Environmental Research Corporation
18 Mason
Irvine, California 92718
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
September 1994
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-D1-0117
13. TYPE OF REPORT AND
Final
PERIOD COVERED
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
James Eddinger, Office of Air Quality Planning and Standards
16. ABSTRACT
This Student Handbook is part of a model State training program which addresses the training needs
of high capacity fossil-fuel fired plant (boiler) operators. Included are generic equipment design
features, combustion control relationships, and operating and maintenance procedures which are designed
to be consistent with the purposes of the Clean Air Act Amendments of 1990. This training program is
not designed to replace the site-specific, on-the-job training programs which are crucial to proper
operation and maintenance of boilers.
17.
KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Air Pollution Control Technology
Boilers
High Capacity Fossil Fuel-Fired Plants
Operator Training
18. DISTRIBUTION STATEMENT
Release Unlimited
b. IDENTIFIERS/OPEN ENDED TERMS
Boilers
Air Pollution Control
Training
19. SECURITY CLASS (Repon)
Unclassified
20. SECURITY CLASS (Page)
Unclassified
c. COSATI Field/Group
21. NO. OF PAGES
582
22. PRICE
iPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE
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U.S. Environmental Protection Agency
Region 5, Library (PL-12J)
77 West Jackson Boulevard, 12th Floor
Chicago, IL 60604-3590
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