INDUSTRIAL BOILER
INSPECTION GUIDE
PEOCo ENVIRONMENTAL
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EPA-340/1-81-007
INDUSTRIAL BOILER
INSPECTION GUIDE
by
PEDCo Environmental, Inc.
1006 N. Bowen Road
Arlington, Texas 76012
Contract No. 68-01-6310
Task Order No. 9
Project No. 3560-3-9
John R. Busik, Project Officer
Robert L. King, Task Manager, DSSE
Division of Stationary Source Enforcement
U.S. ENVIRONMENTAL PROTECTION AGENCY
401 M. STREET, S.W.
WASHINGTON, D.C. 20460
October 1, 1981
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DISCLAIMER
This report was furnished to the U.S. Environmental Protection Agen-
cy (EPA) by PEDCo Environmental, Inc., in fulfillment of Contract No.
68-01-6301, Task No. 9. The contents are as received from the contractor.
The opinions, findings, and conclusions expressed are those of the authors and
not necessarily those of the U.S. Environmental Protection Agency. Mention of
company, process, or product name is not to be considered as an endorsement by
the U.S. Environmental Protection Agency.
n
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CONTENTS
1. Introduction 1-1
1.1 How to use this guide 1-1
1.2 How to update this guide 1-2
2. General Inspection Procedures 2-1
2.1 Preparation and file review 2-1
2.2 Performing the inspection 2-2
2.2.1 Pre-entry observations and safety 2-2
2.2.2 Plant inspection 2-3
3. Control Equipment Inspection 3-1
3.1 Source identification 3-1
3.2 Inspection procedure 3-1
3.3 Stack observation 3-4
3.4 Fan inspection 3-7
3.4.1 F-Factor 3-7
3.5 Control equipment 3-12
3.6 Fabric filter 3-12
3.6.1 External inspection 3-12
3.6.2 Internal inspection 3-20
3.7 Electrostatic precipitator 3-22
3.7.1 External inspection 3-22
3.7.2 Internal inspection 3-31
3.8 Venturi scrubber 3-32
3.8.1 External inspection 3-35
3.8.2 Internal inspection 3-35
3.9 Cyclones 3-37
3.9.1 External inspection 3-37
3.9.2 Internal inspection 3-40
4. Boiler Inspection 4-1
Appendices:
A. Checklist forms A-l
B. Sample boiler inspection report B-l
Glossary
Bibliography
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LIST OF FIGURES
Number Page
3-1 Source Identification Checklist 3-2
3-2 Example of Boiler Equipment Identification Form 3-3
3-3 Example of Visible Emission Observation Form 3-5
3-4 Example of Fan Data Sheet 3-8
3-5 Photograph of an Oxygen Meter On a Boiler Control Board 3-11
3-6 Example of Fabric Filter Description Data Sheet 3-13
3-7 Photograph of Fabric Filter, Showing Upper and Lower Catwalk, 3-15
Compartment Access Doors, and Magnehelic Gages.
3-8 Cross Section of Fabric Filter, Showing Filter Internals and 3-16
a Pressure Gage
3-9 Fabric Filter Compartment External Inspection 3-17
®
3-10 Photograph of a Magnehelic Gage Measuring Overall Pressure 3-18
Drop of a Fabric Filter During Normal Service
3-11 Photograph of a Magnehelic Gage Measuring the Static 3-19
Pressure of the Dirty Side of a Fabric Filter
3-12 Diagram of Electrostatic Precipitator Showing One Field and 3-23
One TR Set
3-13 Example of ESP Description Data Sheet 3-24
3-14 General Relationship Between SCA and Sulfur Content For a 3-26
Cold-Side ESP Operating At 300°F
3-15 Example of ESP Electric Data Checklist 3-27
3-16a Relationship Between Collection Efficiency and Specific 3-29
Corona Power for Fly Ash Precipitators; Based On Field
Test Data
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FIGURES (continued)
Number Page
3-16b Efficiency Versus Specific Corona Power Extended to High 3-29
Collection Efficiencies; Based On Test Data On Recently
Installed Precipitators
3-17 Example of External ESP Inspection Form 3-33
3-18 Flow Diagram of a Typical Venturi Scrubber System 3-34
3-19 Example of Venturi Scrubber Description Data Sheet 3-36
3-20 Flow Diagram of a Dry Cyclone Collector 3-38
3-21 Example of Cyclone Description Data Sheet 3-39
4-1 Example of Boiler Description Data Sheet 4-3
4-2 Example of Boiler Instrumentation Data Sheet 4-6
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LIST OF TABLES
Number Page
3-1 Plume Characteristics and Combustion Parameters 3-6
3-2 F-Factors for Various Fuels 3-9
3-3 Effects of Changes From Normal Operation On ESP Control 3-28
Set Readings
VI
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SECTION 1
INTRODUCTION
1.1 HOW TO USE THIS GUIDE
This inspection guide has been prepared under the direction of the U.S.
Environmental Protection Agency (EPA) to assist state and local agency person-
nel in the inspection of industrial boilers and associated air pollution
control systems. It describes various kinds of industrial boilers and pollu-
tion control equipment, and outlines inspection procedures for these systems.
It does not provide in-depth coverage of environmental regulations because
regulations vary from state to state and are subject to revision. Although
this guide includes a brief discussion of pollutants generated by boilers,
the inspector should study current state and Federal regulations regarding
these pollutants.
This manual is intended as a field guide only; it should not be construed
as a detailed design manual. Additional technical details pertaining to the
operation of boilers and their associated pollution control equipment can be
found in various available publications. Selected sources are listed in the
bibliography.
In many cases inspectors have to cover a large number of sources and thus
have little time to spend with each individual source. Although most of the
sources they inspect are in compliance, some are regularly out of compliance.
These noncomplying sources, especially if they are large emitters, require
more individual attention. Concentrating on violators will improve overall
compliance and air quality more than repeated visits to sources that are
usually in compliance. Of course, each agency will have to strike a balance
and determine how its resources should be spent to achieve continuing compli-
ance and good air quality.
This inspection guide assists the inspector in determining the actual or
probable reason for a violation. With this knowledge he or she can exert more
pressure on the source to come into compliance. In some cases, the knowledge
Industrial Boiler Inspection Guide Introduction
10/81 1-1
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the inspector acquires may help the source to identify the problem. The
inspector should, however, be cautious not to recommend specific remedial
action. For example, if torn bags are noted in one compartment of a fabric
filter, it is all right for the inspector to inform the source, but not to
instruct the source to repair or replace the bags, keep the compartment iso-
lated, or to take any other specific action. Having been informed that the
bags are torn, it is up to the source to do whatever is necessary to maintain
the equipment properly. The danger in giving specific directions is that the
source may blame the inspector and the agency he represents for any problems
that result from following those directions.
1.2 HOW TO UPDATE THIS GUIDE
This guide is presented in loose-leaf notebook style to allow easy
updating. The notebook style also makes it simple to add or delete material
as appropriate. The guide is designed to be revised or updated as new data
become available. The sectional page-numbering system allows for easy inser-
tion of new pages or the updating of existing pages. The name of the section
appears at the bottom right of each page as shown below:
Title Section Title
Issue Date Page Number
An actual example of the page numbering system is as follows:
Industrial Boiler Inspection Guide General Inspection Procedures
10/81 2-1
New Page
When a new page containing additional data is sent to the user, it will
be numbered as follows:
Industrial Boiler Inspection Guide General Inspection Procedures
1/82 2-1.1
This page would be inserted between pages 2-1 and 2-2.
Industrial Boiler Inspection Guide Introduction
10/81 1-2
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Revised page
If page 2-1 is revised, it will be reissued with the same page number,
the issue date of the revision, and the revision number.
Industrial Boiler Inspection Guide General Inspection Procedures
9/82-Rl 2-1
This page will replace the superseded page 2-1 that was issued 10/81.
Industrial Boiler Inspection Guide Introduction
10/81 1-3
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SECTION 2
GENERAL INSPECTION PROCEDURES
Careful preparation and planning are vital to a successful boiler inspec-
tion. Your inspection will be meaningful only if you know what information
you want to collect and are familiar with the equipment at the site. Time
invested in a file review will reduce your field time and that of the source
representative. Also, if you can obtain all the required data during your
inspection, you will avoid later time-consuming efforts to secure missing
data. Furthermore, if you do your homework, plant personnel will view you as
a professional, and are more likely to provide the complete information you
need and to cooperate with the agency you represent to meet clean-air objec-
tives. The guidelines outlined below will help you conduct a successful
boiler inspection.
2.1 PREPARATION AND FILE REVIEW
The first step in preparing for an inspection is to review available
agency data regarding the specific boiler. Note the type of boiler and the
pollution control equipment that will be inspected, and become familiar with
that equipment by reviewing appropriate sections of this guide. Also check
the following file items:
1. Pending compliance schedules
2. Construction and/or operating permits
3. Past conditions of noncompliance and citizen complaints
4. Frequency of malfunction reports
5. History of abnormal operations
6. Stack test data.
Industrial Boiler Inspection Guide General Inspection Procedures
10/81 2-1
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The file review should summarize permit data and previous inspection
information. Stack test data and previous inspection reports will indicate
the normal range of operating conditions for the boiler and its pollution
abatement equipment so that you can detect any deviations from those condi-
tions during the inspection. For example, visible emissions and a lower
pressure drop across a fabric filter indicate that bags may be torn or miss-
ing. If the boiler is operating at an abnormally high rate (look at steam
production or fuel consumption rates), the pollution control equipment may be
overloaded. If previous inspection reports are available, look for trends in
abatement equipment operation, especially pressure drops across fabric fil-
ters, cyclones, and scrubbers. The pressure drop across a fabric filter
slowly increases as bags get older and become blinded. Worn scrubber spray
nozzles decrease pump pressure and cause the scrubber to become less effec-
tive.
Review all regulations that apply to the boilers at the inspection site.
If the boiler is subject to an opacity limit or a fuel sulfur limit (or cor-
responding S02 emission limit), read the stack opacity or collect other neces-
sary data to demonstrate compliance. The sulfur content of the fuel is usual-
ly shown on invoices from the fuel supplier. If the boiler is down, note when
it is expected to start up again. Some boilers operate only during the win-
ter; others are connected with seasonal or cyclic process operations.
If you are required to announce your inspections in advance, a lead time
of one day to one week is generally adequate to ensure that necessary plant
personnel will be available. Contact someone at the plant who has authority
to release data and samples and to arrange for access to specific processes.
2.2 PERFORMING THE INSPECTION
2.2.1 Pre-entry Observations and Safety
Your inspection should begin before you enter the plant. You can legally
photograph the plant and read stack opacities (if you are currently certified
to read visible emissions) without obtaining permission from the source opera-
tor as long as you are not on source property; however, telephoto lenses may
be prohibited. If the boiler stack appears to be out of compliance and you
Industrial Boiler Inspection Guide General Inspection Procedures
10/81 2-2
-------
can position yourself properly to do so, make an opacity reading and photo-
graph the stack before you enter the plant.
Always carry a hardhat and safety glasses with sideshields into the plant
with you. Ear plugs, goggles, and steel-toed safety shoes are also recom-
mended; some companies require them. You are responsible for providing this
common safety equipment, and if you do not have it with you, the plant may
rightfully refuse or delay your entry.
Follow safety procedures during the inspection.
0 Do not touch pipes, valves, or ducts; they may be hot.
0 Do not enter roped-off areas.
0 Do not start up a ladder until the person ahead of you has
reached a landing.
0 Do not lean on platform guardrails; they may not be secure.
0 Be aware of and obey warning signs.
These are not the only safety rules you need to know. Some plants that
have unique hazards, such as toxic gases, will require you to carry a mask
during your inspection. Be sure you understand how and when to use it. Be
especially careful if construction is in progress; you may encounter trip
hazards, temporary platforms, and danger from falling objects. Always be
mindful of your footing, your balance, and what is above you.
2.2.2 Plant Inspection
When you arrive at the plant, introduce yourself and contact a responsi-
ble official to request access to the boiler and boiler operating records. If
requested, provide proper agency identification. This should include a photo-
graph and/or a physical description. Unless your agency instructs you other-
wise, do not sign any forms that limit the plant's liability for your safety
or restrict the scope of your inspection.
Interview the plant manager or some other responsible official(s) prior
to the in-plant inspection. Some of the points for discussion are:
1. The purpose of the inspection.
2. The type of measurements to be made.
3. Any samples to be acquired.
Industrial Boiler Inspection Guide General Inspection Procedures
10/81 2-3
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4. The systems to be evaluated.
5. Changes in plant management (to be noted in the agency file).
6. Process flow sheets to confirm current operational conditions.
7. Operating records required by applicable New Source Perform-
ance Standards (NSPS) and/or for determination of operating
conditions specified in permits.
8. Checklist items that can be filled out during this interview.
Review applicable regulatory requirements carefully, and discuss specific
applicability to the source in question. Also, be prepared to discuss the
following:
1. Authority for the inspection.
2. Agency organization.
3. Scope, timing, and organization of the inspection (preferred
inspection agenda).
4. Treatment of confidential data.
Ask plant officials about the operational status of equipment within the
scope of the inspection. Document the source of all the information collected
during the inspection; for example, did you get the boiler operating rate
verbally or read it from the control board? If equipment is not operating at
or near normal conditions, note the reasons why; also note when units will be
operating normally to aid in scheduling followup inspections. Any information
the source considers to be confidential should be so marked.
If the plant denies you entry to all or part of the facility within the
scope of the inspection, note reasons for refusal, the name and title of the
plant official responsible for the refusal, and the precise time of the refus-
al. Notify your supervisor by telephone immediately, but never attempt to
summarize potential legal consequences of the company's refusal to allow you
entry.
Finally, write a report to document your inspection. The report will
document any violations and will also provide baseline data for future inspec-
tions. Unless agency policy dictates otherwise, do not make any comments
about source compliance. List the data you collected along with applicable
Industrial Boiler Inspection Guide General Inspection Procedures
10/81 2-4
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regulations. There is no benefit in drawing conclusions about compliance in
the report, and an incorrect conclusion could damage your agency's position if
legal action is taken.
A sample inspection report is shown in Appendix B.
Industrial Boiler Inspection Guide General Inspection Procedures
10/81 2-5
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SECTION 3
CONTROL EQUIPMENT INSPECTION
This chapter outlines a typical control equipment inspection at a hypo-
thetical plant. The inspection procedure is keyed to several checklists that
are to be filled out during the inspection.
3.1 SOURCE IDENTIFICATION
You must identify the location, ownership, key personnel, and equipment
at the source. The source identification checklist (Figure 3-1) identifies
the facility; the boiler equipment, identification sheet (Figure 3-2) identi-
fies the boiler and control equipment. Usually you can fill out both sheets
during the file review. After you have labeled and identified each boiler,
control device, and emission point at the bottom of the diagram (as shown in
Figure 3-2), you can refer to the equipment and emission points by code num-
bers in the rest of the report.
3.2 INSPECTION PROCEDURE
Begin the boiler inspection at the stack and work back through the con-
trol equipment and boiler to the control room. This counterflow inspection
allows you to determine quickly whether the boiler is in compliance and the
extent of inspection required. If the boiler appears to be out of compliance,
a step-by-step procedure will allow you to determine why the boiler is not in
compliance. An explanation of excessive emissions is important for two rea-
sons.
1. Excessive emissions do not always indicate an emission vio-
lation. Boilers are sometimes permitted to bypass control
equipment during startup and shutdown, or to exceed normal
emission limits during soot blowing or upset conditions.
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-1
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BOILER INSPECTION CHECKLIST
SOURCE IDENTIFICATION
Date(s) of inspection
. 2.0. >98O
Time in 09CO Out / SCO
Company name
Mailing address
rvj
4O1
Si:
eoooo
Location of facility
(Include county)
Type of industry
Form of ownership
Corporate address
Corporate personnel
Responsible for
facility
Responsible for
environmental
matters
Company personnel
contacted
Confidentiality
statement given to
State or local
agency personnel
Name
Title
Phone
/ova) eeo-oooo
•f
f-
Wl .
Figure 3-1. Source identification checklist.
Industrial Boiler Inspection Guide
10/81 3-2
Control Equipment Inspection
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Source name
Inspector
BOILER EQUIPMENT IDENTIFICATION
S-l
FF-1
8-2
O CO
B-i
8-3
FF-1
S-l
ESP
S-i
Date fttnf,
S-2
1
8-3
8-2
S0t 000
8-2 ~~e 8-Z
Figure 3-2. Example of boiler equipment identification form.
Industrial Boiler Inspection Guide
10/81 3-3
Control Equipment Inspection
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2. By identifying an equipment failure that causes an emissions
excursion, you will obtain evidence that can be used in court,
and you will put pressure on the source operator to bring the
source back into compliance quickly. Sometimes the source may
not have been aware of the cause of its problem, and can
readily make the necessary repairs to remedy it.
3.3 STACK OBSERVATION
If it is possible to do so, observe the stack effluent and read the
opacity before entering the plant. Use the visible emission observation form
(Figure 3-3) in this report or one supplied by your agency for this purpose.
Windspeed, sky condition, and other weather data are of legal importance if
the reading is challenged, as is the diagram in the lower left corner of this
form. Take opacity readings for an appropriate duration, depending on your
state's regulations, and record the readings on the form. Although the regu-
lation may require plume opacity to be below a certain average for, say, a
5-minute period, you may want to take an opacity reading for 30 minutes and
look for a 5-minute period that exceeds the limit. If the source has more
than one boiler, be sure to identify the boiler being observed under "Point of
Emission."
If your agency's policy is to provide the source with a copy of the form,
have the person who receives a copy sign and date the original at the lower
right side of the page.
The color of the plume can provide a clue as to the way the boiler is
operating. To a certain extent, it can also identify excess air conditions
and fuel quality. Table 3-1, which was compiled by EPA's Control Programs
Development Division, shows the effect of combustion parameters on plume
appearance.
If the opacity is within limits, proceed directly to the control room and
note the boiler operating conditions. If the boiler is not operating or is
operating at a very low rate, you may want to reschedule the inspection at a
time when the boiler will be operating under more normal conditions. If the
boiler is operating at a normal rate, you may either terminate the inspection
or perform the rest of the inspection to obtain a record of the operating
conditions for later use. A description of normal operating conditions can be
very useful in the future when you are trying to explain a malfunction.
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-4
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SOURCE NAME
ADDRESS
VISIBLE EMISSION OBSERVATION FORM
XV?- /Soc&'L. OBSERVER T. e£*n^J39eZtm.
4*0 / A? <***•» SV,
UfyiAa. . 0 iut«~
DATE ;
/
MINT OF EHISSION S+*cJi S-2 /rvi BoH.
OBSERVATION
POINT tfouvd
V
STACK: DISTANCE FROM
HINDSPEED 5 */»//
^(5 ft HEIGHTS^ ft
DIRECTION iJrttfi,
SKY CONDITION: RjCuJL
COLOR OF EHISSION: 6/uw*»u
RELATIVE HUMIDITY:
BACKGROUND:
BJ£u£. $£*
AMBIENT AIR TEMPERATURE: SP"F ct>t>.
48CF uJ.h.
CERTIFICATION DATE: cWe_ ; I38O
SUMMARY OF AVERAGE OPACITY
Set
Number
1
£.
Time
Start—End
D300-O90B
icoe- locf,
Opacity
Sum Average
3*5 /f.4
190 7.9
Observer x
Sun<> Wind — =» Plume and Stack
rt '
Sou
(
Obse
X^ I
-o-
(valuator's
ao
10
Zo
IS
= T
£f
5
IS
e;
IS
lt>
30
,.f
ID
zs
IS
IS
IS
£
1C
$•
1C
lo
IS~
5
45
/J-
20
IS
10
IB
10
5-
10
S
10
5
S
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
4b
46
47
48
49
50
51
52
53
54
55
56
57
58
59
0
15
30
45
\
I have received a copy of these opacity
readings.
a,, Yfi . 2?7/9b*fc9f c*4~s
r f /
&, Title: £*^f War. Date: ///z«/*e
• 1 T »
Figure 3-3. Example of visible emission observation form.
Control Equipment Inspection
Industrial Boiler Inspection Guide
10/81
3-5
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TABLE 3-1. PLUME CHARACTERISTICS AND COMBUSTION PARAMETERS.
Plume color
Possible operating parameters to investigate
White
Gray
Black
Reddish brown
Bluish white
Excess combustion air; loss of burner flame
in oil-fired furnace
Inadequate air supply or distribution; high
hydrocarbon emissions
Lack of air; clogged or dirty burners or
insufficient atomizing pressure; improper
oil preheat; improper size of coal
Excess furnace temperatures or excess air;
burner configuration; high NO emissions
K
High sulfur content in fuel; high SO emis-
sions
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3-6
Control Equipment Inspection
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3.4 FAN INSPECTION
Boiler control equipment restricts the flow of air from the boiler. This
restriction is overcome by an induced-draft fan between the boiler and the
stack. To evaluate the fan, you need baseline fan and control equipment data
(taken during a period of good operating conditions).
Comparing the fan data sheet (Figure 3-4) with the baseline data sheet
will indicate whether the air flow rate through the control device has
changed. Unless you have a fan curve from the manufacturer and are aware of
fan speed and the pressure drop across the fan, actual flow cannot easily be
determined; however, changes from the base case will indicate changes in flow.
An increase in flow indicates that the equipment is operating at a higher
than normal rate or air is leaking into the system. Either condition could
mean that the control equipment is being overloaded. Such overloads lead to
reduced bag life in fabric filters and increased emissions from electrostatic
precipitators. Any of the following may indicate that the system flow has
increased from the baseline condition:
1. Increased motor current.
2. Lower differential pressure across the fan.
3. A more open damper setting.
Mechanical problems such as vibration or loose belts can impair air flow
®
and lead to system failure. You can use a Magnehelic gage to check fan pres-
sure drop if pressure taps are available on each side of the fan. Use an
induction ammeter to determine current flow and a tachometer to measure fan
speed.
3.4.1 F-Factor
Sometimes you will not be able to get a fan curve or other necessary data
to determine the flue gas flow rate from the fan. Since the flow rate is very
important in evaluating most control equipment, the F-factor method was devel-
oped to estimate this flow.
The dry and wet basis F-factors for coal and oil are shown in Table 3-2.
These factors were determined by statistical studies of many fuel samples and
are generally accurate to within 4 percent. Application to a specific boiler
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-7
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FAN DATA SHEET
Source name X
Inspector
1. FAN MOTOR
Manufacturer
Model No.
303
Rated horsepower 4-O
Volts Z3Q/MO
1175
Maximum rpm
Operating current: Panel
2. DRIVE
Direct
Belt
Pulley reduction
Audible belt slippage: Yes
3. FAN
Manufacturer /ymx
Model No.
Fan vibration
Gas temperature at inlet, °F
Fan rpm 1115
Fan static pressures: Inlet _
Differential static pressures:
Fan housing condition
Dampers
Fan exit
Gas flow from fan curve
Date fW. 20
Fan No. Fa*n m
Type
TIKK
Maximum amps _
Service factor
Other
/OS/SI
Other
No
Service
J-. D.
Measured
Outlet
Panel
Figure 3-4. Example of fan data sheet.
Industrial Boiler Inspection Guide
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Control Equipment Inspection
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TABLE 3-2. F-FACTORS FOR VARIOUS FUELS.'
Fuel type
Coal
Anthracite .
Bituminuous
Lignite
Oil
Gas
Natural
Propane
Butane
Wood
Wood Bark
Fd
DSCF
106 Btu
10,140
9,820
9,900
9,220
8,740
8,740
8,740
9,280
9,640
Fw
WSCF
10b Btu
10,580
10,680
12,000
10,360
10,650
10,240
10,430
-6
-e
These factors are taken from Appendix C of Continuous Air Pollution Source
Monitoring Systems, EPA 625/6-79-005.
DDSCF stands for dry standard cubic feet.
"WSCF stands for wet standard cubic feet.
Use the bituminous coal figures for sub-bituminous coal in the absence of
other data.
*The moisture content of wood is so variable that the moisture of the wood
being burned must be measured to determine the moisture correction factor.
Industrial Boiler Inspection Guide
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3-9
Control Equipment Inspection
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requires corrections for excess air (flue gas oxygen content), pressure, and
temperature of the flue gas.
Excess air (air beyond the minimum amount required for combustion) is
used in all boilers to insure that there is sufficient oxygen to burn all the
fuel. Boiler and ductwork leaks add additional air (and oxygen) to the flue
gas. The flue gas oxygen content must be known to account for this excess air
in the flue gas. This method requires a determination of oxygen on a dry
basis, which is the way most boiler oxygen meters operate. Figure 3-5 shows
an oxygen meter in a boiler control room.
A temperature correction is necessary because gas volume (and flow)
increase as temperature increases. Gas volume also increases as the pressure
decreases. Pressure differences occur because of differences in elevation
above sea level. If two identical boilers are fired, one at sea level and one
at an elevation of 3000 ft, the boiler at 3000 ft will have a 10 percent
greater flue gas flow rate.
The equation for calculating flue gas flow rate and a definition of the
terms is given below.
= - FF f _ ' ) + (F - F )1 r 1 f 1
60 Lhd 120.9 - 0; C w VJ L 530 J L30770 - AJ
where ACFM = Flue gas flow rate in actual cubic feet per minute.
H = The boiler fuel firing rate in million Btu's per hour.
This can be calculated from the fuel consumption rate and
the heat content of the fuel.
F . = The dry basis F-factor from Table 3-2 for the fuel being
fired. If more than one fuel is being fired a weighted
average F-factor can be used.
02 = The flue gas oxygen content in percent on a dry basis.
This can be read on the oxygen meter if the boiler has
one.
F = The wet basis F-factor from Table 3-2 for the fuel being
fired.
T = The flue gas temperature at the control device in degrees
fahrenheit. This is usually monitored in the boiler
control room.
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10/81 3-10
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Figure 3-5. Photograph of an oxygen meter
on a boiler control board.
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Control Equipment Inspection
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A = Altitude above sea level in feet. If this isn't known
set A equal to zero. The equation is valid to a maximum
altitude of 10,000 ft.
As an example, find the flue gas flow rate of a boiler at 1500 ft above
sea level firing 40,000 Ib/h of bituminous coal with a heating value of 12,000
Btu/h. The control room oxygen meter shows an oxygen level of 6 percent after
the air preheater (the closest point to the control device that is monitored)
and the gas temperature is 380°F. The F-factors come from Table 3-2.
The heat input is calculated first:
40,000 Ib/h x 12,000 Btu/lb = 480 x 106 Btu/h
The flue gas flow rate is:
AfFM - 48° rqft?n ( 20'9 1 + no fiftfl - q fi?rm f380 + 460. r 30770 n
ACFM " "60 [982° (20.9 - 6} no>680 9.820)] ( ^ ) L30770 . 150gJ
= 195,000 acfm.
This number is only an estimate, but you will find it very useful when
evaluating the control devices described later.
3.5 CONTROL EQUIPMENT
Boiler pollution control equipment may consist of a fabric filter, an
electrostatic precipitator (ESP), a cyclone, or a venturi scrubber. Some
boilers (especially gas-fired units) have no control equipment. Each collec-
tor is discussed separately.
3.6 FABRIC FILTER
3.6.1 External Inspection
Excessive emissions usually indicate either that some bags are defective
or missing or that the fabric filter is being bypassed. Emissions will in-
crease somewhat immediately after a compartment has been cleaned, but they
should decline steadily once the compartment is back on line.
Figure 3-6 is an example of a fabric filter data sheet. As indicated,
you should sketch the layout of the compartments and duct work on the bottom
of this sheet and indicate the orientation of the various components. Be sure
to label the fabric filter so that you can refer to individual compartments
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-12
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Source name
Inspector
FABRIC FILTER DESCRIPTION
Date
20} 81
AC. G
Fabric filter No.
FF-1
Date Installed
1915
Manufacturer (J> 5,
Cs>.
Total filter area, ft
,OOO
Air/cloth ratio: Net 2,
Lua*
Gas flow, acfm #f% OOO
Gross 2.0
Cleaning system: Type
Cleaning frequency
Operating temperature
Comments
Pressure drop before cleaning
Cleaning controlled by AP
3BO'F
3 I
u).
Time & /irs
CM/Vl&nt~
•fagf ~™c 'oa<3f
SKETCH THE FABRIC FILTER AND LABEL THE COMPARTMENTS
FROM
0-1 o~et B-
t f
t I
JT
r L°
e
e
c
f
\ ^
Figure 3-6. Example of fabric filter description data sheet.
Control Equipment Inspection
Industrial Boiler Inspection Guide
10/81
3-13
-------
later. It is usually convenient to use the plant's designation for each
compartment. Other information that is entered on this data sheet can help
you determine the overall condition of the unit. In general, high air/cloth
ratios reduce fabric filter life and increase dust penetration. The current
trend is to use reverse-air cleaning systems and air/cloth ratios of 2.0 cfm
per square foot. Typical bag life on such systems appears to be 3 to 4 years.
Sometimes fly ash will blind the filter fabric over a period of months or
years. Overcoming this problem may necessitate an increased cleaning frequen-
cy. Immediately after each cleaning the pressure drop will return to its
minimum value, and the pressure drop will increase slowly as fly ash accumu-
lates on the fabric until the unit is cleaned again.
Begin the fabric filter inspection by checking each individual compart-
ment. A typical system has walkways and access doors to the fabric filter at
two levels. Each compartment or group of compartments driven by a common fan
should have a differential pressure gage or manometer with which to measure
the static pressure on the clean side and the dirty side and the differential
pressure across the bag. Note that the pressure drop should be the same on
all compartments using the same fan.
Figure 3-7 is a photograph of a fabric filter taken from the walkway at
the tube sheet level. This photograph also shows a higher walkway, which
provides access to the tops of the bags. The access doors and the pressure
gages (mounted to the left of each door) are also clearly visible. Figure 3-8
shows the fabric filter internals and the pressure gage.
The checklist in Figure 3-9 should be used during your inspection. At
each compartment, measure the clean-side, dirty-side, and overall pressure
drop across the filter. Figure 3-10 shows a pressure gage measuring the
pressure drop across the filter during normal service. Figure 3-11 shows the
gage when the clean-side pressure tap is vented; the gage shows static pres-
sure on the dirty side. If the unit is operating; the pressure on the dirty
side will always be higher than that on the clean-side.
If possible, disconnect the plant gages and check the lines with a porta-
ble differential pressure gage. Obtain permission from a plant representative
before you do this. If several of the permanent gages are defective, suggest
that the plant install proper connections for easy attachment of a portable
gage during future checks. A plugged line on the dirty side of a compartment
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-14
-------
Figure 3-7. Photograph of fabric filter, showing upper and lower
catwalk, compartment access doors, and Magnehelic gages.
Industrial Boiler Inspection Guide
10/81
3-15
Control Equipment Inspection
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BAG TENSION SPRINGS
BAG CAPS
TUBESHEET »-"LTJ"Lru-H
PRESSURE
GAGE
ASH HOPPER
Figure 3-8. Cross section of fabric filter, showing
filter internals and a pressure gage.
Industrial Boiler Inspection Guide
10/81 3-16
Control Equipment Inspection
-------
FABRIC FILTER COMPARTMENT EXTERNAL INSPECTION
Source name XVZ ^
Inspector
Date nsv. 2.0j 198O
Fabric filter No. FF-1
1. Static pressure (inches W.G.)
Compartment
A
e
c.
D
e
F
Plant's instruments
Clean
side
-3
-
-------
Figure 3-10. Photograph of a Magnehelic gage measuring
overall pressure drop of fabric filter during normal service.
Industrial Boiler Inspection Guide
10/81
3-18
Control Equipment Inspection
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Figure 3-11. Photograph of a Magnehelic gage measuring the static
pressure of the dirty side of a fabric filter. The clean
side tap is vented to the atmosphere.
Industrial Boiler Inspection Guide
10/81
3-19
Control Equipment Inspection
-------
is a common problem. The static pressure of a plugged line will read zero
after it has been vented, and it should be repaired.
At the end of this check you should be able to identify any defective
gages and the pressure drop across the filter system. The results in the
example shown in Figure 3-9 indicate that gages on Compartments C and E are
defective because their readings differ considerably from the inspector's test
gage. The zero-pressure drop for Compartment D suggests that the compartment
is isolated.
Listen and feel for air leaks into the filter system. Leaks usually
occur around the access doors or at joints in the ductwork. Check the con-
dition of the door gaskets. Air leaks cause localized cooling that can, in
turn, cause condensation and corrosion of internal parts.
The isolation check is also shown in Figure 3-9. To perform this check,
have the operator isolate each compartment, one at a time, and read the opa-
city for at least 5 minutes after each isolation. Use the plant's opacity
meter, if one is available. At some well-instrumented installations each
compartment will have its own opacity monitor, and the isolation of individual
compartments will not be necessary. If the filter system has an automatic
cleaning cycle, this must be locked out during the test so that only one
compartment is isolated at a time.
If opacity decreases when a particular compartment is isolated, inspect
the compartment internally to determine the problem. In many installations it
is impossible to isolate a compartment and enter it when the unit is on line.
Be sure to follow all plant safety procedures, and have someone from the plant
accompany you when you enter a compartment.
3.6.2 Internal Inspection
An internal inspection can clearly pinpoint the cause of a malfunction by
revealing that bags are torn or missing. Certain safety precautions should be
observed to guard against heat, toxic gases, and low oxygen levels. Always
work closely with the plant personnel, and be sure that a plant representative
accompanies you on any internal inspection. Ask for and follow plant safety
procedures.
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-20
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If the boiler is not operating, make sure the fabric filter compartment
has been vented and cooled. This is the safest condition for conducting the
inspection.
In rare situations a compartment can be entered while the fabric filter
is operating. Make sure the compartment is locked out and that the boiler
operator knows you are planning to enter it. Enter the compartment slowly and
be prepared to leave immediately if heat seems excessive or if you detect any
sulfurous odor, which indicates leaks in the valves isolating the compartment.
If necessary, wear a dust mask to prevent inhaling fly ash. If you have any
doubt about the safety of entering the compartment, stay out.
When you enter a compartment, always have a second person wait outside.
Compartment doors cannot be opened from the inside, and you would be trapped
if the door should close. If there is any question about the air quality
inside, use an oxygen supply or stay out.
An excessive accumulation of ash on the clean side is the most obvious
sign of trouble in a fabric filter. You should make an internal inspection
before anyone else enters the compartment and disturbs the ash accumulations.
Filter bags usually fail at the bottom where the bag attaches to the tube
sheet, and fly ash may accumulate around torn bags. The bags should be dry.
Check them for the presence of oil, which may have dripped on the filters from
the shaker mechanism, or for dampness, which may have resulted from a section
of the fabric filter running below dewpoint.
Any air leaks into the compartment can cause local condensation and
corrosion. Check around doors, and note the condition of the door gasket.
Check the hopper for incomplete solids removal and corrosion.
Hopper problems are a common cause of fabric filter failure. A bridged
or plugged hopper will fill up with fly ash and restrict the gas flow in a
compartment until that compartment becomes useless. Hoppers usually have an
access hatch for inspection. Only plant personnel should open hopper doors.
Be especially careful; if the hopper is full, you could be buried in fly ash.
Fly ash in the hopper will harden if exposed to water. Condensation and
hopper plugging can result from hopper heater failure, air leaks in the hopper
walls, or leakage through the hopper di.scharge valve.
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-21
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3.7 ELECTROSTATIC PRECIPITATORS
The electrostatic precipitator (ESP) is the most complex of the control
systems discussed in this report. As shown in Figure 3-12, ESP's contain
alternating rows of plates and wires. A high voltage field within the ESP
charges fly ash particles as they pass through the ESP system and attracts the
particles to the plates, where they collect. (This is the same type of at-
traction that pulls hair to a comb or brush on a dry day.)
A transformer rectifier (TR) set produces the high voltage in an ESP.
The TR set converts the plant voltage (normally 220 or 460 V a.c.) to 30,000
to 60,000 V d.c. Each TR set (and the wires and plates connected to it) forms
one field, and the typical ESP has three or more fields. Figure 3-12 is a
simplified schematic of an ESP. The first field removes 50 to 75 percent of
the fly ash entering an ESP, and each of the additional fields removes a
portion of the remaining fly ash.
3.7.1 External Inspection
Figure 3-13 is an example of an ESP description data sheet for a hypothe-
tical ESP system. A comparison of the sample information with design data or
past operating data indicates a change in ESP efficiency. (The amount of the
change can be estimated by using a power calculation, shown later.) Sketch
the ESP at the bottom of the data sheet; show each field, the direction of the
gas flow, and the location of the ESP relative to the boiler and stack.
Three variables tend to affect the ESP efficency. They are:
1. Specific Collection Area. The specific collection area (SCA)
usually ranges from 200 to 800 square feet per 1000 actual
cubic feet per minute (acfm). To determine the SCA in square
feet per 1000 acfm, divide the actual cubic feet per minute of
gas flow into the square feet of the plate area and multiply
by 1000. An increase in the SCA increases the efficiency of
the ESP. Operating the ESP equipment at gas flows above the
design rate will reduce the SCA and the efficiency.
2. Temperature. Gas temperature also affects the efficiency of
an ESP. Hot-side ESP's, which operate at 600° to 700°F, are
not as sensitive to temperature changes as cold-side ESP's,
which operate at 300° to 400°F. A gas temperature decrease of
15° to 20°F can cause a noticeable reduction in the efficiency
of a cold-side ESP.
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-22
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FROM PLANT
POWER SUPPLY
PRIMARY CURRENT
220 OR 460 VOLTS
ALTERNATING CURRENT
SECONDARY CURRENT
30,000 TO 50,000 VOLTS
DIRECT CURRENT
RECORD VOLTS AND AMPS
•RECORD KILOVOLTS AND MILLIAMPERES
Figure 3-12. Diagram of electrostatic precipitator, showing one field
and one TR set. Additional fields are normally used. Each has its own
TR set and each is electrically independent.
Industrial Boiler Inspection Guide
10/81 3-23
Control Equipment Inspection
-------
ESP DESCRIPTION
Source name XY2 eJhJLdbuz*, Date /Inf. 20. 738O
Inspector _f£. r^^n^i^, ESP No. «P-2
Date Installed
aji
Manufacturer U.S. €SP C*.
Total ft plate area
Gas flow, acfm
Design
Actual 45o.
Actual 4*£ 7
SCA, ft'/lOOO acfm Design _
Temperature, °F Design 32QV Actual
Coal sulfur content, % Design i.Q *?• Actual Q.7 /o
Face velocity, ft/m Design "2.^0 **/*! Actual
SKETCH THE ESP AND LABEL THE FIELDS (TR SET).
N
9-f* H-rft 3ft
8-3
t
T
V
^/5 TACK.
5-Z
TK-l
Figure 3-13. Example of ESP description data sheet.
Industrial Boiler Inspection Guide
10/81 3-24
Control Equipment Inspection
-------
3. Coal sulfur content. ESP efficiency generally increases with
the sulfur content of the coal burned in the boiler. This is
especially true when the sulfur content is less than 1 per-
cent.
Figure 3-14 will serve as a rough guide for estimating the effect of changes
in SCA and coal sulfur content on the efficiency of a cold-side ESP; however,
it should not be used for estimating an absolute efficiency.
Check the ESP control system thoroughly. Control panels usually include
primary and secondary current and voltage meters and a spark rate meter.
Record the voltage, amperage, and spark rate for each section, as shown in
Figure 3-15. It is not unusual for the spark rate meter to be out of order.
The other gages on the control panel will jump when the field sparks. When
the spark meter is not operating, you can determine the spark rate by counting
the number of times these meters oscillate in 30 seconds and multiplying by 2.
You should compare the control room readings with calibrated or design values
for each section. If a daily log is kept, check it to determine whether
readings are representative. Data drift indicates such problems as air in-
leakage at air heaters or in ducts leading to the ESP, fly ash buildup on ESP
internals, and/or deterioration of electronic components. Also note inopera-
tive meters, the number of power supplies on manual control, and power sup-
plies on automatic control that are set for operating voltages below design
specifications (such as might be done to reduce wire breakage.) Record all of
the information that is called for on the ESP electrical data checklist (Fig-
ure 3-15).
Table 3-3 lists some common operating problems and how they affect ESP
electrical parameters. Figures 3-16a and 3-16b show ESP collection efficiency
as a function of power consumption. You can use these curves to obtain a rough
estimate of efficiency, but keep in mind the extreme variations and the lack
of data at high efficiencies (>98 percent).
In general, the corona voltage should be 35 kV or higher, the secondary
current (milliamperes) should increase or stay constant as you move from the
inlet to the outlet of the ESP, and the spark rate should be about 10 sparks
per minute.
From the data presented earlier in Figure 3-13, you can draw the fol-
lowing conclusions:
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-25
-------
o
o
CM
700
600
500
400
300
200
100
99.9
99.5
99.0
1.0 2.0
SULFUR IN COAL. %
3.0
4.0
Figure 3-14. General relationship between SCA and
sulfur content for a cold-side ESP operating at 300°F.
Industrial Boiler Inspection Guide
10/81
3-26
Control Equipment Inspection
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O 3
^ Q.
00 C
M VI
r+
-J
^*
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00
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<-»•
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o
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ESP ELECTRICAL DATA
Location
BotigK.
0-3
TR set
No.
±
2
3
Primary
voltage, V
Present
420
4ZO
420
Base
4ZO
480
480
Primary
current A
Present
75
230
230
Base
75
2.38
238
Secondary
Voltage, kV
Present
50
4$
45
Base
So
So
So
Secondary
current, MA
Present
4*o
$00
600
Base
4co
Goo
800
Spark rate,
sparks/ml n
Present
7
3
3
Base
10
6
2
re
o
Figure 3-15. Example of ESP electrical data checklist.
-------
O 3
CD C
l-i in
TABLE 3-3. CHANGES FROM NORMAL ESP OPERATION.
f
QJ
as
o
-j
i— i
tn
\o
O
O
C
I-J
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n>
o
o
3
O
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JO
c
-a'
3
(D
Cl'
3
•o
*-»
Primary
voltage,
V, a.c.
300
260
350
300-350
280
180
0-300
0
330
265
Primary
current,
A, a.c.
50
55
40
50-60
52
85
0-50
100+
50
50
Secondary
current,
mA, d.c.
200
230
175
20-250
210
300
0-200
0
200
200
Condition
Normal full load
System load off by 1/2
System load constant, but
increase in dust load
Gas temperature increases
Gas temperature decreases
ESP hopper fills with dust
Discharge electrode breaks
Transformer- rectifier
shorts
Rapper on discharge system
fails
Rapper on collection plate
Effect
--
Gas volume and dust concentration decrease;
efficiency increases because of reduced
gas velocity.
Efficiency increases.
Efficiency rises; sparking increases
because of increased resistivity.
Efficiency decreases.
Efficiency decreases.
Efficiency may fall to 0 (may vary between 0
and normal if top part of electrode is left
swinging inside the ESP). Instrument fluc-
tuates violently. Arcing can be heard out-
side the ESP.
No current passes from TR set to the ESP.
Efficiency falls to zero.
Dust builds up on discharge electrodes.
Resistance increases because corona dis-
charge decreases. Additional voltage is
required to keep current constant.
Sparking increases. Voltage must be re-
duced to keep current constant.
U)
ro
oo
-------
THEORETICAL CURVE _
FOR k = 0.55
25 50 75 100 125 150
CORONA POWER, watts/1000 acfm
Figure 3-16a. Relationship between collection efficiency and specific
corona power for fly ash precipitators; based on field test data.
^99.9
§ 99.8
fc 99
S-99.5
6 "
£ 98
~ 95
U-
uj 90
o 80
P 70
a 50
o
o
0 100 200 300 400 500 600
CORONA POWER, watts/1000 acfm
Figure 3-16b. Efficiency versus specific corona power extended
to high collection efficiencies; based on test data
on recently installed precipitators.
Industrial Boiler Inspection Guide
10/81
3-29
Control Equipment Inspection
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1. The gas flow through the ESP is lower than the design rate.
This results in an increase in the SCA and tends to increase
the unit efficiency.
2. The operating temperature is below the design temperature.
This tends to reduce the overall efficiency of the unit.
3. The 0.7 percent sulfur content of the coal is less than the
design value of 1.0 percent. This tends to have an adverse
effect on the efficiency of the unit.
Because the relative effects of these three factors are difficult to
estimate, you cannot readily determine if the overall effect is beneficial or
detrimental. From the sample electrical data in Figure 3-15, however, you can
conclude the following:
1. The ESP secondary current increases from inlet to outlet; all
fields appear to be operating.
2. The design and operating power per 1000 acfm (sometimes called
corona power) can be calculated from the data in Figures 3-13
and 3-15. The power in watts, supplied by each TR set, is
calculated by multiplying the kilovolts (kV) by the milliamps
(mA) of each TR set shown in Figure 3-15. The total power is
the sum of the power of the three TR sets. Figure 3-13 shows
the airflow to be 500,000 acfm; so dividing the total power by
500 yields the power per 1000 acfm:
Design = <50><400> + (50^°°> * ^50^80°) = 180 watts/1000 acfm
Operating = (50)(400) + (45)(500) + (45)(600) = ]54 watts/1000 acfm
Based on the curve in Figure 3-15b, this decrease in power reduces estimated
efficiency from 99.50 to 99.25 percent, which results in a 50 percent increase
in emissions from the unit (0.75 percent instead of 0.50 percent of the inlet
fly ash particulates).
The spark rate usually limits the secondary voltage. As voltage in-
creases both ESP efficiency and spark rate increase until excessive sparking
overrides efficiency gains from the higher voltage. A spark is a short cir-
cuit that causes a momentary voltage drop and loss of efficiency. Over 20
sparks per minute is excessive, and the efficiency of a unit that isn't spark-
ing can be increased by increasing the voltage.
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-30
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Spark rate decreases in each field as you move from the dirty to the
clean gas side of the ESP. This is because most of the fly ash is removed in
the first field, and the heavy fly ash concentration promotes sparking. The
spark rates shown in Figure 3-15 are low enough to indicate that the voltage
could be increased, especially in the last two fields.
If the plant is in violation of opacity or mass emission regulations, a
solution to the problem might be:
1. To increase the voltage in the last two ESP fields to the
design rate of 50 kV.
2. To increase the temperature of the gas into the ESP to the
design level of 320°F.
Rapper/Vibrator Inspection—
Mechanical, electrical, or air operated rappers or vibrators periodically
remove accumulated fly ash by shaking the plates and wires. These are re-
ferred to simply as rappers throughout the rest of this discussion. Rappers
can be located on the top and/or side of the ESP. They operate on a timed
cycle, and you should be able to hear them turn on and off. Obtain a diagram
of the rapping system sequence from the plant personnel, and verify that all
rappers are operating. Irregular sounds from an individual rapper indicate
that it either is operating improperly or is broken. Check rapping intensity
and frequency against design and past performance. The rapping intensity of
electric rappers is usually indicated by volts or amps; the rapping intensity
of air-operated rappers is indicated by air pressure. In general, an increase
in either intensity or frequency of the rapping will result in increased emis-
sions because dislodged fly ash can become reentrained in the flue gas and be
carried out the stack. On the other hand, insufficient rapping can allow
solids to build up on the plates, which reduces ESP efficiency.
3.7.2 Internal Inspection
The ESP can be entered only if the control device is not being used.
Unlike fabric filters, sections of an ESP cannot be isolated and bypassed.
Before entering the ESP, be sure the electrical supply is locked out, and
follow all of the safety procedures for entering a fabric filter described in
Section 3.6.2.
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-31
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Look for missing wires. A row of wires should be between each row of
plates in a regular pattern. Missing wires reduce efficiency. Check for
warped plates, especially in large ESP's. A warped plate that is closer than
usual to a wire can cause premature sparking that reduces the voltage in the
entire field. Look for signs for corrosion, especially around the doors.
Corrosion around joints usually indicates that air leaks are causing localized
cooling and condensation. General corrosion of the ESP internals indicates
that the unit has been operated at low gas temperatures (below the sulfuric
acid dew point).
More than 1/4 inch of ash coating on wires or plates probably means that
the internals are not being rapped enough. An ash coating will insulate the
wires and plates and reduce efficiency.
Suspension insulators, which support and isolate the high-voltage parts
of an ESP, are housed in a plenum (called the penthouse or top housing) on top
of the ESP that is fan-pressurized with filtered air to prevent ash from
leaking out of the ESP onto the insulators. Ash accumulations can cause
arcing and may short the wires or plates to the ESP housing. Check to see if
the ventilation fan is running, and note the condition of the filters. If the
boiler is down, inspect the insulators for ash deposits and signs of arcing.
Make sure the ESP is deenergized before entering the top housing. Figure 3-17
is an ESP inspection checklist for the rappers and the top housing.
3.8 VENTURI SCRUBBERS
Venturi scrubbers wet the fly ash and capture it in a water stream.
Figure 3-18 is a flow diagram of a typical venturi scrubber. Ash-laden air
enters the scrubber and accelerates to a high velocity in the venturi throat.
Gas velocities in the throat section vary from 100 to 500 ft per second, and
gas pressure drops are from 10 to 30 inches of water. Typical water flow in
this system is 2 to 5 gal/min per 1000 acfm.
Water can be injected into the top of the venturi, as shown in Fig-
ure 3-18, or directly into the throat. The high-velocity gas stream in the
throat atomizes the liquid and maximizes contact between the dust particles
and the water droplets. The water droplets themselves collide and agglomerate
in the divergent section of the venturi. A 90 degree elbow at the venturi
Industrial Boiler Inspection Guide Control Equipment Inspection
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EXTERNAL ESP INSPECTION
Source name XV£
Inspector c^.
Rappers
Rapper location: Top
Rapper type: Air
Date flfir, 24. I3&0
ESP No. ESP- .2
side yes
Electrical
Rapping frequency: TR No. 1 £ *»&*, .
TR No. 3 l
Mechanical
TR No. 2 5
TR No. 4
Top housing condition £Sf
tq -
Insulator condition ESP
-
*)>*<** ^4-6-0—
Fan and purge-air filter condition F^LfLfc*. LA
£K
Comments
Figure 3-17. Example of external ESP inspection form.
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3-33
Control Equipment Inspection
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O =3
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CONTAMINATED
FLUE GAS
I
U>
CONVERGENT
SECTION
VENTURI
THROAT
DIVERGENT
SECTION
DIRECTIONAL
CHANGE IN
ELBOW CAUSES
ADDITIONAL
IMPACTION AND
DROPLET
AGGLOMERATION
SCRUBBING
-WATER SPRAYS
INTO VENTURI.
FLY ASH PARTICLES
AND GAS IN
> TURBULENT
1IXING SECTION
TO
SEPARATOR
WATER IS SPRAYED
INTO VENTURI
INLET AND WETS
ASH PARTICLES.
DETAIL OF VENTURI
VENTURI THROAT
o
o
o
JO
C
(D
CLEAN WATER RETURNS
TO VENTURI
SETTLING POND
WATER/AIR
SEPARATION
CHAMBER
CLEAN GAS
OUT
WATER/ASH
SLURRY FLOWS
BY GRAVITY
TO THE
SETTLING POND.
v>
TJ
tt>
n
Figure 3-18. Flow diagram of a typical venturi scrubber system.
-------
outlet causes particles to impinge on the wet surface for further particle
removal and liquid agglomeration. The wet exhaust air then enters a cyclone
or baffle separator, where the liquid separates from the gas by centrifugal
force or impaction and drains out the bottom of the separator. The clean gas
discharges at the top of the separator.
Venturi efficiency can be adjusted by increasing or decreasing the liquid
flow rate. Also, some Venturis have adjustable throats to accommodate vari-
able gas flows. The collection efficiency of a venturi scrubber increases
with energy consumption.
3.8.1 External Inspection
To evaluate venturi scrubber performance, first confirm water circulation
through the system. Figure 3-19 is an example of a data sheet for describing
the venturi scrubber. Sketch the scrubber system on the form and identify the
orientation of the various system components. The additional information
called for on this form will help you to determine the overall condition of
the unit. In general, low pump pressure indicates erosion of the nozzles
and/or the pump impeller, which results in an increase in the water spray
droplet size and a reduction in particle collection efficiency. Baseline data
are very useful when evaluating a venturi.
Venturi scrubbers are usually not used for particulate control on coal-
fired boilers because the sulfur in the coal forms sulfuric acid in the water.
If the pH of the water falls below 6, the acid will attack carbon steel. The
pH is easily measured with pH paper. Scrubbers are sometimes used on wood- or
bark-fired boilers. Caustic is sometimes added to the water to control pH.
If the recirculation water is not settled or otherwise cleaned properly,
solids in the water can erode or plug the nozzles. The water can also get so
dirty that it will not effectively collect additional solids.
3.8.2 Internal Inspection
During the internal inspection, check the spray nozzles for scaling,
corrosion, or erosion. Venturi internals are susceptible to corrosion, espe-
cially around welds and at the bottom of the skirt that forms the venturi
cone. Turbulent conditions in the venturi zone accelerate venturi skirt
corrosion by removing the particulate buildup and thereby exposing fresh metal
to continuous attack.
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-35
-------
Source name
Inspector _
VENTUR1 SCRUBBER DESCRIPTION
rJ^JL^uS^ Date n/nr. 2.0. I38&
Scrubber No. \1-J-
Type of scrubber
Manufacturer _ U.S.
Installation date 1312.
Gas flow, acfm
Gas temperature, °F
Pressure drop across the scrubber, in. water
Liquid flow, gal/min
Nozzle pressure, psi
Liquid pH
Comments
Design
40,000
3SQ'f
Actual
IZQ<
6.5
AZOcL
SKETCH THE VENTURI SCRUBBER
r» ST/»C K.
Figure 3-19. Example of venturi scrubber description data sheet.
Industrial Boiler Inspection Guide
10/81 3-36
Control Equipment Inspection
-------
3.9 CYCLONES
Cyclones are commonly used to control particulate emissions from boilers.
They come in many different sizes and shapes, but the principle of operation
is the same in all units. As shown in Figure 3-20, the cyclone consists of a
cylindrical section on top of a conical section. The dust-laden air enters
the cylindrical section tangentially, and the centrifugal force created by the
air as it spins around in the cyclone pushes the particulate matter to the
wall. Air flows spirally downward through the unit and then upward out of the
unit through the central exhaust. The conical section accelerates the circu-
lating air and increases the centrifugal forces that push the particles to the
wall of the cyclone. The particles then slide down the cyclone wall and
through a valve into a collection chamber. A system consisting of several
smaller cyclones is generally more efficient than a single large cyclone. For
a multiple-cyclone unit to operate at maximum effiency, dust distribution and
the pressure drop across each cyclone must be relatively equal.
3.9.1 External Inspection
Air leaks in the body of the collector or through the bottom valve are
the most common external problems encountered with cyclone collectors. These
leaks create turbulence within the cyclone and cause a net loss in collection
efficiency. Figure 3-21 is an example of a cyclone-description data sheet.
Sketch the cyclone collector on this sheet and show its orientation relative
to the boiler and other equipment. The additional information called for on
this form will help you to determine the overall condition of the collector.
The seal between the collection hopper and the cyclone must be well maintained
to prevent air from leaking into or out of the cyclone. If the ash discharge
valve fails or the collection hopper fills up and blocks the discharge from
the cyclone, material may accumulate inside to the point that the cyclone
ceases to function.
A cyclone system has an optimum gas flow rate at which particulate re-
moval efficiency is highest. Excessive gas flows occur when the boiler load
is very high, and lower air flows occur when the boiler load is low. Well-
designed systems provide for the recycling of boiler stack gases during
periods of low boiler load so as to maintain optimum air velocities in the
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-37
-------
CLEAN AIR
OUT
DIRTY AIR
IN
TOP VIEW OF CYCLONE
CLEAN AIR OUT
OUTLET PIPE EXTENDS
INTO THE CYCLONE
TO PREVENT INLET AIR
FROM SHORT-CIRCUITING
DIRECTLY TO THE OUTLET
c
\
1
1
1
1
it
t:1
•. '• ••.'.
... , :l
'<* ' DTRTY AIR
£ "•-:'. • '• INLET
SLEEVE TO
PREVENT ASH
FROM BLOWING
OUT
THE SPINNING AIR FORCES THE
ASH TO THE WALL OF THE CYCLONE
A SLOW-SPEED MOTOR TURNS
THE "STAR" VALVE THAT SEALS
THE COLLECTION HOPPER FROM
THE CYCLONE
PARTICULATE
COLLECTION
HOPPER
OR DRUM
Figure 3-20. Flow diagram of a dry cyclone collector.
Industrial Boiler Inspection Guide
10/81
3-38
Control Equipment Inspection
-------
CYCLONE DESCRIPTION
Source Name XY2 dh,
Solids discharge rate, characterize T^v^Lwy va£v4. iltji
fuma aZl~
A
T /'O/OI
Comments:
SKETCH THE CYCLONE SYSTEM
f-f>f* -J "/• > /5r/»CK.)
_ •*! 1 ^*^___^/
R0"-f ^ •) 1 1
v -M
i
Figure 3-21. Example of cyclone description data sheet.
Industrial Boiler Inspection Guide
10/81 3-39
Control Equipment Inspection
-------
cyclone. In some multiple-cyclone systems, operators can handle reduced loads
by shutting off one or more banks. You should note this under "Comments."
3.9.2 Internal Inspection
During the internal cyclone inspection, be sure to note plugged or eroded
hoppers . and tubes. Also, look for eroded inlet vanes and hopper short-
circuiting. Call any problems to the attention of the plant representative.
Industrial Boiler Inspection Guide Control Equipment Inspection
10/81 3-40
-------
SECTION 4
BOILER INSPECTION
In the course of your inspections of pollution control equipment you will
find that gas, oil, and coal are three principal boiler fuels. The following
paragraphs briefly describe the characteristics of boilers fired by each of
these fuels.
Gas-fired boilers rarely have significant pollution control problems, and
there should be no visible emissions from the stack. Carbon monoxide and
nitrogen oxides limits for boilers covered by NSPS restrict the range of
allowable operating conditions for these boilers. Generally, you will only be
able to check excess air readings to estimate whether the boilers are running
properly. Most gas-fired boilers are equipped with an oxygen monitor. The
oxygen level at the boiler outlet should be well under 5 percent; if it ex-
ceeds this amount, nitrogen oxides emissions may be excessive. Typical oxygen
levels will be less than 1 percent. For these boilers, you should be able to
obtain steam rates in pounds per hour, steam pressure, and steam temperature.
Fuel consumption rates also may be available.
Most oil-fired boilers use either No. 2 oil or No. 6 oil. The operating
problems of boilers fired with No. 2 oil are not much different from those of
gas-fired boilers. There should be no visible emissions from the stack, and
sulfur dioxide emissions will be very low. The oxygen level in the boiler
exhaust gas will generally be 1 to 2 percent. Any visible particulate matter
indicates unburned carbon and calls for an increase in excess air. You should
be able to obtain a recent fuel analysis showing the sulfur and heat content
of the fuel. Visible emissions from the stack may be a problem on boilers
firing No. 6 oil. The sulfur content of this grade of oil is above 1 percent,
and the vanadium content often causes the further oxidation of sulfur dioxide
to sulfur trioxide, which produces an acid mist plume. Generally this plume
will be white. If the boiler is out of adjustment, however, unburned carbon
may cause a black plume. Because No. 6 oil is heavy and difficult to atomize,
Industrial Boiler Inspection Guide Boiler Inspection
10/81 4-1
-------
it requires preheating and atomization (mechanical, hot air, or steam). In
many installations, oil burners must be cleaned at least once per shift. If
you note a plume opacity problem, determine when the burners were last
cleaned. These boilers are also equipped with soot blowers, and special
provisions in the regulations may allow some opacity excursions during soot-
blowing operations. Opacity excursions may also occur during startup and
shutdown.
Coal-fired boilers include hand-fired, stoker-fired, and pulverized-coal
units. The hand-fired boilers generally do not have sophisticated controls,
and they tend to smoke considerably, especially when the furnace box is opened
up to add coal. The operation of stoker-fired boilers requires careful ad-
justments of stoker feed, overfire air, and underfire air. Pulverized coal-
fired boilers are usually equipped with sophisticated combustion-control
systems. During your inspection, count the number of pulverizers that are
running. If one or more pulverizers are not operating, the coal going into
the boiler could be too coarse, which can cause excessive particulate emis-
sions. This might not be the cause, however, if boiler rate has been reduced.
Use a recent fuel analysis to determine whether the boiler is meeting S02
restrictions.
Figure 4-1 is an example of a boiler-description data sheet. The data
sheet is shown filled out in Appendix B. The boiler designation (Line 1) is
taken from Figure 3-2 (boiler equipment identification). Use two columns to
indicate boilers that burn more than one type of fuel during the year.
Describe the boiler operation by listing the capacity factor and the number of
days of operation for each fuel (Lines 2 and 3). Show the average capacity
factor and days-of operation for the previous calendar year or for a recent
12-month period. If the calendar year is not used, note this in the comments
section. The capacity factor is the ratio of the average steam output to the
rated steam output of the boiler.
Enter the boiler manufacturer on Line 4 and the installation date (to
determine if the boiler is an NSPS unit) on Line 5. Indicate the type of
boiler (e.g., fire-tube, water-tube, pulverized-coal, underfeed stoker) on
Line 6.
Fuel data are entered on Line 7a through g. These include the type of
fuel (oil, gas, coal, bagasse, etc.) and the sulfur, ash, and heat content of
Industrial Boiler Inspection Guide Boiler Inspection
10/81 4-2
-------
O =>
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C. BOILER DATA
1. Boiler designation (Checklist B)
2. Average capacity factor during 19 *
3. Hours of operation during 19
4. Boiler manufacturer
5. Year boiler placed in service
6. Type of boiler
7. Fuel data
a . Type
b. Sulfur content (coal and oil
only)**
c. Ash content (coal only)**
d. Heat content**
e. Rated maximum consumption**
f . Actual maximum consumption**
g. Consumption during inspection**
8. Steam production
a. Rated maximum production**
b. Actual maximum production**
c. Production during Inspection**
Additional comments
Average capacity factor Is based on 7e, rated maximum fuel consumption.
»*
Give units.
Figure 4-1. Example of boiler description data sheet.
-------
the fuel. The rated maximum fuel consumption refers to the boiler nameplate
capacity; the actual maximum fuel consumption is the maximum historical rate
for the boiler operation. Indicate units of measurement for all data in this
table. Data on the ash content of coal and the sulfur contents of oil and
coal allow you to estimate particulate and sulfur dioxide emissions. For
example, if a boiler burns bituminous coal with a 3.3 percent ash content and
a 0.7 percent sulfur content and is equipped with a cyclone collector, emis-
sions calculations (based on AP-42) can be made as follows:
Particulate emission factor = 2 x ash content
(Ib/ton coal burned)
= 2 x 3.3
Particulate emission factor =6.6 Ib/ton of coal burned
Sulfur oxides emission factor = 38 x sulfur content
(Ib/ton coal burned)
= 38 x 0.7
Sulfur oxides emission factor = 26.6 Ib/ton of coal burned.
Emission levels generated from AP-42 data are approximate. Only an
on-site source test can provide data of sufficient accuracy for initiation of
legal action. AP-42 data may indicate if a stack test is required.
If a boiler that is designed to burn coal with an ash content of 9.0
percent and a heating value of 11,470 Btu/lb burns coal with an ash content of
20 percent and a heating value of 9,600 Btu/lb, the coal-handling and the
ash-handling systems may be overtaxed when the boiler operates at capacity. A
boiler requires a significantly greater quantity of coal to meet the steam
load demand when it burns a coal of a lower grade than it was designed to
burn. When ash-removal facilities are not adequate, burning lower-grade coal
can impair ESP efficiency or even damage the ESP (e.g., warped plates, shorted
electrodes) by overfilling the ash hoppers.
Steam production data are summarized on Lines 8a, b, and c. Fuel con-
sumption and steam production should correspond. Although both items are
included on the checklist, most sources maintain records for only one of the
parameters. If both are recorded, the numbers can be crosschecked to deter-
mine consistency.
Industrial Boiler Inspection Guide Boiler Inspection
10/81 4-4
-------
Generally, boiler instrumentation data (for inclusion in Figure 4-2) will
be available from the control room. All of the data called for on this form
will not be available for most industrial boilers because small boilers gener-
ally are not well-instrumented. Be sure to indicate units for all data re-
corded on this form, and be aware that instruments will sometimes give faulty
readings.
Lower-than-specified exhaust temperatures may indicate that a boiler is
operating under high excess air conditions, which reduce boiler efficiency and
increase nitrogen oxides emissions. Sometimes, however, low temperatures may
be caused by air in-leakage after the combustion chamber.
Note the oxygen level of the exhaust gas. Typical oxygen levels for good
boiler operation are 0.5 to 1 percent for gas-fired boilers, 1 to 3 percent
for oil-fired boilers, 5 to 6 percent for pulverized-coal-fired boilers, and 7
to 8 percent for stoker-fired boilers. (A 5 percent oxygen level in boiler
exhaust gas is equivalent to about 20 percent excess air.) Note that these
conditions represent oxygen levels at the boiler firebox outlet, and they may
differ significantly from oxygen levels in the stack because of in-leakage
through ductwork and the air preheater.
Large industrial boilers maintain opacity records in the control room.
Inspect opacity charts for the 24 hours preceding the inspection to identify
any irregularity in the boiler operation. Most opacity meters automatically
calibrate at regular intervals. This shows on the strip chart as a short
spike to 100 percent opacity. If the boiler has a continuous SO or NO
/\ /\
meter, the past performance should also be checked.
Industrial Boiler Inspection Guide Boiler Inspection
10/81 4-5
-------
O 3
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0. INSTRUMENTATION DATA
1. Boiler designation
2. Steam production*
3. Fuel consumption*
4. A1r flow
5. Exhaust gas
a. Temperature*
b. COz*
c. 02*
d. S02*
e. NOX*
f. Opacity*
6. Fuel pressure (oil or
gas)*
7. Fuel temperature/oil only*
Additional observations:
CD
o
ft)
-j
Give units.
n
d-
Figure 4-2. Example of boiler instrumentation data sheet.
-------
APPENDIX A
BOILER INSPECTION CHECKLISTS
This appendix provides blank checklists that may be copied and used when
conducting boiler inspections.
Industrial Boiler Inspection Guide Appendix A
10/81 A-l
-------
BOILER INSPECTION CHECKLIST
SOURCE IDENTIFICATION
Date(s) of inspection
Time in Out
Company name
Mailing address
Location of facility
(Include county)
Type of industry _
Form of ownership
Corporate address
Corporate personnel Name Title Phone
Responsible for
facility
Responsible for
environmental
matters
Company personnel
contacted
Confidentiality
statement given to
State or local
agency personnel
Industrial Boiler Inspection Guide Appendix A
10/81 A-2
-------
BOILER EQUIPMENT IDENTIFICATION
Source name Date _
Inspector
Industrial Boiler Inspection Guide Appendix A
10/81 _
-------
SOURCE NAME,
ADDRESS
VISIBLE EMISSION OBSERVATION FORM
OBSERVER
DATE
POINT OF EMISSION
OBSERVATION
POINT
STACK: DISTANCE FROM
WINDSPEED
HEIGHT
DIRECTION
SKY CONDITION:
COLOR OF EMISSION:
RELATIVE HUMIDITY:
BACKGROUND:
AMBIENT AIR TEMPERATURE:
CERTIFICATION DATE:
SUMMARY OF AVERAGE OPACITY
Set
Number
Time
Start—End
Opacity
Sum
Observer x
Sunx> Wind — ^ Plume and
OC=T
Sou
c
Obse
*ce
>
*ver
V
Average
Stack
——
Remarks:
0
i
2
3
4
5
6
7
8
9
10
II
12
n
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
0
15
30
45
•
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
0
15
30
45
I have received a copy of these opacity
readings.
Evaluator's Signature:
Title:
Date:
Industrial Boiler Inspection Guide
10/81 A-4
Appendix A
-------
FAN DATA SHEET
Source name Date
Inspector Fan No.
1. FAN MOTOR
Manufacturer
Model No. Type
Rated horsepower
Volts Maximum amps _
Maximum rpm Service factor
Operating current: Panel Other _
2. DRIVE
Direct Belt Other
Pulley reduction
Audible belt slippage: Yes No
3. FAN
Manufacturer
Model No. Service
Fan vibration
Gas temperature at inlet, °F
Fan rpm
Fan static pressures: Inlet Outlet
Differential static pressures: Measured Panel
Fan housing condition
Dampers
Fan exit
Gas flow from fan curve
Industrial Boiler Inspection Guide Appendix A
10/81 A~5
-------
FABRIC FILTER DESCRIPTION
Source name Date
Inspector Fabric filter No.
Date installed Manufacturer
2
Total filter area, ft Gas flow, acfm
Air/cloth ratio: Net Gross
Cleaning system: Type
Cleaning frequency
Pressure drop before cleaning
Cleaning controlled by AP Time
Operating temperature
Comments
SKETCH THE FABRIC FILTER AND LABEL THE COMPARTMENTS
Industrial Boiler Inspection Guide Appendix A
10/81 A-6
-------
Source name
Inspector
FABRIC FILTER COMPARTMENT EXTERNAL INSPECTION
Date
Fabric filter No.
1. Static pressure (inches W.G.)
Compartment
Plant's instruments
Clean
side
Dirty
side
Differential
Inspector's instruments
Clean
side
Dirty
side
Differential
Comments: (Note any in-leakage of air or signs of corrosion.)
2. Isolation check
Isolated compartment
Opacity
A
B
C
D
E
F
Comments:
Industrial Boiler Inspection Guide
10/81 A-7
Appendix A
-------
ESP DESCRIPTION
Source name
Inspector
Date
ESP No.
Date installed
Manufacturer
2
Total ft plate area
Gas flow, acfm
SCA, ft2/! 000 acfm
Temperature, °F
Coal sulfur content, %
Face velocity, ft/m
Design
Design
Design
Design
Design
Actual
Actual
Actual
Actual
Actual
SKETCH THE ESP AND LABEL THE FIELDS (TR SET)
Industrial Boiler Inspection Guide
10/81
Appendix A
A-8
-------
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ESP ELECTRICAL DATA
Location
TR set
No.
Primary
voltage, V
Present
Base
Primary
current, A
Present
Base
Secondary
Voltage, kV
Present
Base
Secondary
current, mA .
Present
Base
Spark rate,
sparks/mi n
Present
Base
CO
3
Q.
—j.
X
-------
Source name
Inspector
Rappers
Rapper location: Top
Rapper type: Air
EXTERNAL ESP INSPECTION
Date
Rapping frequency: TR No. 1
TR No. 3
Top housing condition
ESP No.
Side
Electrical
Mechanical
TR No. 2
TR No. 4
Insulator condition
Fan and purge-air filter condition
Comments
Industrial Boiler Inspection Guide
10/81 A-10
Appendix A
-------
VENTURI SCRUBBER DESCRIPTION
Source name Date
Inspector Scrubber No.
Type of scrubber Installation date
Manufacturer
Design Actual
Gas flow, acfm
Gas temperature, °F
Pressure drop across the scrubber, in. water
Liquid flow, gal/min
Nozzle pressure, psi
Liquid pH
Comments
SKETCH THE VENTURI SCRUBBER
Industrial Boiler Inspection Guide Appendix A
10/81 A-ll
-------
CYCLONE DESCRIPTION
Source Name Date
Inspector Cyclone No.
Type of cyclone Installation date_
Manufacturer
Design Actual
Gas flow, acfm
Gas temperature, °F
Pressure drop across the collector, in. water
Audible air leakage at hatches
Solids discharge rate, characterize_
Comments:
SKETCH THE CYCLONE SYSTEM
Industrial Boiler Inspection Guide Appendix A
10/81 A-12
-------
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BOILER DATA
1. Boiler designation (Checklist B)
2. Average capacity factor during 19 *
3. Hours of operation during 19
4. Boiler manufacturer
5. Year boiler placed in service
6. Type of boiler
7. Fuel data
a . Type
b. Sulfur content (coal and oil
only)**
c. Ash content (coal only)**
d. Heat content**
e. Rated maximum consumption**
f. Actual maximum consumption**
g. Consumption during inspection**
8. Steam production
a. Rated maximum production**
b. Actual maximum production**
c. Production during inspection**
O>
3
CL
X
Additional comments
**
Average capacity factor is based on 7e, rated maximum fuel consumption.
k
Give units.
-------
ndustrial Boiler Inspection Guide
0/81 A'1 4
INSTRUMENTATION DATA
1. Boiler designation
2. Steam production*
3. Fuel consumption*
4. Air flow
5. Exhaust gas
a. Temperature*
b. C02*
c. 02*
d. S02*
e. NOX*
f. Opacity*
6. Fuel pressure (oil or
gas)*
7. Fuel temperature/oil only*
-
•a
•a
CD
3
a.
x
Additional observations:
Give units.
-------
APPENDIX B
SAMPLE BOILER INSPECTION REPORT
This appendix contains an example inspection report. If your agency has
no particular report design, you may want to use this format.
Industrial Boiler Inspection Guide Appendix B
10/81 B-l
-------
BOILER INSPECTION REPORT
RST COMPANY
1500 COMMERCE STREET
LIMA, MISSISSIPPI 39121
On April 16, 1981, Bruce Williams inspected the boilers at RST Company in
Lima, Mississippi. During this boiler inspection Mr. Tim Hume, Chief Engi-
neer, and Mr. Barry Jones, Plant Supervisor, accompanied me.
PROCESS DESCRIPTION
RST Company manufactures fertilizers at this location. Two coal-fired
(spreader stoker) boilers (B-l and B-2) are associated with the fertilizer
plant. These boilers provide process steam for the plant and heating for
office areas. The plant receives sized coal with an average sulfur content of
0.7 percent and a heat content of about 13,800 Btu/lb. These figures were
obtained from coal company invoices.
Flue gas from each boiler discharges into a multicyclone to remove parti-
culate matter.
A common vacuum type ash handling system is used to convey bottom ash
from the boilers and fly ash from the multicyclone to a silo. Ash stored in
the silo is removed by truck to a disposal site. Water is mixed with the ash
during truck loading to minimize dusting.
Applicable Regulations
The "Air Quality Regulations" (APC-S-1) of the Mississippi Air and Water
Pollution Control Commission are applicable to this facility and regulate
opacity, particulate mass emissions, and S02 as follows:
Opacity - not to exceed 40 percent
Industrial Boiler Inspection Guide Appendix B
10/81 B-2
-------
Mass Emissions - not to exceed the amount given by
E=0.8803Q-°-1665
where E = allowable emissions in lb/106 Btu
Q = heat input, 106 Btu/h
Sulfur Dioxide - not to exceed 4.8 lb/106 Btu heat input.
RESULTS OF INSPECTION
The visible emission readings showed an average opacity of 19 percent.
Table 1 estimates the particulate emissions from Boilers 1 and 2 at 0.42 lb/
106 Btu. The allowable emissions are 0.49 lb/106 Btu for Boiler 1 and
0.42 lb/106 Btu for Boiler 2. Sulfur dioxide emissions for both boilers are
estimated at 0.99 lb/106 Btu.
Industrial Boiler Inspection Guide Appendix B
10/81 B-3
-------
TABLE 1. PARTICULATE EMISSION EVALUATION.
Particulate emission Allowable
Process estimate (1b/106 Btu) emission*1
particulate
(1b/106 Btu)
Boiler No. 1
Boiler No. 2
0.42
0.42
0.49
0.42
Maximum heat
inputc (106 Btu/h)
33.0
83.0
TABLE 2. SULFUR DIOXIDE EMISSION EVALUATION.
Process
Boiler No.
Boiler No.
Sulfur dioxide
emission estimate0
(1b/106 Btu)
0.99
0.99
Allowable sulfur
dioxide emission
estimate5 (1b/106 Btu)
4.8
4.8
Maximum heat
inputc (106 Btu/h)
33.0
83.0
Calculated from AP-42 data.
Calculated using Mississippi State Regulations.
CSupplied by RST Company.
Industrial Boiler Inspection Guide
10/81
B-4
Appendix B
-------
BOILER INSPECTION CHECKLISTS
Industrial Boiler Inspection Guide Appendix B
10/81 B-5
-------
BOILER INSPECTION CHECKLIST
SOURCE IDENTIFICATION
Date(s) of inspection
Time in
HRs, Out
/3/e>
Company name
Mailing address
ffS T
"3 3 ' 2,
Location of facility S<^»n£ CL*L, -vn/xx^-M^ atLthjl^A/ . ff) OM-00 00
- oo oo
ooo
k&O) GQG-Qi
(OOP) t>oo~ooc>o
Industrial Boiler Inspection Guide
10/81 B"6
Appendix B
-------
BOILER EQUIPMENT IDENTIFICATION
Source name ffS7~
Inspector 8/
Date
N
8-1
S-l
f-n
c-i
8-1 La.
6-2
-2
60,000
5 - £
Industrial Boiler Inspection Guide
10/81 B-7
Appendix B
-------
SOURCE NAME /?ST
ADDRESS ISOO
VISIBLE EMISSION OBSERVATION FORM
OBSERVER
DATE
POINT OF EMISSION S+a-JL 5~2. ffn^nv ber&*. 8 -1 )
OBSERVATION
POINT Qsim<*J jt
/
^
STACK: DISTANCE FROM 60-feHEIGHT ^p-ft
WINDSPEED 5Vb /0 MyoA DIRECTION S U/
SKY CONDITION: r^^uJ^j
COLOR OF EMISSION: ^^1
RELATIVE HUMIDITY: ° ^
BACKGROUND:
uJLte. t&rviA
-JGVo
^
AMBIENT AIR TEMPERATURE: &5°F
CERTIFICATION DATE:
WOA^JI
O I
G 1
SUMMARY OF AVERAGE OPACITY
Set
Number
/
Time
Start—End
1053- 1105
Opacity
Sum
Se>&
Observer x
Sun-6- Wind — ^ Plume and
ocr:
Sou
Obse
-ce
rver
X
Average
Zo<&
Stack
Remarks:
0
1
2
3
4
5
6
7
8
9
10
II
12
n
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
0
15"
10
^o
25
25
20
15
/S"
20
2.0
zs
20
SO
30
20
'5
25
25
20
Zo
45
25
20
20
30
25
20
•
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
0
15
30
45
Evaluator's Signature:
I have received a copy of these opacity
.
Title: 4JLJ£^U
Date:
ndustrfal Boiler Inspection Guide
10/81 B-8
ppendix B
-------
SOURCE NAME RST
ADDRESS / 5*00
VISIBLE EMISSION OBSERVATION FORM
OBSERVER
DATE
OpsuJ!
'SI
POINT OF EMISSION 5 ' +a.JL S - 2. / F/iem ^5°E
CERTIFICATION DATE:
WlcvLcJi '%L
SUMMARY OF AVERAGE OPACITY
Set
Number
/
Observe
Sunxjv
Time
Start—End
1107- 1113
Opacity
Sum Average
y-ss 19. o
" X
Wind — i* Plume and Stack
Sou
Obse
S
rver
X
Remarks:
0
1
2
3
4
5
6
7
8
9
10
11
12
n
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
0
Zo
ZO
15
10
15
ZO
15
Zo
Z0
IS
10
ZO
BO
30
Zo
zr
IB
1?
2^
2r
45
Zo
zr
IB
2S
2£
•
30
31
32
33
34
35
36
37
3S
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
0
15
30
45
I have received a copy of these opacity
readings. . ..
Evaluator's Signature:
8.
Industrial Boiler Inspection Guide
10/81
Title:.
B-9
Date:
Appendix 6
-------
FAN DATA SHEET
Source name ff ST
Inspector 3 ,
1
FAN MOTOR
Manufacturer
Date
Fan No.
t* ' -> , r gtvi L& ,
/6 19 & /
F - I
i 6-2)
Model No. y-O&
Type Tin.
/c
Rated horsepower 4
-------
FAN DATA SHEET
Source name ff 5T
Inspector 0.
Date
Fan No. F-Z.
t 16, /3?l
1. FAN MOTOR
Manufacturer
U.S.
Model No. BO1
$
Type TEfC
Rated horsepower "7 £
Volts E3O,
/
Maximum rpm
Operating current:
17 GO
Panel
Maximum amps / $O /
Service factor /, /_5"
Other
90
DRIVE
Direct
Belt
Pulley reduction
Audible belt slippage: Yes
Other
No
X
3. FAN
Manufacturer
Model No.
U, 5, F
Fan vibration
Gas temperature at inlet, °F
Fan rpm
Service
Fan static pressures: Inlet •
Differential static pressures: Measured
Fan housing condition
Dampers
Fan exit
Outlet
Panel
a Q-Tdja/K-
Gas flow from fan curve
Industrial Boiler Inspection Guide
10/81 B-ll
Appendix B
-------
Source Name fPST
*~^
CYCLONE DESCRIPTION
Date
Inspector 8-
Cyclone No. C- 3.
Type of cyclone_
Manufacturer U> S»
Installation date
Gas flow, acfm
Gas temperature, °F
Pressure drop across the collector, in. water
Audible air leakage at hatches
Design Actual
350 3B0
Solids discharge rate, characterize
SKETCH THE CYCLONE SYSTEM
FLi>e JAS I
ft** e-i
C-l
-J'r -T
>LF-3L
Industrial Boiler Inspection Guide
10/81 B-12
Appendix B
-------
Source Name_
Inspector
CYCLONE DESCRIPTION
Date
/&
Cyclone No.
Type of cyclone JYLuJfct*. -
Manufacturer J4. S,
c^
Installation date
Gas flow, acfm
Gas temperature, °F
Pressure drop across the collector, in. water
Audible air leakage at hatches
Design Actual
30,000 £0,300
35O
Solids discharge rate, characterize
SKETCH THE CYCLONE SYSTEM
Industrial Boiler Inspection Guide
10/81 B-13
Appendix B
-------
ndustrial Boiler Inspection Guide
0/81 B-14
BOILER DATA
1. Boiler designation (Checklist B)
2. Average capacity factor during 19735k
3. Hours of operation during 19
4. Boiler manufacturer
5. Year boiler placed in service
6. Type of boiler
7. Fuel data
a. Type
b. Sulfur content (coal and oil
only)**
c. Ash content (coal only)**
d. Heat content**
e. Rated maximum consumption**
f. Actual maximum consumption**
g. Consumption during inspection**
8. Steam production
a. Rated maximum production**
b. Actual maximum production**
c. Production during inspection**
8-1
o.ZS"
398O (b/f|
19^O "'/A
1C 8O '*»/Ai
Z+,000 lk/h
13) ZOO lb/h
ie>,?oe> */h
G-'Z
O.to
4973
AC& \>o*Jb+ Cer.
/3S &
SpSVLajt* St>&^
$ Ztu**U*10tA4. C&CL&.
0.7?*.
(o *?•
fSfS&O 8TtJ/IB
£,000 Ib/h
4- $eo lk/h
*te>oo ty/h
GO; 000 M/h
*t-Q)OO0 Ib/h
*t-Oj600 '^//i
T3
T3
ft)
Q.
Additional comments
CO
**
Average capacity factor is based on 7e, rated maximum fuel consumption.
k
Give units.
-------
ndustrial Boiler Inspection Guide
0/81 B-15
INSTRUMENTATION DATA
1. Boiler designation
2. Steam production*
3. Fuel consumption*
4. Air flow
5. Exhaust gas
a. Temperature*
b. C02*
c. 02*
d. S02*
e. NOX*
f. Opacity*
6. Fuel pressure (oil or
gas)*
7. Fuel temperature/oil only*
8-1
IG>, YOO {Vh
IGXO '* /h
-3&0* F
4-*?o
Zff
3-Z.
? 0,600 U>/h
*tOOO 'b/fr
3 (oO^F
5*7*
£0
Additional observations:
au/i.
•a
•o
o.
X
DO
Give units.
-------
CALCULATIONS
PARTICULATE EMISSIONS
This calculation applies to both boilers (B-l and B-2).
From AP-42 (page 1.1-3, 12/77 edition) particulate emissions in Ib/ton of coal
without any control device are given by 13A, where A equals percent ash.
13 x 6 = 78 Ib/ton coal
The coal heat content is
13,800 Btu/lb x 2000 Ib/ton = 27.6 x 106 Btu/ton
Based on the minimum efficiency of a cyclone (AP-42, p. 1.1-2, 12/77 edition),
controlled emissions are
78 x (1 - 0.85) = 11.7 Ib/ton
In terms of pounds per million Btu's the emissions are
11-7 = 0.42 lb/106 Btu
27.6 x 106
The allowable emission rate is calculated by
E= 0.8803Q-0'1665
where E = allowable emission, lb/106 Btu
Q = maximum heat input, 106 Btu/lb
111
c _ n QQn, ,2400 Ib/h x 13,800 Btu/1b^-o-1665
t — U.ooUo ^ "\ft& '
= 0.49 lb/106 Btu
B-2
c _ n QQno ,6000 Ib/h x 13.800 Btu/lbx-o.i66s
t - U.OOUJ t J-Q6 '
= 0.42 lb/106 Btu
Both boilers are in compliance. Boiler B-2 is just at the limit.
Industrial Boiler Inspection Guide Appendix B
10/81 B-l6
-------
FLUE GAS FLOW RATE
The flue gas flow rate is calculated using F-factors for bituminous coal.
The F-factors are from "Continuous Air Pollution Source Monitoring Systems,"
EPA 625/6-79-005, page C-7. The boiler elevation is about 1000 ft above sea
level .
B-1
B-2
H = 1680 Ib/h x 13,800 Btu/lb = 23.2 x 106 Btu/h
.380
Arfm _ 23.2
Acfm ~
20.9
20.9 .
- }
460 .
530
= 8237 acfm
H
Arf_
Acfm
4000 Ib/h x 13,800 Btu/lb = 55.2 x 106 Btu/h
55.2 , 20.9 > - 380 + 460
,
(
20.9 - 5
>
}
530
= 20,300 acfm
,
(
30770
30770 - 1000
.
}
30770
30770 - 1000
.
Industrial Boiler Inspection Guide
10/81
B-17
Appendix B
-------
PHOTOGRAPH NO. 1. RST Company t>oiler stacks.
S-l is on the left and S-2 is on the right.
Industrial
10/81
Boiler Inspection Guide
Appendix B
B-18
-------
GLOSSARY
AIR HEATER OR AIR PREHEATER - A heat transfer device that heats air coming
into the boiler with flue gas exhausting from the boiler. This conserves
energy and makes the boiler more efficient.
AIR INFILTRATION - The leakage of air through cracks or other openings into
the boiler duct system or control device.
ANALYSIS, PROXIMATE - A method of reporting fuel composition in terms of
moisture, volatile matter, fixed carbon, and ash, as a percentage of the
total weight of the fuel.
ANALYSIS, ULTIMATE - An exact chemical analysis of the fuels, including car-
bon, hydrogen, sulfur, nitrogen, oxygen, and ash content.
ANTHRACITE - A type of coal, mined mostly in Pennsylvania that contains a high
fixed carbon content and low amount of volatile material.
ASH - The incombustible solid matter in fuels, usually mineral in composition.
ASH-FREE BASIS - A method of reporting fuel analyses in which ash content is
deducted and the other constituents are recalculated to total 100 per-
cent.
ASH PIT - A pit or hopper located below the boiler where ash accumulates
until it is removed.
ATOMIZER - A device that reduces liquid into a very fine spray for combus-
tion purposes.
AVAILABLE DRAFT - The draft that is utilized to force air into the combustion
chamber and to force gaseous combustion products out of the boiler.
B
BAFFLE - A plate or wall that deflects and changes the course of a gas or a
liquid.
BAG FILTER - Another term for a fabric filter.
Industrial Boiler Inspection Guide Glossary
10/81 1
-------
BANKING - This term applies to stoker boilers. It refers to burning solid
fuels at a very slow rate in order to maintain ignition. This is some-
times done when steam is not needed, but the operator does not want to
shut the boiler down completely.
BASE LOAD - The rate at which a boiler is usually operated for long periods of
time.
BITUMINOUS COAL - A coal commonly found in the Appalachian Region. Heating
values are typically 10,000 to 14,000 Btu/lb.
SLOWDOWN - The periodic or continual removal of small amounts of water from
the boiler drum to reduce the concentration or buildup of dissolved
impurities and sludge.
BLOWER - A fan used to move air under pressure.
BOILER HORSEPOWER - A term sometimes used to denote the capacity of a boiler.
One boiler horsepower is equivalent to 33,472 Btu/h of steam output.
BRITISH THERMAL UNIT (Btu) - The amount of heat required to raise the tempera-
ture of 1 Ib of water 1°F; 1 Btu is about 252 calories.
BUNKER-C OIL - Sometimes called residual fuel oil or No. 6 fuel oil. This is
a viscous, low-grade oil that must be heated before it can be atomized in
a boiler.
CAPACITY FACTOR - The ratio of the boiler steam production rate to its maxi-
mum design steam load.
CHAIN GRATE STOKER - A stoker that has a moving endless chain as a grate sur-
face. Coal is fed directly onto this chain from a hopper and moves
across the combustion section of the boiler.
COMBUSTION RATE - The amount of fuel fired per unit of time, such as pounds
of coal per hour, or gallons of oil per hour.
CONDENSATE - Water that has been condensed from steam.
DAMPER - A device for regulating the flow of gas or air by partially blocking
the path of flow.
DAMPER LOSS - The reduction in static pressure of gas or air flowing through a
damper.
Industrial Boiler Inspection Guide Glossary
10/81 2
-------
DESIGN LOAD - The maximum steam production rate that a boiler is designed to
produce.
DEW POINT - The temperature at which condensation begins. References to the
dew point of flue gas usually refer to the temperature at which sulfuric
acid will begin to condense.
DIRECT-FIRED BOILER - A pulverized-coal boiler that is fed directly from the
coal pulverizers; it has no pulverized coal surge hold system.
DISTILLATE FUELS - Liquid fuels distilled from crude petroleum of a higher
grade than No. 5 or No. 6 fuel oils.
DOWNCOMER - A boiler tube through which liquid flows downward.
DRUM --A cylindrical shell designed to withstand high internal pressures in
which the steam separates from the water and leaves the boiler.
DRY STEAM - Steam containing no moisture, or superheated steam.
ECONOMIZER - A device designed to transfer heat from the gaseous combustion
products to the boiler feedwater.
EFFICIENCY - The ratio of the amount of energy leaving the boiler in steam to
the amount of energy fed to the boiler in fuel.
ENTRAINMENT - The conveying of droplets of water from the boiler by steam.
EVAPORATION RATE - The number of pounds of water evaporated per unit of time.
EXCESS AIR - Air supplied to burn the fuel in excess of the air theoretically
required for complete oxidation.
FEEDWATER - Water introduced into the boiler to replace lost steam and conden-
sate. This water includes returning condensate, as well as treated fresh
water.
FEEDWATER TREATMENT - A treatment of boiler feedwater by the addition of chemi-
cals, ionic exchange, and deaeration to remove minerals and gases that
would be harmful to the boiler.
FIREBOX - A term sometimes used to describe the furnace section of a boiler.
FIRE POINT - The lowest temperature at which fuel oil gives off enough vapor
to burn continuously when ignited.
Industrial Boiler Inspection Guide Glossary
10/81 3
-------
FIRE TUBE - A boiler design in which the hot combustion products pass through
the tubes and the water is on the outside of the tubes.
FLAME DETECTOR - A device that indicates the presence of a flame in the
boiler. This is usually part of the safety system.
FLUE - A passage for the gaseous products of combustion.
FLUE GAS - The gaseous products of combustion that leave the boiler.
FLY ASH - The fine particles of ash that are carried out of a boiler by the
combustion gases.
FORCED-DRAFT FAN - A fan that supplies air under pressure to the combustion
chamber of the boiler.
FOULING - Accumulation of refuse in gas passages or absorbing surfaces which
results in undesirable restrictions to the flow of gas or heat.
FRIABILITY - The tendency of a lump of coal to crumble or break into small
pieces.
FUEL BED - The layer of burning coal on a stoker boiler grate.
FUEL-BED RESISTANCE - The static pressure differential necessary to drive air
through a fuel bed.
G
GAGE PRESSURE - The pressure above atmospheric pressure.
GRATE - The surface on which the fuel is supported and burned in a stoker
boiler.
H
HANDHOLE - An opening in the pressure portion of a boiler, generally no larger
than 6 in. in its longest dimension.
HAND LANCE - A pipe carrying air, steam, or water under high pressure for the
manual cleaning of ash and slag accumulations from heat-transfer sur-
faces.
HOGGED FUEL - Wood refuse that has been chipped or shredded by a machine known
as a hog.
HOPPER - A chamber or bin used for holding solid fuel or ash.
Industrial Boiler Inspection Guide Glossary
10/81 4
-------
HYDROSTATIC TEST - A test of the strength and tightness of a vessel by filling
the vessel with water, sealing it off, and then pressurizing the water.
IGNITION - Lighting of the boiler.
IGNITION TEMPERATURE - The lowest temperature of a fuel at which combustion is
self-sustaining.
INCHES WATER GAGE (w.g.) - A term for measuring low pressure or pressure dif-
ferentials. One inch of water is 0.036 Ib per square inch.
INDUCED-DRAFT FAN - A fan on the exhaust side of the boiler that draws combus-
tion gases from the boiler.
L
LAGGING - A term usually meaning insulation.
LIGNITE - A low-Btu, high-moisture coal usually found west of the Mississippi.
LIVE STEAM - Steam that has been generated, but has not yet been used.
LOAD FACTOR - The ratio of the average load in a given period to the maximum
load carried during that period.
M
MAKEUP WATER - Water added to the boiler to make up for losses through blow-
down, leakage, steam losses, etc.
N
NATURAL CIRCULATION - The circulation of water through a boiler by means of
differences in density rather than a pump.
NATURAL GAS - Gaseous fuel occurring in nature, consisting predominantly of
methane.
ORSAT - An apparatus used to measure certain constituents of flue gas by se-
quential absorption in chemical solutions.
Industrial Boiler Inspection Guide Glossary
10/81 5
-------
OVERFIRE AIR - Air for combustion admitted into the furnace above the fuel
beds to complete the combustion of unburned hydrocarbons.
PASS - A confined passageway through which a fluid flows in one direction to
be heated.
PEAK LOAD - The maximum load that a boiler can carry for a stated short period
of time.
PITOT TUBE - An instrument used to measure the velocity of gas flowing through
a section of duct.
PLENUM - An enclosure through which gas or air passes at low velocities.
PNEUMATIC CONVEYING - Transporting fuel through a conduit by air.
PREHEATED AIR - Air that has been heated above ambient temperature.
PRESSURE DROP - The difference in pressure between two points along a gas
flow path, caused by resistance to flow.
PRIMARY AIR - Air introduced with the fuel at the burner. This is sometimes
referred to as pulverizer air in pulverized coal boilers.
PRIMARY AIR FAN - The fan used to supply primary air.
PRODUCTS OF COMBUSTION - The gases and solids resulting from the combustion
of fuel.
PROXIMATE ANALYSIS - See "Analysis, Proximate."
PUFF - A minor combustion explosion within the boiler furnace.
PULVERIZER - A machine that reduces coal to a fineness suitable for burning
in suspension.
PULVERIZER AIR - Air that passes through the pulverizer to dry and convey the
pulverized coal to the combustion chamber and direct-fired systems, or to
a storage bin.
PULVERIZED FUEL - Solid fuel reduced to a finely crushed or powdered state.
PULVERIZED COAL BOILER - Sometimes called a PC boiler. Coal is ground into
a powder and blown into the firebox with hot air for combustion. About
80 percent of the ash in the coal is carried out in the flue gas.
PYRITES - A compound of iron and sulfur occurring naturally in coal.
Industrial Boiler Inspection Guide Glossary
10/81 6
-------
RADIATION LOSS - A term used in boiler heat balance calculations to account
for total heat losses by conduction, radiation, and convection from the
furnace box to the ambient air.
RATED CAPACITY - The manufacturer's stated capacity rating for the equipment
in question.
RAW WATER - Water supplied to the plant before any treatment.
REFRACTORY - A heat-resistant material used to line boiler combustion areas.
REGISTER - An apparatus used to regulate the direction of flow of combustion
air.
REHEATER - Heat transfer equipment to heat steam after it has given up some
of its original heat.
REHEATING - The process of adding heat to steam to raise its temperature after
it has done part of its work.
REINJECTION - The procedure of returning a portion of the collected fly ash to
the furnace to complete the combustion of any residual carbon in the fly
ash.
RETORT - A channel in an underfeed stoker through which fuel is forced upward
into the fuel bed.
RETRACTABLE BLOWER - A soot blower that can be mechanically extended and then
retracted into the boiler.
RIFFLE - A device for taking a representative sample of coal by repetitively
splitting the sample into smaller portions.
RISER TUBE - A tube through which steam and water pass up into the boiler
drum.
ROTARY VALVES - A device that maintains an airtight seal as it dumps ash from
the bottom of an ash hopper.
RUN OF MINE - Unscreened coal as it comes out of the mine.
S
SCALE - A hard coating of mineral on internal boiler surfaces.
SCREW FEEDER - A means of conveying coal or ash by a screw that rotates
inside a pipe. This is sometimes called a screw conveyor.
Industrial Boiler Inspection Guide Glossary
10/81 7
-------
SECONDARY AIR - Air for combustion to supplement the primary air.
SECONDARY COMBUSTION - Combustion occurring as a result of ignition at a point
beyond the normal furnace combustion chamber. This is sometimes called
delayed combustion.
SOOT BLOWER - A mechanical device that uses high-pressure steam or air to
remove accumulated material from the fire side of a heat transfer sur-
face.
SPECIFIC HEAT - A quantity of heat expressed in Btu's required to raise the
temperature of 1 Ib of a material by 1°F.
SPREADER STOKER - A device that throws coal onto the surface of a grate by
means of mechanical feeders above the grate.
STANDARD AIR - Dry air at atmospheric pressure and 70°F. This term is used
in combustion calculations.
STEAM QUALITY - The vapor percent by weight in a steam/water mixture.
STOKER BOILER - A boiler in which solid fuel is fed onto a grate in the fire-
box and burned. See Traveling Grate, Chain Grate, Vibrating Grate, and
Spreader Stoker. Stokers usually have low fly ash carryover.
SUBBITUMINOUS COAL - A medium-quality coal usually rated between 9500 and
13,000 Btu/lb.
SUPERHEAT - To raise the temperature of steam above its saturation point.
SURFACE BLOWOFF - The removal of water or foam from the surface of the water
in the boiler drum.
SURFACE MOISTURE - The portion of coal moisture that comes from external
sources such as water seepage, rain, snow, etc.; sometimes called free
moisture.
TANGENTIAL FIRING - A method of firing in which burners located in the furnace
walls fire tangentially to an imaginary circle within the furnace.
THEORETICAL AIR - The quantity of air required for perfect combustion.
TRAVELING-GRATE STOKER - A stoker similar to a chain-grate stoker except that
the grate is driven by chains but is separate from the chains.
TUYERES - Air entry ports into the combustion zone that restrict the flow of
ash back into the air plenum.
Industrial Boiler Inspection Guide Glossary
10/81 8
-------
u
ULTIMATE ANALYSIS - See "Analysis, Ultimate."
USE FACTOR - The ratio of hours of operation to total hours in a given period.
VERTICAL FIRING - An arrangement of firing in which the air and fuel are dis-
charged vertically into the furnace.
VIBRATING GRATE STOKER - A stoker in which vibration and gravity move coal
along a grate that is inclined downward. Typically the grate is vibrated
for about 5 seconds every 2 minutes.
VOLATILE MATTER - The gaseous products given off when a fuel is heated when
prescribed conditions.
W
WASTE HEAT - Heat recovered from exhaust flue gases and used for other process
purposes, such as drying grains or processing ores.
WATER TUBE - A boiler construction method whereby water to be heated passes
inside a tube with the fire on the outside of the tube.
WINDBOX - A plenum below the grate of a stoker boiler, or surrounding the
burner of other types of boilers, in which air, under pressure, is sup-
plied for the combustion of fuel.
WINDBOX PRESSURE - The static pressure in the windbox of a burner or stoker.
ZONE CONTROL - The control of air flow into individual zones below the bed of
a stoker boiler.
Industrial Boiler Inspection Guide Glossary
10/81 9
-------
BIBLIOGRAPHY
Air Pollution Control, Industrial Guide to. Handbook, EPA-625-6-78-004, June
1978.
Combustion Evaluation, APTI Course 427, Student Manual, EPA 450/2-80-063,
February 1980.
Confined Space Entry, Recommendations for. Addendum for use with Workshop
Volume II. U.S. Environmental Protection Agency, Office of Enforcement,
March 1980.
Counterflow Inspection Procedures for Performance Baseline Assessment and
Routine Evaluation. (Draft report for the Environmental Protection Agen-
cy, Division of Stationary Source Enforcement.) By J. R. Richards, PEDCo
Environmental, Inc., February 1980.
Data Validation Scheme for Pulverized Boilers, A. By C. Bruffey and
W. G. DeWees, PEDCo Environmental, Inc., undated.
Electrostatic Precipitation of Fly Ash. By H. J. White, APCA, July 1977.
Electrostatic Precipitators, Operation and Maintenance of. Vol. V. Refer-
ence Material for Technical Workshop on Evaluation of Industrial Air
Pollution Control Equipment Operation and Maintenance Practices. (Draft)
U.S. Environmental Protection Agency Office of Enforcement, July 1979.
Electrostatic Precipitators, Operation and Maintenance of. Michigan Chapter,
East Central Section, of APCA, April 1978.
Electrostatic Precipitators, Selected Articles on, Vol. IV, Reference Mate-
rial for Boiler Compliance Inspection Workshop for EPA Region III, Draft,
EPA Office of Enforcement, January 1981.
Electrostatic Precipitator Performance, Inspection Manual for Evaluation of.
By M. Szabo, Y. Shah, and S. Schleisser, PEDCo Environmental, Inc., Janu-
ary 1981.
ESP Inspection Procedures - Operator and Control Agency Roles in Ensuring
Continuous Compliance. By J. R. Richards, R. Hawks, and M. Szabo, PEDCo
Environmental, Inc., undated.
ESP Performance Analysis and Diagnosis of Internal Conditions from Operation
and Maintenance Recordkeeping. By S. Schliesser, PEDCo Environmental,
Inc., undated.
Industrial Boiler Inspection Guide Bibliography
10/81 1
-------
Fabric Filters. By C. M. Schmidt, Schmidt Associates, Inc., Cleveland, Ohio,
undated.
Fabric Filter Experience With a Utility Boiler, Pennsylvania Power and Light
Co., Sunbury SES - Presentation Outline. By D. J. Murphy, Sunbury SES,
undated.
Fabric Filters, Operation and Maintenance of. Vol. VI. Reference Material
for Enforcement Workshop on Plant Inspection and Evaluation Procedures.
Draft. U.S. Environmental Protection Agency, Office of Enforcement, July
1979.
Fabric Filters, Selected Articles on. Vol. V. Draft. Reference Material for
Boiler Compliance Inspection Workshop for EPA Region III, Draft, EPA
Office of Enforcement, January 1981.
Filter Media and Fabric Filter Aspects for Coal-Fired Boiler and S02 Dry
Scrubbing Applications. Condensed Handbook. By. L. Bergmann, Filter
Media Consulting, Inc., no date.
Flue Gas Desulfurization Systems, Selected Articles on. Vol. VI. Reference
Material for Boiler Compliance Inspection Workshop for U.S. Environmental
Protection Agency, Office of Enforcement, January 1981.
Industrial Boilers, Good Operating Practices for. By C. M. Schmidt, Schmidt
Associates, Inc., Cleveland, Ohio, November 1979.
Observer's Checklist Package for EPA Reference Test Methods and Continuous
Emission Monitor Certification. Draft. U.S. Environmental Protection
Agency Office of Enforcement, June 1980.
Observing Compliance Tests. Vol. IX. Draft. U.S. Environmental Protection
Agency, Office of Enforcement, July 1979.
Opacity as an Indicator of Control Equipment Performance. By Kirk Foster,
U.S. Environmental Protection Agency, Office of Enforcement, and
G. Saunders, PEDCo Environmental, Inc., November 1978.
Particulate Source Sampling at Steam Generators with Intermittent Soot Blow
ing. By J. W. Peeler, Entropy Environmentalists, for K. Foster, DSSE,
October 1978.
Power from Coal. Special report by editors of Power, February 1974.
Process and Control Equipment Flow Charting Techniques. Vol. III. Draft. By
J. R. Richards, PEDCo Environmental, Inc., for U.S. Environmental Protec-
tion Agency, Office of Enforcement, February 1979.
Pulverized Coal-Fired Utility Boiler, Practical Operating Aspects of a. By
T. Malinky, Pennsylvania Power & Light Co., York Haven, Pennsylvania,
undated.
Industrial Boiler Inspection Guide Bibliography
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Smoke-Stack Plumes, Their Opacity and Visual Effects. By W. Conner, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina,
undated.
Industrial Boiler Inspection Guide Bibliography
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