United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-82-006b
March 1982
Air
Fossil Fuel Fired Draft
Industrial Boilers- EIS
Background Information
Volume 2: Appendices
-------
EPA-450/3-82-006b
Fossil Fuel Fired
Industrial Boilers-
Background Information
Volume 2: Appendices
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
March 1982
-------
This report has been reviewed by the Emission Standards and Engineering Division
of the Office of Air Quality Planning and Standards, EPA, and approved for publication.
Mention of trade names or commercial products is not intended to constitute endorsement
or recommendation for use. Copies of this report are available through the Library
Services Office (MD-35) .U.S. Environmental Protection Agency, Research Triangle
Park, N.C. 27711, or from National Technical Information Services, 5285 Port Royal
Road, Springfield, Virginia 22161.
For sale by Superintendent of Documents
U.S. Government Printing Office
Washington, DC 20402
-------
TABLE OF CONTENTS
Page
APPENDIX A - Evolution of the Background Information Document . . . A-l
APPENDIX B - Index to Environmental Considerations B-l
APPENDIX C - Emission Test Data C-l
APPENDIX D - Emission Measurement and Monitoring Methods D-l
APPENDIX E - Emerging Technology Model Boiler Impact Analysis . . . E-l
m
-------
APPENDIX A
EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
The purpose of this study was to develop background information to
support New Source Performance Standards (NSPS) for industrial boilers.
Work on this study was performed by the Acurex Corporation from June 1978
until February 1980 and by the Radian Corporation after February 1980 under
contract with the United States Environmental Protection Agency, Office of
Air Quality Planning and Standards.
The following chronology lists the major events which have occurred
during the development of background information for the industrial boiler
NSPS. Major events are divided into three categories: (1) plant visits and
emission testing, (2) meetings and briefings, and (3) reports and mailings.
I. Plant Visits and Emission Testing
July 28, 1978 Plant visit to DuPont in Wilmington, Delaware.
August 17, 1978 Plant visit to Caterpillar Tractor Company in
Joliet, Illinois.
August 18, 1978 Plant visit to General Motors Corporation in
Parma, Ohio.
September 11, 1978 Plant visit to Great Southern Paper in Cedar
Springs, Georgia.
September 18, 1978 Plant visit to Babcock and Wilcox in Wilmington,
North Carolina.
A-l
-------
September 19, 1978
September 20, 1978
September 21, 1978
September 22, 1978
September 30, 1978
November 14, 1978
December 13, 1978
January - March, 1979
February 21, 1979
March 21, 1979
August 13, 1979
August 13, 1979
August 14, 1979
August 14, 1979
August 28, 1979
August 28, 1979
October 16, 1979
Plant visit to Cleaver Brooks in Lebanon,
Pennsylvania.
Plant visit to Keeler Company in Williamsport,
Pennsylvania.
Plant visit to International Boiler Works in East
Stroudsburg, Pennsylvania.
Plant visit to Peabody Engineering Corporation in
Stamford, Connecticut.
Plant visit to Mead Paperboard in Stevenson,
Alabama.
Plant visit to Firestone Tire and Rubber Company,
in Pottstown, Pennsylvania.
Visit for test presurvey to Rickenbacker Air Force
Base in Columbus, Ohio.
Emission source -testing at Rickenbacker Air Force
Base in Columbus, Ohio.
Plant visit to Johnson Boiler Company offices in
Ferrysburg, Michigan.
Plant visit to DuPont.
Plant visit to Holsum Foods in Waukesha, Wisconsin.
Plant visit to Libby, McNeil, and Libby in
Janesville, Wisconsin.
Plant visit to Minn-Dak Farmer's Co-op in Whapeton,
North Dakota.
Plant visit to American Crystal Sugar Company in
Moorehead, Minnesota.
Plant visit to Goodyear Tires in Akron, Ohio.
Plant visit to Ohio Rubber Company in Willoughby,
Ohio.
Plant visit to General Motors in St. Louis,
Missouri.
A-2
-------
October -
November, 1979
November, 1979 -
January, 1980
January - March 1980
January 1980 -
March 1980
February 8, 1980
February 8, 1980
March 25, 1980
March 26, 1980
April 18, 1980
April 18, 1980
July 1, 1980
August 19, 1980
August 20, 1980
August 29, -
September 24, 1980
November 10-17, 1980
December 15-17, 1980
Emission source testing at Mead Paperboard in
Stevenson, Alabama.
Continuous S02 Monitoring at Rickenbacker Air Force
Base in Columous, Ohio.
Continuous S02 Monitoring at General Motors plant
in Parma, Ohio.
Continuous S0? Monitoring at General Motors in
St. Louis, Missouri.
Plant visit to Tri-Valley Growers in Modesto,
California.
Plant visit to California Canners and Growers in
San Jose, California.
Plant visit to Brown-Forman Spirits in Louisville,
Kentucky.
Plant visit to Jack Daniel Distillery in Lynchburg,
Tennessee.
Plant visit to Great Lakes Steel in Ecorse,
Michigan.
Plant visit to Republic Steel in Chicago, Illinois.
Plant visit to General Motors Corporation in
Columbus, Ohio.
Plant visit to Celanese Fibers Amcell plant in
Cumberland, Maryland.
Visit to Georgetown University fluidized bed
combustion steam generator in Washington, D. C.
Continuous S0£ Monitoring at Celanese Fibers in
Cumberland, Maryland.
Emission testing for particulate matter at General
Motors in Parma, Ohio.
Emission source testing for particulate matter at
DuPont and Company Washington Works in Parkersburg,
West Virginia.
A-3
-------
June 10, 1981
June 30, 1981
July 16, 1981
August 1-4, 1981
September 29 -
October 2, 1981
December 1, 1981
March 2, 1982
Plant visit to DuPont DeNemours Company in
Martinsville, Virginia.
Plant visit to General Motors Chevrolet Plant in
Parma, Ohio.
Plant visit to Tennessee Eastman Company in
Kingsport, Tennessee.
Emission source testing at Caterpillar Tractor in
Peoria, Illinois.
Emission source testing at Boston Edison Company
in Everett, Massachusetts.
Particulate emission test at Caterpillar Tractor
Company in Peoria, Illinois.
Particulate emission source testing at General
Motors plant, Hamilton, Ohio.
II. Meetings and Briefings
April 17, 1978
April 18, 1978
June 2, 1978
July 19, 1978
December 6, 1978
December 8, 1978
January 10-11, 1979
February 15, 1979
February 28, 1979
Meeting of project team members with Department of
Energy (DOE) representatives.
Meeting of project team members with American
Boiler Manufacturers Association (ABMA).
Meeting of project team members with DuPont
representatives.
Meeting of project team members with ABMA.
EPA Working Group meeting.
EPA Steering Committee meeting.
NAPCTAC meeting on status of NSPS for industrial
boilers.
Meeting of project team with ABMA, Industrial Gas
Cleaning Institute, Department of Energy, and
Council of Industrial Boiler Owners (CIBO).
Meeting of project team members with DOE
representatives.
A-4
-------
March 27, 1979
March 29, 1979
June 11, 1979
June 19, 1979
July 12, 1979
July, 1979
August 3, 1979
October 4, 1979
October 16, 1979
October 17, 1979
October 26, 1979
October 29, 1979
January 24, 1980
February 11, 1980
February 28, 1930
March 18, 1980
July 9-10, 1980
September 24, 1980
Meeting of project team with CIBO.
Presentation to National Association of
Manufacturers in Washington, D.C.
Meeting of project team members with DOE to discuss
energy scenarios that will be used in industrial
boiler NSPS development.
Meeting of project team members with representa-
tives of Combustion Engineering.
Meeting of project team members with CIBO
representatives.
Meeting of contractor with United States Sugar Beet
Association representative.
Meeting of contractor with National Food Processors
Association representative.
Meeting of project team with General Motors
representatives.
Meeting of project team with several industrial
representatives.
Meeting of project team members with CIBO
representatives.
Meeting of project team members with ABMA.
Meeting of project team with Rickenbacker Air Force
Base representatives.
Meeting of project team members with National Food
Processors Association representative.
Change of contractors from Acurex to Radian.
Team meeting to review project status.
Team meeting to discuss IFCAM results for Round 4
and set input conditions for Round 5.
NAPCTAC meeting.
Meeting of project team members and industry
representatives on coal-limestone pellet status.
A-5
-------
September, 1980
October, 1980
November 6, 1980
November, 1980
November 15, 1980
December 8, 1980
March 12, 1981
March, 1981
June, 1981
July 15, 1981
February 9, 1982
March 2, 1982
March 10, 1982
IFCAM working group meetings.
Project schedule revised to incorporate a second
NAPCTAC meeting and two steering committee
meetings.
Team meeting to discuss EPA's Office of Research
and Development position on the IB NSPS.
Briefing held for Steering Committee.
Steering Committee meeting.
Meeting of project team members with ABMA
representative.
Meeting of project team members with Charles
Schmidt to discuss industrial boilers and emission
controls.
Team meeting to outline remaining work on
statistical analyses reports.
Team meeting to discuss preamble and regulation.
Team meeting to review adipic acid addition to FGD
data, S02 report, fuel nitrogen/NO emission study,
and respirable PM cost effectiveness.
Meeting with representatives of ABMA, CIBO, and
Chemical Manufacturer's Association.
Meeting with representatives of ABMA to discuss NO
control techniques for stoker boilers. x
Meeting with representatives of ABMA to discuss NO
control techniques for stoker boilers. x
A-6
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APPENDIX B
INDEX TO ENVIRONMENTAL CONSIDERATIONS
This appendix consists of a reference system which is cross
indexed with the October 21, 1974, Federal Register (30 FR 37419)
containing EPA guidelines for the preparation of Environmental
Impact Statements. This index can be used to identify sections of
the document which contain data and information germane to any
portion of the Federal Register guidelines.
There are, however, other documents and docket entries which also
contain data and information, of both a policy and a technical nature,
used in developing the proposed standards. This Appendix specifies
only the portions of this document that are relevant to the indexed items,
B-l
-------
TABLE B-l. INDEX TO ENVIRONMENTAL CONSIDERATIONS
CD
ro
Agency Guideline for Preparing Regulatory
Action Environmental Impact Statements
(39 FR 37419)
(1) Background and summary of regulatory
alternatives
Regulatory alternatives
Statutory basis for proposing standards
Source category and affected industries
Location Within the Background Information Document
The regulatory alternatives are summarized in
Chapter 6.
The statutory basis for the proposed standards
is summarized in Chapter 2, Section 2.1.
A discussion of the industrial boiler source category
is presented in Chapter 3. Details of the "business/
economic" nature of the industries affected are
presented in Chapter 9.
Emission control technologies
A discussion of emission control technologies is
presented in Chapter 4.
-------
TABLE B-l. (CONTINUED)
CO
I
CO
Agency Guideline for Preparing Regulatory
Action Environmental Impact Statements
(39 FR 37419)
(2) Environmental, Energy, and Economic
Impacts of Regulatory Alternatives
Regulatory alternatives
Environmental impacts
(Individual boilers)
Energy impacts
(Individual boilers)
Cost impacts
(Individual boilers)
Economic impacts
(Individual boilers)
National and regional
environmental, energy
and cost impacts
Locations Within the Background Information Document
Various regulatory alternatives are discussed in
Chapter 6.
The environmental impacts of various regulatory
alternatives are presented in Chapter 7, Sections
7.1, 7.2 and 7.3.
The energy impacts of various regulatory
alternatives are discussed in Chapter 7, Section 7.4
Cost impacts of various regulatory alternatives
are discussed in Chapter 8.
The economic impacts of various regulatory
alternatives are presented in Chapter 9.
The national and regional impacts of regulatory
alternatives are presented in Chapter 9.
-------
TABLE B-l. (CONTINUED)
Agency Guideline for Preparing Regulatory
Action Environmental Impact Statements
(39 FR 37419)
Location Within the Background Information Document
CD
i
-£»
(3) Environmental impact of the
regulatory alternatives
Air pollution
(Individual boilers)
Water pollution
(Individual boilers)
Solid waste disposal
(Individual boilers)
The impact of the proposed standards on air
pollution is presented in Chapter 7, Section 7.1.
The impact of the proposed standards on water
pollution is presented in Chapter 7, Section 7.2.
The impact of the proposed standards on solid
waste disposal is presented in Chapter 7, Section 7.3
-------
APPENDIX C
TABLE OF CONTENTS
Page
C.I PARTICULATE EMISSION DATA C-3
C.I.I Participate Emission Data for Electrostatic
Precipitators C-5
C.I.2 Particulate Emission Data for Fabric Filters c-28
C.I.3 Particulate Emission Data for Mechanical Collectors . . c-51
C.I.4 Particulate Emission Data for Dual Mechanical
Collectors C-86
C.I.5 Particulate Emission Data for Wet Scrubbers c-94
C.I.6 Particulate Emission Data for Side Stream Separators. . c-138
C.2 VISIBLE EMISSION DATA C-155
C.3 S02 EMISSION REDUCTION DATA C-160
C.4 N0x EMISSION REDUCTION DATA C-194
C.5 REFERENCES C-262
C-i
-------
APPENDIX C
Available emission data illustrating the performance levels achievable
by various control systems evaluated in this study are presented in this
appendix. The data are analyzed and discussed in Chapter 4. The data
base is organized as follows:
Section C.I - Particulate Emission Data
C.I.I - For Electrostatic Precipitators
C.I.2 - For Fabric Filters
C.I.3 - For Mechanical Collectors
C.I.4 - For Dual Mechanical Collectors
C.I.5 - For Wet Scrubbers
C.I.6 - For Side-Stream Separators
Section C.2 - Visible Emission Data
Section C.3 - SCL Emission Data
Section C.4 - NO Emission Data
A
Section C.5 - References
For each data set presented in this Appendix, a brief description of the
test site is provided which includes data such as (when available):
• Boiler type and rated capacity
• Load factor during test
•Type of emission control system
• Important emission control system design specifications (where known)
• Important emission control operating parameters (during test)
• Control system outlet emission level
• Test method used
C-l
-------
All particulate and visible emission test sites are given a letter
designation (example, Plant A). All S0? emission locations are given a
roman numeral designation (example, Location I). Roman numerical
designations are also given to all NO emission test locations.
X
C-2
-------
C.I PARTICULATE EMISSION DATA
A majority of the participate emission data presented here is from
tests conducted by industrial boiler owners/operators. Other tests were
conducted by the EPA. Each site was given a letter designation upon
receipt of test data.
Data presented in Section C.I are organized into subsections, as
indicated on page C-l of Appendix C. Each subsection presents the
emission data for one type of control device. At the beginning of each
subsection the emission test data are presented in graphical form. The
first figure in each subsection is referred to as "support data".
Support data is emission test data considered to be representative of
the PM emission levels achievable with well designed, operated, and
maintained control devices. This support data is presented and discussed
in Chapter 4. If a second figure is shown in the subsection, it will
contain all of the test data presented in that subsection including the
data that, for various reasons, cannot be classified as support data.
Such factors as lack of information on critical control device operating
parameters or abnormal conditions during testing prevented some data
from being classified as support data. Documentation of such factors is
included in the description of each site. Site descriptions also include
boiler type, manufacturer, and rated capacity, type of particulate
control equipment, available design and/or operating parameters, and
particulate matter test method. Most tests were conducted in accordance
with EPA Method 5, but in some cases a high sample box temperature was
used to avoid SO., condensation, (see Appendix D). These cases are
C-3
-------
identified in the site descriptions. Since most of the tests were
conducted by different individuals, the same information is not available
for each site or test. Opacity data was available for a small number of
sites. Average opacity and test methods are stated.
Following each site description is an emission test summary sheet
which includes the data and time of the test, isokinetic sampling ratios,
and boiler load during testing. Stack gas data includes: velocity,
flow, temperature, pressure and percent moisture. Fuel analyses are
included when available and are for samples as received from suppliers
unless stated otherwise.
C-4
-------
C.I.I PARTICULATE EMISSION DATA FOR ELECTROSTATIC PRECIPITATORS
C-5
-------
O Individual Tests
-j- Average of Tests
V*
o —-
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(.070)
20
(.047)
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(.023)
Spreader Stokers
w/ Upstream MC
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*
T Pulverized Coal -Fired ,_
Boilers w/ No Upstream MC
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-------
Plant K
Three spreader stoker boilers were tested at Plant K. The rated
capacities of boilers 7, 8 and 9 are 92, 120 and 156 million Btu per hour
(thermal output), respectively. Each is controlled by a mechanical
collector placed in series with an electrostatic precipitator. The
design SCA for ESP's on boilers 7, 8, and 9 are 132, 152 and 128 ft2/103
acfm, respectively. The stack test reports were conducted for the
West Virginia Pollution Control Commission under Regulation II and in
accordance with EPA Method 5. Boiler Nos. 7 and 9 were operating above
100% capacity during testing while boiler No. 8 averaged 95% of capacity.
These operating capacities were calculated by using the orsat analysis
results and the "F" factor method as outlined in AP-42.
C-7
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PLANT K
Boiler # 7
TEST SUMMARY SHEETS (Particulates Only)
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of des
Operating SCA (ft2/10
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm^/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
lb/10" Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity
One
4.76
3.01
0.007
29239
12571
11.5
Two
Three
Average
ign)
3 acfm)
12/9/76
0954
99.4
103
12/9/76
105
12/9/76
0851
99.1
4.79
285.6
546
4.83
2.15
0.005
12576
12.07
o.nn?
28997
12467
11.98
C-8
-------
PLANT K
Boiler # 8
TEST SUMMARY SHEETS (Particulates Only)1
Test Number One Two Three Average
General Data
Date 12/7/76 12/7 12/7
Time 1155 0917
Isokinetic Ratio (%) 100.03 101.55 102.21 im.?fi
Boiler Load (% of design) 94 93 98 gs
Operating SCA (ft2/103 acfm) ifin
Gas Data
Velocity (mps) 8.84
Velocity (fps) 29
Flow (dnm^/min)
Flow (dscfm)
Temperature (°C) i .71
Temperature (°F) 340
Pressure (inches W.C.)
Moisture (%) 5.57 5.15 5.41 5.38
Particulate Emissions
g/dnm
Gr/dscf
ng/J fi 3.87 1.72 2.15 2.5?
lb/10° Btu 0.009 0.004 0.005 Q.QQf
Fuel Analysis
Heating Value (kj/kg) 29445 28805 29077
Heating Value (Btu/lb) 12659 12384 12501
0/0 Asn 9.98 12.25 11.38
% Sulfur
Average Opacity (%)
C-9
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PLANT K
Boiler # 9
TEST SUMMARY SHEETS (Particuletes Only)
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating SCA (ft2/103 acfm)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnnvVmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
99.8
102
lb/10v Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity
5.59
0.013
26816
11529
11.29
0.60
98.1
101
R.45
97.7
99
98.5
101
128
187.8
370
8.42
0.010
0.012
C-10
-------
Plant N
The ABMA, DOE & EPA conducted tests at Plant N to determine boiler
emissions and efficiency to help in the manufacture of more economical
and environmentally satisfactory boilers and control equipment.
Plant N has two identical spreader stokers, each with a capacity of
300,000 pounds of steam per hour. Only one unit was tested. It is
equipped with a mechanical collector and hot side electrostatic precipi-
tator in series.* In addition, fly ash from the mechanical collector
p
hopper is reinjected into the boiler.
All tests were conducted in accordance with EPA Method 5. Nine
tests were conducted at the mechanical collector outlet and four at the
ESP outlet. The four ESP outlet tests are presented here. The two low
load tests are averaged separately from the two high load tests.
\>L- /-i r\O
*The ESP design SCA is 344 ft^/10J acfm. Average operating SCA for the
low load tests was 634 ft /10 ?acfm, while the average operating SCA for
the high load tests was 542 ftVl(T acfm. Source: Kelly, M. E. (Radian
Corporation). Telephone conversation with P. J. Langsjoen (KVB). ESP
collector area. April 6, 1981.
C-ll
-------
PLANT N
Low Load Tests
TEST SUMMARY SHEETS (Participates Only)'
Test Number
One
Two
Three
Average
General Data
Date 8/30
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating SCA (ft2/103 acfm)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm-Vmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/0 c
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
20.46
67.13
1753.6
61920
8/31
.18-93
a
0.0174
0.0076
7.14
0.0166
23188
9969
549nn
7.45
0.0206
0.0090
8.34
0.0194
24074
10350
3.94
0.63
1Q.70
64.63
1654.?
58410
0-01Q
0.0083
7.74.
0.018
1.75
C-12
-------
PLANT N
High Load Tests
TEST SUMMARY SHEETS (Particulates Only)2
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating SCA (ft2/103 acfm)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnnrVmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J 6
lb/10° Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
571
24.07
78.97
1860.6
65700
7.59
0.0648
0.0283
24.77
0.0576
24502
10534
8.79
0.73
10/30
T05
_76
512
27.23
89.32
2073.0
73200
7.55
0.0334
0.0146
12.73
0.0296
105.5
76
542
25.65
84.15
7.57
0.0341
0.0149
18.80
0.0436
24676
10609
C-13
-------
Plant P
Plant P contains a Riley spreader stoker boiler with a rated capacity
of 200,000 pounds of steam per hour. It is equipped with a mechanical
dust collector and an electrostatic precipitator in series. Fly ash
from the boiler and mechanical collector hoppers is reinjected into the
2 3
boiler. The ESP has a design specific collection area of 349 ft /10
acfm. Two particulate emission tests were conducted at the ESP outlet.
Test No. 1 was conducted at 87% of design capacity and at low 02 conditions,
Normal 02 conditions existed during test No. 2 which was conducted at
3
89% of design capacity. Both tests were done according to EPA Method 5.
014
-------
PLANT P
TEST SUMMARY SHEETS (Participates Only)3
Test Number
One
Two
Three
Average
General Data
Date 2/16/78
Time
Isokinetic Ratio (%)
Boiler Load (% of design) 87
Operating SCA (ft2/103 acfm) 401
Excess Air (%) 25*
Gas Data
Velocity (mps) 16.0
Velocity (fps) 52.48
Flow (dnrrvvmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J fi
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
20.33
66.71
18.17
59.6
0.028
0.012
9.89
0.023
30659
13180
6.47
0.71
n.nifi
n.nn«
7-74
n.ni8
30240
13001
6.69
0.75
0.023
0.01
9.03
0.021
Low excess air test
(XI5
-------
Plant W
Three pulverized coal boilers (BB, PG & RC) were tested at Plant W.
Boilers BB ( 400 x 105 Btu/hr heat output capacity) and PG ( 400 x 106
Btu/hr heat output capacity) are equipped with separate electrostatic
precipitators. Exhaust gases are vented from the two ESP's to a common
stack. Boiler RC ( 540 x 10 Btu/hr heat output capacity) is equipped
with a separate ESP and stack. Outlet emissions for all boilers were
measured at the ESP outlet. The design SCA's are 300, 369 and 325
ft2/103 acfm for boilers RC, BB and PG, respectively.*
Two tests were conducted on each boiler. Boiler load during testing
averaged 86 percent of capacity at unit BB, 91 percent of capacity at
4 5
unit PG and about 80 percent of capacity at unit RC. *
*Kelly, M. E. (Radian Corporation). Telephone conversation with M. L.
Ransmeier (Champion Papers). ESP plate areas and design flow rates for
boilers PG, RC, and BB. April 7, 1981.
C-16
-------
PLANT W
Boiler RC
TEST SUMMARY SHEETS (Particulates Only)4'5
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Oxygen
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis^
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
9/26/79
10:15-11:30
102.79
72
374
9.35
8.0
0.0723
0.0316
26.96
0.0627
9/26/79
11:50-1:00
103.57
85
103.15
-2666^5
94155
1Q7 ft
9.69
7.7
0.0637
n.n?7Q
22.79
0.053
C-17
-------
PLANT VI
Boiler BB
TEST SUMMARY SHEETS (Particulates Only)4'5
Test Number
One
Two
Three
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnmVmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Oxygen
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
10/8/79
4:30-10:45
104.39
86
14.03
46.03
2175.7
171.7
7 '.5
0.0641
0.0280
23.65
0.0550
10/8/79
10:55-12:05
100.99
86
14.66
48.10
79,941
171
7.7
8.0
0.0303
0.0140
12.30
0.0286
102.69
86
14.35
47.07
2219.8
78.383
340.5
7.5
.7.7_
0.0210
18.06
0.04?
C-18
-------
PLANT W
Boiler PG
TEST SUMMARY SHEETS (Participates Only)4,5
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Oxygen (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
10/1/79
8:45-9:55
105.02
90.8
13.56
44.5
2050.0
72.386
161.7
323
11
7.0
0.0368
0.0161
T2T04
10/1/79
10:10-11:20
104.70
..8
0.0314
0.0137
10.96
0.0255
104.86
90.8
13.6R
44 -«7
74R7R
155.fi
0.0341
0.0149
11.61
0.027
C-19
-------
Plant Z
Four pulverized coal boilers (Nos. 25, 26, 27 and 29) with an
approximate capacity of 430,000 pounds of steam per hour each were
tested at Plant Z. Boiler Nos. 25, 26, 27 and 29 are all equipped with
separate mechanical dust collectors and Buell electrostatic precipitators.
p
Each ESP has a total plate area of 19,335 ft . The mechanical collectors
were not.in use during testing. The Buell ESPs were found to be more
efficient when the mechanical collectors were not operating. All tests
were done in accordance with EPA Method 5. Three test runs were conducted
at each of the five boilers. During testing, the ESPs provided an average
specific collection area of 98, 90, 96 and 98 ft2/103 acfm for boilers
25, 26, 27 and 29, respectively. The boilers were operating at or near
capacity. Therefore, the operating SCA's are equal to the design SCA's.
C-20
-------
PLANT Z
Boiler 25
TEST SUMMARY SHEETS (Participates Only):6
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating SCA (ft2/103 acfm)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm^/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J 6
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
12/5/78
8:23-9:32
100
15.61
-5TT?
3596.6
2.91
0.030
0.013
11.35
0.0264
12/5/78 12/5/78
10:03-11:15 11:35-12:44
99.6
98.7
6.71
0.039
0.017
14.84
0.0345
Ifi n
5? -4
35Qfi.fi
i?7,nnn
141
285
6.74
0.034
0.015
13.07
0.0304
99.2
"98"
6.80
0.034
0.015
13.07
0.0304
12
C-21
-------
PLANT Z
Boiler #26
TEST SUMMARY SHEETS (Particulates Only)6
Test Number
One
Two
Three
Average
271
General Data
Date 12/2
Time • 8:20-9:30
Isokinetic Ratio (%) 95.7
Boiler Load (% of design)
Operating SCA (ft2/103 acfm)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J c
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
7.85
0.076
0.033
28.77
0.0669
94.9
17.13
136000
138
280
~6786
0.076
0.033
28.77
0.0669
17.47
136000
142
287
"TT62
0.082
0.036
31.39
0.0730
1978
96.1
90
17.16
56.3
3823.2
135000
137
279
TM
0.078
0.034
29.67
0.0690
C-22
-------
PLANT Z
Boiler #27
TEST SUMMARY SHEETS (Particulates Only)6
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of des;
Operating SCA (ft2/10J acfm)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm-Vmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J f-
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
16.31
3794.9
134000
124
256
7.62
0.060
0.026
22.66
0.0527
16.19
53.1
7.76
0.048
0.021
19.69
0.0458
3681.6
130000
127
260
~7~85~
0.062
0.027
23.05
OT03T
1978
3738.2
132000
126
258
7.74
0.057
O2F
21.67
0.0504
12
*** T
C-23
-------
PLANT Z
Boiler #29
TEST SUMMARY SHEETS (Particulates Only)6
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of des- ..,
Operating SCA (ft2/103 acfm)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnnvVmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J c
lb/10° Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
11/an
11:37
95.9
3596.6
127000
133
271
7.48
0.025
0.011
8.99
0.0290
11/30
1:40
95.5
3568.3
126000
133
271
0.025
0.011
8.86
0.0206
96.6
3568.3
126000
133
271
7.51
0.023
0.010
8.17
0.0190
1978
96.0
"98
51.5
3568.3
126000
133
271
7.63
0.025
0.011
8.9
0.0207
12
~1
C-24
-------
Plant HHH
This 585 megawatt boiler/generator system supplies electrical power to
a central grid system. The boiler fires a high sulfur, high vanadium
residual oil and is typically base loaded at or near 560 megawatts.
Designed by combustion engineering the boiler is a controlled circulation,
tangentially fired (cyclone type) utility boiler. The design excess air
value is 3 percent. However, during the testing the excess air valves
ranged between 6.0 and 7.5 percent. This was reportedly normal boiler
operation. In general the boiler maintained steady state normal operation
throughout the testing period. Soot was blown continuously during the
emission testing.
Flue gas from two preheaters are directed to the Buell modular
electrostatic precipitator which is a split flow unit. After leaving the
precipitator, flue gases from both sides are combined and exhausted to a
common stack.
C-25
-------
PLANT HHH
Boiler No. 7
Method 5 - Low Temperature
TEST SUMMARY SHEETS (Particulates Only)
Test Number
One
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
0.086
0.038
2JLL_
0.065
Two
Three
Average
9/3D/B1
10:17-4^50
.9.8,0.
10/1/81
10:40.--2-;30
10.0.. 5_
1Q1.6_
10./2/81
9: 57^12-: 45
95. 6_
100.Z.
101.2.
297QO
1Q48QQ
183
36J
3Q80Q
1Q8600
183
361
106400
__12B
__3J52
0.090
C-26
-------
PLANT HHH
Boiler No. 7
Method 5 - High Temperature
TEST SUMMARY SHEETS (Particulates Only)'
Test Number
One
Two
Three
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Fart icu1ate Emission s
g/dnra3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Q.Q54
0.024
17.7
0.041
361
29100
102800
183
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
9/30/81
10:17-4:50
98.6
101.4
10/1/81
10:40-2:30
101.1
101.6
10/2/81
9 '57-12 '45
'loo.s'
100.7
100.2
101.2
29433
0.057
0.025
19.4
0.045
C-27
-------
C.I.2. PARTICULATE EMISSION DATA FOR FABRIC FILTERS
C-28
-------
$ EPA Sponsored Test
O Industry Test
J- Average of Tests
(.047P
m
O •— »
S £ —
-------
Plant C
Testing at Plant C was performed to gather emission information on a
boiler firing low-sulfur coal. The unit tested is a pulverized coal boiler
with a rated capacity of 250,000 pounds of steam per hour. Exhaust gas is
vented to a baghouse which contains eight compartments with 180 bags each.
The design air-to-cloth ratio is 2.26 to 1.
Three particulate emission tests were conducted in accordance with EPA
Method 5. The boiler operated normally and at full load while the tests
were in progress. During test number three, a soot blowing cycle was
o
included. Opacity, which averaged 2.5, was read according to EPA Method 9.
C-30
-------
PLANT C
TEST SUMMARY SHEETS (Particulates Only)
8
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating A/C (acfm/ftz)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnnr/min)
Flow (dscfm)
Temperature (°C)
Temperature ( F)
Pressure (inches W.C.)
Moisture (%)
Parti cul ate Emissions
g/dnm
Gr/dscf
ng/J 6
lb/10b Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
6/7/77
100.1
100
2.2
13.12
43.001
179.4
355.0
0.0442
O.J11231
14.45
{LD316
25723
11058
11.76
.57
2.5
Two
6/8/77
100.7
100
2.2
13.13
43.060
179.4
355.0
0.0406
0.01774
13.59
0.0316
25055
10771
10.78
.54
2.5
Three*
678/77
101.3
100
~12.5
41.803
179.4
355
0.0657
0.02871
18.41
0.0428
26263
11290
8.10
.47
2.5
Average
TOOTT
"Toy
12.99
42.623
179.4
355
0.0502
0.02192
15.48
0.0360
25681
11040
10.18
2.5
Soot blow cycle included.
C-31
-------
Plant J_2
Boiler nos. 3 and 4 at Plant J2 are Babcock and Wilcox spreader stokers,
with a combined steam generating capacity of 55 x 10 Ib/hr. Induced
draft fan vents flue gas from the two boilers to a common baghouse
2
(16,560 ft , four compartment Wheelabrator Frye baghouse), which has
2
design air-to-cloth ratio of 3.4 acfm/ft (three compartments in service)
2
and 2.5 acfm/ft (four compartments in service).
Three test runs were conducted on boiler no. 4 according to EPA
Method 5 in July 1979. The boiler averaged 27,500 pounds of steam per
9
hour, approximately 93% of capacity during the test run.
Soot blowing was conducted during test three on boiler no. 4 for about
seven minutes. Grain loading from that boiler was doubled without increasing
the grain loading at the filter outlet. Soot is normally blown once per day
for about 90 seconds per boiler.
C-32
-------
PLANT J2
TEST SUMMARY SHEETS (Participates Only)9'10
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating A/C (acfm/ft2)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm-Vmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J 6
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
4/16/80
104.2
25958
12LJ_
260.8
4.2
0.018
0.00743
9.99
.0230
5.87
<1
Two
4/17/80
104.3
.26672
122.7
252.9
5.0
Q.Q3Q
0.02039
0.0541
4.58
0.97
<1
Three *
4/17/80
104.1
2.3
134.1
273.3
4.1
0.016
0. 00707
0.0208
10.91
0.88
<1
Average
104.2
84-96
26476
128.0
262.3
4.6
0.0?1
0.00116
14.08
6.88
0.83
<1
Including a seven minute soot blowing cycle on boiler no. 4 during test three,
C-33
-------
Plant EE
Four spreader stoker boilers were tested at Plant EE. Boilers 2, 4, 5
and 6 have rated capacities of 64, 125, 181 and 241 million Btu per hour,
respectively, with steam capabilities of 50,000 100,000, 150,000, and
200,000 Ib/hr respectively. Each is equipped with a single stage multi-
cyclone mechanical collector followed by a baghouse. The baghouses on
boilers 2, 4, 5 and 6 use pulse jet cleaning. The baghouse on boiler 2
is 12x12x40 feet with five compartments containing 490, 6.25 inch diameter
2
by 9 feet, bags. The filter cloth area is 7,400 ft providing an air-to-
2
cloth ratio of 3.4 acfm/ft . There are two baghouses on boiler 4, each
12x12x30 feet total with six compartments containing 840 bags, 6.25 inch
2
diameter by 9 feet. The total filter cloth area is 12,600 ft providing
2
an air-to-cloth ratio of 3.7 acfm/ft . Boiler 5 is equipped with two
baghouses, each 12x12x40 feet with six compartments containing 1176 bags,
6.25 inch diameter by 9 feet. The total filter cloth area is 17,600 ft
9
providing an air-to-cloth ratio of 3.7 acfm/ft . Boiler 6 has two
baghouses, each 12x12x50 feet. Six compartments containing 1512, 6.25
2
inch diameter by 9 feet, bags provide a total filter area of 22,700 ft .
2
This provides an air-to-cloth ratio of 3.8 acfm/ft . The baghouses for
boiler 2, 4, 5 and 6 are designed for airflows at 350°F of 25,000,
46,000, 65,000 and 86,000 acfm respectively. Exhaust gas from boilers
2 and 4 is vented to stack no. 1. Gas from boilers 5 and 6 is vented
to stack no. 3 .
Three compliance tests were conducted at each boiler under Regulation
II, (1974) for the State of West Virginia Air Pollution Control Commission.
C-34
-------
Chemical analysis performed on the participate captured during testing
on boiler 6 revealed that close to 50 percent of the catch was sulfate.
This sulfate would not have been present had the filter and probe been
maintained at 275°F (above the acid dew point). Therefore, all test
results for boiler 6 have been removed from the support data figures.
Prior to testing boiler number 5, the baghouse was inadvertantly
"overcleaned", resulting in a higher than normal three day average
emission rate. Emissions diminished over the three day test period
with equilibrium reached in between tests 2 and 3. For this reason test 1
has been eliminated from the support data figures, and from calculation
of the average values reported in the Test Summary Sheet.
The stack opacities were consistently less than 10 percent on the
Lear-Seigler monitors mounted on the breeching at the entrance to the
stacks.
C-35
-------
PLANT EE
Boiler #2
11
TEST SUMMARY SHEETS (Participates Only)
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Q£ (% by volume, dry basis)
Operating A/C (acfm/ft2)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm-Vmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J fi
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
3/16/76
1:00
102.4
98.2
6.0
3.46
5.5
8.6
0.020
31294
13454
~TM
<10
Two
3/16/76
10:00
103.6
98.2
6.5
3.46
6.45
0.015
31622
13595
6.79
2.8
<10
Three
3/16/76
9:15
101.1
99.6
6^4
3.41
4.86
0.009
3?13fi
13816
6.47
2.65
<10
Average
102^4
98.7
6.3
3.44
5.27
6.45
0.015
^1684
13622
6.90
2.75
<10
C-36
-------
PLANT EE
Boiler #4
TEST SUMMARY SHEETS (Participates Only)
11
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
02 (% volume, dry basis
Operating A/C (acfm/ft^
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm^/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J 6
lb/10° Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
3/24/76
1620
6.69
2.9
3/25/76
1015
93
77.3
6.0
2.9
77.2
2.89
5.4
n.mn
31490
13538
6.64
2.65
n.nn7
4.3
0.010
31403
13501
7.0
2.6
C-37
-------
PLANT EE
Boiler #5
TEST SUMMARY SHEETS (Particulates Only)
11
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
02 (% volume, dry basis]
Operating A/C (acfm/ft^]
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnnr/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
11/4/75
1200
93.54
96.5
5.58
3.6
6.21
U/6./I5
1140
96.4
96.4
5.41
3.6
6.R5
-5.^37-
3.6
6 RE
g/dnm
Gr/dscf
ng/J fi
lb/10° Btu
Fuel Analysis
Heating Value
Heating Value
% Ash
% Sulfur
Average Opacity
(kj/kg)
(Btu/lb)
(%)
58.48
0.136
31729
11641
6.98
3.0
^
16.34
0.038
32245
13863
6.46
2.92
-"-
7.74
0.018
31948
13735
6.44
2.98
< 10
12.04
0.028
32Q2Z
I3Z22.
6.45
2.95
< 10
* This test not included in the support data figures. Prior to testing
baghouse was "overcleaned1 resulting in higher than normal emission rate.
C-38
-------
PLANT EE
Boiler #6*
TEST SUMMARY SHEETS (Particulates Only)
11
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
0? (% volume, dry basis;
Operating A/C (acfm/ft
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm^/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Parti cul ate Emissions
g/dnm
Gr/dscf
ng/J A
lb/10° Btu
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One Two
12/17/75 12/18/75
1712 1050
103.3 104.41
98.3 98.9
5.23 4.72
3.7 ~1T8~
30.53 7.74
0.071 0.018
30878 30899
13275 13284
7 27 7 97
/ • t / / » y i
2Q1 O QQ
• o 1 L » oo
•<10 <10
Three
12/18/75
20:02
103.11
98
4.98
18.92
0.044
31029
13340
7.03
2.88
<10
Average
q«.4
4.Qfi
6-11
18.92
0.044
30936
13300
7.42
<10
* This data is not included in support data figures.
was not maintained during tests.
Proper probe temperature
C-39
-------
Plant JJ
Plant JJ contains a nine compartment baghouse which cleans the flue
gas from three spreader stokers. These stokers have a combined capacity
of 260,000 Ib/hr of steam. All of the stokers utilize fly ash reinjection
techniques. At maximum capacity the baghouse has an air-to-cloth ratio
2
of 3.38 acfm/ft . These boilers primarily produce steam for space
heating. In warm weather these boilers each produce as low as 30,000
Ib/hr of steam. The boilers produce as much as 180,000 Ib/hr in cold
weather.
Three tests were run with the pulse-jet cleaning mode. Three
additional tests were run with the reverse-air cleaning mode. Particulate
emission tests were conducted in accordance with EPA Method 5 while
opacity readings were taken according to EPA Method 9 . The tests were
carried out in April and are therefore at relatively low loads (25-31%
of design). Because very low load operation may not be representative
12
of normal operation these tests are not included in support data figures.
The opacity data were used in the opacity section.
C-40
-------
PLANT JJ
TEST SUMMARY SHEETS (Participates Only)
Pulse Jet Cleaning Mode
12
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating A/C (acfm/ft2)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm^/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Oxygen (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J r
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
4/4/77
1.0
538
19.000
318
5.7
10.8
0.016
0.007
8.6
0.020
27186
11,688
10.65
2.07
Two
4/5/77
97.6
31
1.1
21,800
333
5.3
9.6
n.nn
n.nns
5.6
0.013
10.65
1.79
0
Three
4/5/77
98.8
30
1.0
583
20.600
337
5.8
8.8
n . rm
n.niR
0^036.
26954
11.36
Average
30
1.0
_5.Z9_
2Q.5QQ
?7Q
9.7
0 021
Q.QQ9
Q.Q23
2Z.T53-
11674
in.fifi
* Due to low load operation these tests are not included in the support
data figuress but they are included in the opacity section.
C-41
-------
PLANT JJ
TEST SUMMARY SHEETS (Particulates Only)
Reverse Air Cleaning Mode
12
Test Number
General Data
***•'
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating A/C (acfm/ft2)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm^/min)
Flow (dscfm)
Temperature (°C)
Temperature ( F)
Pressure (inches W.C.)
Moisture/%)
Oxygen (%)
Parti cul ate Emissions
g/dnm
Gr/dscf
ng/J 6
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
4/6/77
97.2
31
1.1
615
21.700
332
5.1
10.5
n.nnq
Q.QQ4
Q.on
?ann3
IPMQ
8.QQ
1.86
Two
4/7/77
96.5
26
1.0
507
17.900
325
5.7
9.7
n.009
Q.QQ4
4.3
0.010
2550J1
10963
7.81
1.64
0
Three
4/7/77
97.3
25
1.0
17.900
315
5.1
11.4
0.007
0.003
3.9
0.009
27980
12D22.
8.91
0
Average
97.0
i.Q
543
19,200
324
5.3
10.5
0.009
0.004
4.3
0.010
.27161
11677
8.24
1.68
<1
* Due to the low load operation, this data is not included in the support
data figures.
C-42
-------
Plant KK
Plant KK has two pulverized coal-fired boilers. Boiler 7?with a
rated capacity of 260,000 Ib/hr steam, was tested. Fly ash is removed
by a ten-compartment baghouse. The baghouse is designed to handle a
flue gas flow of 165,000 acfm between 270 and 500°F, with a pressure
drop of 8 inches W.G. Each compartment of the baghouse contains 96,
11.5 inch diameter by 30 feet, bags, providing a total filter area of
2 2
86,708 ft . This provides a design air-to-cloth ratio of 1.9 acfm/ft .
Test runs were made both with normal excess air to the boiler and
with low excess air to the boiler. All tests were conducted in
10
accordance with EPA Method 5. Boiler loads ranged from 67 - 83 percent
of design with all tests but one conducted at loads above 75 percent of
design. Tests at loads less than 75 percent were not included in the
support data figures.
C-43
-------
PLANT KK
TEST SUMMARY SHEETS (Particulates Only)
Low Excess Air Tests
13
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating A/C (acfm/ft2)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfni)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture,J%)
Oxygen (%)
Particulate Emissions
g/dnm
Gr/dscf
ng/J f.
lb/10° Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
6/7/79
65
1.3
10.1
69947
152
305
TA
12.8
O.Q30
10160
14.95
0.73
0
Two
6/8/79
64
10.3
33.8
71646
149
300
7.0
8.4
(LJQ20_
10160
14.SS.
-*-
Three
6/12/79
63
10.2
33.5
74847
"~T49~
300
7.1
7.8
0.018
10160
14.95
0.73
0
Average
7/11/79
64
1.3
in 1
33
_ZQ233
160
320
7.8
JLS_
0.006
1D9JO-
_7.36_
0.30
_o_
Due to low boiler loads all low excess air tests are not included in the
support data figures, but they are used in the opacity section.
C-44
-------
PLANT KK
TEST SUMMARY SHEETS (Participates Only)
Low Excess Air Tests
13
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%}
Boiler Load (% of design)
Operating A/C (acfm/ft2)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnrrrYmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Oxygen (%}
Particulate Emissions
g/dnm
Gr/dscf
n9/J fi
lb/10° Btu
F_ueJ Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity
7/11/79
71
1.5
11.9
82816
160
320
O.QQ7
10910
7.36
0.30
7/12/79
1.4
10.7
7622<
JI60.
320
7.6
(LDJQS.
10910
7.36
0.30
0
10.5
74411
155
311
'.4
n.nna
10535
0
* Due to low boiler loads, all low excess air tests are not included in the
support data figures, but they are used in the opacity section.
C-45
-------
PLANT KK
TEST SUMMARY SHEETS (Participates Only)
Normal Excess Air Tests
13
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating A/C (acfm/ft2)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnirvVmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Oxygen (%)
Parti cul ate Emissions
g/dnm
Gr/dscf
ng/J fi
lb/10D Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One Two* Three* Average
• 6/14/79 7/10/79 7/10/79
-fy- -f7^ — f-, -fV
13.9 11.9 JU^4_ 12.4
45.5 39.0 37.3 4D.7
96029 84315 79550 86628
155 161 169 161
310 321 335 322
8.1 8.2 8.3 8.3
7.8 6.4 4.3 6.2
0.018 OJ)15_ Q.QUL 0.014
10160 LQ9_10_ 10910. .10660
14.95 7.36 7.36 9.8Q
0.73 0.30 0.30 Q.44
0000
* Due to low boiler loads these tests are not included in the support
data figures , but they are used in the opacity section.
C-46
-------
Plant K2
Plant K2 consists of a 100,000 Ib/hr coal/limestone feed fluidized-bed
boiler (FBB). The FBB is a two-bed, single-cell, top-suspended, balanced
draft, natural circulation boiler capable of generating steam at 275 psig
2
for delivery into the steam header for heating and cooling of 204,000 m of
building space. Saturated steam at 625 psig can also be produced for
delivery into the header through a pressure regulation valve, with
provisions for future cogeneration of electrical energy.
The design and operation of the FBB is based on classical fluidized-bed
principles; i.e., use of low superficial velocity in the range of 1.2 to
24 m/sec (4 to 8 ft/sec), and primary recirculation of entrained solids to
the combustion chamber. Coal is fed into each bed using separate
conventional spreader stoker overbed feeders. Limestone is fed by gravity
at a single point in each bed. Design parameters for the FBB include:
- Bed Dimensions 19'-4" x ll'-O (2 segments)
- Coal Type Bituminous
- Bed Temperature 1,594°F
- Fluidizing Velocity 8 ft/sec
- Ca/S Ratio 3
- Efficiency (Thermal) 83.51%
- Reinjection Flow 7,500 Ib/hr
Particulate control is effected by passing flue gas through a
multicyclone (primary control) and baghouse (final control). Fly ash from
the multicyclone hopper is reinjected on a continuous basis. The test
report for Plant K2 supplied no design data for the particulate control
devices.
Two or three boiler/baghouse operating conditions may have increased
particulate emission rates to higher than expected rates, as measured on
-------
August 23. Factors which may have increased baghouse inlet loadings include
inefficient multicyclone performance due to clogging and excessive bed
elutriation induced by injection of overfire air near the top of bed A.
Baghouse efficiency may have been lower than design (inlet concentrations
were not measured using EPA reference method procedures) due to bag
punctures and apparent blinding of the Teflon bags interspersed throughout
several baghouse compartments.
Prior to measurements made on September 13, several damaged bags were
replaced and baghouse performance improved.
C-48
-------
PLANT K2
TEST SUMMARY SHEETS (Particulates Only) 53
Test "lumber
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
8-23-81 8-23-81 8-23-81
96.7
53.6
95.9
52.0
98.6
51.0
97.1
52.;
Gas Data
Excess Air (%)
Velocity (mps)
Velocity (fps)
Flow (dnrrH/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Oxygen (%)
Particulate Emissions
3
g/dnm
gr/dscf
ng/J r
lb/10° Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
117.9 117.9 117.9
11.5
11.5
18890 19245 18?96
170 170 169
11.5
47.04 37.79 24.58
0.1094 0.0879 0.0572
117.9
1RS10
170
11.5
36.5
0.0848
12914
13.3
1.44
C-49
-------
PLANT K2
TEST SUMMARY SHEETS (Participates Only)53
Test Number One Two
General Data
Date 9-13^81 9^13-81
Time
Isokinetic Ratio (%) 98.6 98.4
Boiler Load (% of design) 54.0 47.0
Gas Data
Excess Air (%) 89.5 97.3
Velocity (mps)
Velocity (fps)
Flow (dnrrP/min)
Flow (dscfm) 17,607 18,121
Temperature (°C) 176 176
Temperature (°F) 348 349
Pressure (inches W.G.)
Oxvqpn W 8.9 8.0
Parti cul ate Emissions
g/dnm
gr/dscf
ng/J 6 32.31 20.92
lb/10 Btu 0.0751 0.0487
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Three Average
9_zl_3-_81
98.4 95 if
50.0 50.3
97.3 94.7
18,177 17,968
176 176
349 349
8.0 8.3
19.62 24.28
0.0456 0.0565
12,952
12.8
2.20
C-50
-------
C.I.3 PARTICULATE -EMISSION DATA FOR MECHANICAL COLLECTORS
C-51
-------
O Industry Test
4- Aver»ge of Tests
600
(1.39)
500
(1.16)
V)
J £• 400 ^_
S fe (0.93F
** A
3 ^ 300__
S 1 (0.70)
O.
200 _
(0.47)
100_
(0.23F
Spreader Stokers with
Fly Ash Relnjectlon
8 . 9
0
I i
o ? T
A 9
f T
0
SP without Fly Ash
Relnjectlon
?
i
1
*
o
, Other Stokers without .
Fly Ash Relnjectlon
?
0 f |
1
@
£ ? ^.
till i i ill i i i i i i
Plant AAPNAANPAAPAA UU UU AA R HH R R HH H
Boiler No. . G--G--G-G - - G - - - -
Boiler Typeb SP SP SP SP SP SP SP SP SP SP SP SP VG CG VG VG CG U
Design Capacity 75 200 300 75 300 200 75 200 75 160 160 75 90 70 90 90 70 35
(10^ Ib steam/hr)
Operating Capacity 16- 47 37- 57 60- 73- 76- 81- 97- 55- 59- 98 45 48- 61- 79- 73- 77-
(X of Design) 17 59 74 79 86 100 102 60 60 50 69 89 103 90
Fuel Sulfur (Wt 1) 0.92 0.84 0.77 0.75 0.91 0.92 0.72 0.90 0.90 - 0.75 2.23 1.82 2.26 1.89 1.65 0.57
Fuel Ash (Wt «) 7.3 8.9 7.2 8.3 5.3 7.4 7.5 8.0 6.8 - - 8.3 8.2 9.0 8.1 7.2 7.0 8.1
Figure C.I.3-1. Mechanical collector emission data.'
aA11 tests ordered from left to right by Increasing operating capacity
bSP-spreader stoker, VG-vlbratlng grate stoker. CG-chaln grate stoker, U-underfeed
C-52
-------
Plant H
Particulate emission tests were conducted at Plant H to determine
the degree of compliance with Ohio participate emission codes. The
tested unit (boiler no. 1) is a Babcock and Wilcox underfeed stoker with
a rated capacity of 35,000 pounds of steam per hour. It is equipped
with a Zurn Air Systems multiclone dust collector followed by an induced
draft fan. The pressure drop across the multiclone collector is three
inches of water. Tests were conducted in accordance with EPA Method 5.
14
Boiler load averaged 82 percent of the rated capacity.
C-53
-------
PLANT H
TEST SUMMARY SHEETS (Particulates Only)14
Test Number One Two Three Average
General Data
Date 7/26/18 7/26/78 7/26/78
Time
Isokinetic Ratio (%) 103.1 101.8 102.6 10?, R
Boiler Load (% of design) 90.3 76.6 78.9 ft] q
Gas Data
Velocity (mps) • 3.14 2.84 2.87
Velocity (fps) 10.3 9.3 9.4
Flow (dnmVmin) 384.6 351.6 358.4 365.0
Flow (dscfm) 13581.7 12416.7 12565.7 1 ?ftftfl 4
Temperature (°C) 217.1 214.3 209.3 213.6
Temperature (°F) 422.8 417.8 408.8 416.5
Pressure (inches W.C.)
Moisture (%) 6.3 6.0 6.0 6.1
Particulate Emissions
g/dnm3
Gr/dscf
ng/J 38.7 30 1 ?5.8 31 4
lb/106 Btu 0.09 0.07 n.f!6 Q Q73
Fuel Analysis
Heating Value (kj/kg) 31710
Heating Value (Btu/lb) 13633
% Ash 8.11
% Sulfur 0.57
Average Opacity (%) <5 <5 <5
C-54
-------
Plant N
The ABMA, DOE & EPA conducted tests at Plant N to determine boiler
emissions and efficiency to help in the manufacture of more economical
and environmentally satisfactory boilers and control equipment.
Plant N has two identical spreader stokers, each with a capacity of
300,000 pounds of steam per hour. Only one unit was tested. It is
equipped with a mechanical collector and electrostatic precipitator in
series.
All tests were conducted in accordance with EPA Method 5. Nine
tests were conducted at the mechanical collector outlet and four at the
ESP outlet. Results from tests conducted at the mechanical collector
outlet are presented here.
Because boiler load varied from 37 to 85 percent of capacity, the
series of 9 tests were divided into two sets of data. Low load tests
(below 59%) and higher load tests (60 percent and above) are segregated
2
and averaged separately in the following test summary sheets .
C-55
-------
PLANT N
Low Load Tests
TEST SUMMARY SHEETS (Particulates Only)2
Test Number
One
Two
Three
MC Outlet
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (raps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
6.2
0.455
0.199
230.9
0.537
24435
10505
7.70
0.92
3.1
8/30
11.44
1706.0
602'
9.27
0.593
0.259
220.2
0.512
23188
9969
6.79
0.62
2.5
104
48
10.3
33.69
1564.1
55230
0.524
0.229
225.6
0.525
23811
10237
7.25
0.77
28
C-56
-------
PLANT N
Normal Load Tests
TEST SUMMARY SHEETS (Particulates Only)2
Test Number
One
Two
Three
Four
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
8/11/77
111.4
61
10.14
33.25
1537.8
54300
8.92
0.329
250.26
OBT
24533
10547
6.09
0.93
8/18/77
8/18/77
60
11.38
1709.4
60360
8.76
CLI25J
0.317
277.78
0.646
108
72
11.75
38.54
1723.0
60840
0.373
283.8
0.660
10588
5.21
1.02
108
41.95
1860.6
9.40
1.101
0.481
407.64
0.948
P4533
10547
6.09
0.93
K
This fuel analysis is not based on grab samples taken during the test
It is based on an average proximate analysis conducted on a coal stockpile.
C-57
-------
PLANT N
Normal Load Tests
TEST SUMMARY SHEETS (Participates Only)2
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Five
8/26
95
1875.09
66240
9.67
0.455
285.1
0.663
25074
10780
4.49
0.9
3.4
Six
8/27
102
12.55
41.16
1819.8
64260
8.89
0.789
0.315
246.0
24579
10567
6.13
0.86
Seven
10/6
101
13.95
45.78
1984.7
70080
11.77
0.33R
0.600
23638
10158
0.77
6.9
MC Outlet
Average
104
12.2
40. Q
1754 4
-6J.9-5Q
0.658
0.356
287
0.667
24511
10538
5.32
0.91
C-58
-------
Plant P
Plant P contains a Riley spreader stoker boiler with a rated
capacity of 200,000 pounds of steam per hour. It is equipped with a
mechanical dust collector and an electrostatic precipitator in series.
Results from tests conducted at the mechanical collector outlet are
presented here.
The mechanical dust collector is a UOP Design 104 with 140 ten-inch
tubes. Fly ash from the dust collector hopper and economizer was
reinjected back into the boiler during all tests. Nine tests were
performed during which the boiler fired a Kentucky Cumberland coal.
3
Boiler load during testing averaged 78 percent.
Because boiler load varied from 47 to 100 percent of capacity, the
series of 9 tests were divided into three sets of data: high, medium
and low load tests. The data in each set are averaged and presented
separately in the summary figures at the beginning of this section. One
low load test (47%) is presented alone, while a second set consists of
all tests conducted between loads of 73 to 79 percent of capacity. The
third set consists of all tests run between 81 to 100 percent of capacity,
C-59
-------
PLANT P
Multiclone Outlet
TEST SUMMARY SHEETS (Particulates Only)3
Test Number
Jj5W-=kQ.a(i.Jest
One
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Endssions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Two
Three
Average
47
7.43
24.3,9
0^155
0.199
192
0.446
31339
13485
_8^5_
0.84
C-60
-------
PLANT P
Medium Load Tests
TEST SUMMARY SHEETS (Particulates Only)J
Test Number One Two Three Four
Cenejal _D_a_ta
Date
Time
Jsokinetic Ratio (%)
Boiler Load (% of design) 73 75 _71__ _73
Gas Data
Velocity (mps) 10.31 JL1.S5 9.71 .JLLfll
Velocity (fps) 32JJ2_ 39.23 1Z.U _31_.J_2
Flow (dnm3/min)
Flow (dscfm)
Tompcrature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Part_ic^_l_a_te_ Emissions
g/dnm3 Q.618 Q.746 0.602 0.670
Gr/dscf Q.270 0.326 0.263 0.293
ng/J 241 357 223 254
lb/106 Btu 0.561 0.830 0.518 0.591
Fuel Analysis
Heating Value (kj/kg) 30147 30470
Heating Value (Btu/lb) 12972 13111
% Ash 8.22 8.83
% Sulfur 1.06 1.05 0.93 0.68
Average Opacity (%)
C-61
-------
PLANT P
Medium Load Test
TEST SUMMARY SHEETS (Particulates Only)
Test Number
Five
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
75
9.23
30.28
0.713
0.311
242
0.563
30479
13115
8.00.
0.87
Average
75
10.46
33.31
Q.67Q
0.293
263
0.613
30629
13180
7.36
0.92
C-62
-------
PLANT P
High Load Tests
TEST SUMMARY SHEETS (Particulates Only)3
Test Number
One
Two
Three
Average
G c ner_al_D a_ta_
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnra3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
10.85
35.60
0.387
0.169
147
0.343
30951
13318
~5T8T
"078T
13.50
44.29
0.584
0.255
209
0.485
30391
13077
7.60
0.91
inn
13.33
.43.7?
..33—
30033
12923
10.66
0.91
C-63
-------
Plant R
Plant R contains a Babcock and Wilcox vibrating grate stoker (Boiler D)
equipped with a UOP multiclone dust collector. Boiler D has a rated
capacity of 90,000 pounds of steam per hour. Sixteen particulate emission
tests were conducted at this unit using three different coal types.
This series of tests is divided into three sets of data: low,
medium and high load tests. The data in each set are averaged and
presented separately from the other sets. Overfire air pressure was
varied at low, medium and high boiler loadings. One test was conducted
at low load with overfire air pressure at 10 inches of water. Eight
medium load tests were conducted with overfire air pressure varying from
5 to 13 inches of water. Six tests were conducted at high load.
Overfire air pressure varied from 7 to 15 inches of water. All tests
15
were carried out in accordance with EPA Method 5. Opacity was determined
with a transmissometer.
C-64
-------
PLANT R
Low Load Test
TEST SUMMARY SHEETS (Particulates Only)
15
Test Number
General Data
Date
Time
Tsokinetic Ratio (%)
Boiler Load (% of design)
Overfire Air Pressure
c^.?. Data (inches
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulaj:_e_ Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
Two
Three
Average
3.30
10.82
____
0.138
1W70S
0.456
30396
1_3068_
8^24_
2.23
C-65
-------
PLANT R
Medium Load Tests
TEST SUMMARY SHEETS (Particulates Only)15
Test Number One Two Three Four
General Data
Date 8/3 8/15 8/22 8/18
Time
Isokinetic Ratio (%)
Boiler Load (% of design) 69 64 63 65
Overfire Air Pressure fin.
/> ^ u r\\ b 615
Gas Data
Velocity (tups) 5.67 4.07 4.72 4.19
Velocity (fps) 18.59 13.36 15.5 13.74
Flow (dnm3/min) '
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3 Q.288 0.476 0.384 0.325
Gr/dscf Q.126 0.208 0.168 0.142
ng/J 152.65 239.57 209.84 159.96
lb/106 Btu Q.355 0.557 0.488 0.372
Fuel Analysis
Heating Value (kj/kg) 29854 30426 30187 30317
Heating Value (Btu/lb) 12835 13081 12978 13034
% Ash 9.26 8.08 9.0 8.83
% Sulfur 2.54 2.79 2.57 2.85
Average Opacity (%) - 30 _J1_ 12
C-66
-------
PLANT R
Medium Load Tests
TEST SUMMARY SHEETS (Participates Only)
15
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Overfire Air Pressure (in.
H20)
Gjis__Da_ta_
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
ic ulate Emissions
3
Five
g/dnm
gr/dscf
ng/J r
lb/10D
Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
66
10
-5.-2JL
17.09
0.270
0.118
141.04
0.328
30433
13084
8.65
2.59
12
Six
8/31
_62_
10
4.28
0.291
0.127
152.22
0.354
30282
13019
8.13
2.50
Seven
Eight
_J54_
4.46
14.62
0.319
31685
13627
5.89
12
1.11
12
61
4.17
13.67
0.469
0.205
255.85
0.595
31068
13357
6.96
Average
1.11
11
64_
"9.4
4.60
1508
13
c-e;
-------
PLANT R
High Load Tests
TEST SUMMARY SHEETS (Participates Only)
15
Test Number
One
Two
Three
Four
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Overfire Air pressure
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
9/6
5.29
17.37
0.613
0.268
287.8
0.667
29854
12935
9.14
2.82
19
9/8
Q.485
0.212
210.7
0.490
29864
12839
9.57
2.94
29
Q/1?
4.56
14.97
0.753
0.329
324.22
0.754
31034
13342
6.86
2.04
35
32166
13829
4.92
1.15
19
C-68
-------
PLANT R
High Load Tests
TEST SUMMARY SHEETS (Particulates Only)
15
Test Number
Five
Six
Seven
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Overfire Air pressure
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
4.90
16.07
0.563
0.246
246.82
0.574
30317
13034
8.47
2.44
23
9/14
10
5.??
17.14
0.403
0.176
168.99
9/15
normal
Fi.51
18.09
_3_2_
IL4Q3
n.17fi
JLS_LH3
0.421
31778
13662
5.99
0.98
19
5.1?
16.81
0.519
Q.??7
-228-8.4
0.532
30979
1.89
C-69
-------
Plant AA
Plant AA contains a Zurn spreader stoker (Boiler G) rated at
75,000 pounds of steam per hour. The overfire air system consists of
three rows of air jets, one lower row on the front wall and an upper and
lower row on the rear wall. Fly ash is reinjected. Exhaust gas from
this boiler is vented to a UOP mechanical dust collector.
Fifteen particulate emission tests were conducted at this site in
accordance with EPA Method 5. Boiler capacity varied from 15% to 100%
of design capacity. The series of 15 tests are divided into four sets
of data: low, medium, intermediate and high load tests. The data in
each set are averaged and presented separately from the other sets.
Particulate emissions were well above average during tests where
boiler loads averaged 17% of design (low load tests). During test
number 10 fly ash was not reinjected and the particulate emission rate
(.364 lb/10 Btu) was above average. Two tests (numbers 2 and 15) were
conducted under low overfire air conditions. No effect on particulate
emission rate was shown. All other tests were conducted under normal
conditions except test number 5 in which boiler load was 57% of capacity.
The lowest particulate emission rate (.129 lb/10 Btu) was experienced
16
during this test.
C-70
-------
PLANT AA
Low Load Tests
TEST SUMMARY SHEETS (Particulates Only)16
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
* No Flyash Reinjection
16
8.75
0.435
Q.19Q
401.19
0.933
29933
12869
JL32.
0.75
10.60
0.476
0.208
409.79
.9!
32238
13860
6.56
1.31
8.40
27.57
0.229
Q.1QO
212.85
0.495
29803
12813
6.95
0.69
9.24
30.33
C-71
-------
PLANT AA
Medium Load Test
TEST SUMMARY SHEETS (Particulates Only)16
Test Number One Two Three Average
General Data
Date
Time ^^^ ZZZZ
Isokinetic Ratio (%)
Boiler Load (% of design) 57 ^^
Gas Data
Velocity (mp.s) 15.33
Velocity (fps) 50.28
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%) •
Particulate Emissions
g/dnm3 0.105
Gr/dscf 0.046
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg) 29933
Heating Value (Btu/lb) 12869
% Ash
% Sulfur
Average Opacity (%)
C-72
-------
PLANT AA
Intermediate Load Tests
TEST SUMMARY SHEETS (Participates Only)
16
Test Number
One
Two
Three
Four
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (nips)
Velocity (fps)
Flow (dnm3/roin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
18.42
60.42
29803
12813
6_.95_
0.69
19.17
62.88
0.195
0.085
95.03
0.221
0.69
19.08
62.61
80
19.09
62.64
0.279
0.122
JLLU8
0.260
Q.093
94.fi
0.??Q
_29_9_3J3
12869
8.32
0.75
* Low overfire air
C-73
-------
PLANT AA
Intermediate Load Tests
TEST SUMMARY SHEETS (Participates Only)
16
Test Number
Five
Six
Seven
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnmVmin)
Flow (dscfm)
Temperature (°C)
Temperature (CF)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
82
20.61
67.62
0.311
0.136
143.62
0.334
29803
12813
6.95
0.69
19.27
63.21
0.195
0.085
95.46
0.222
29933
12869
0.75
20.08
65.87
0.458
0.200
208.12
0.484
29933
12869
8.32
0.75
19.32
63.61
0.282
0.123
126.6
0.294
C-74
-------
PLANT AA
High Load Tests
TEST SUMMARY SHEETS (Particulates Only)
16
Test Number
One
Two
Three
Four Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
21.63
70.96
98
20.93
68.65
0.325
0.142
137.6
0.320
29803
12813
6.95
Q.69
?9Q33
12869
8.32
0.75
100
20.78
68.19
0.166
3??38
13860
6.56
1.31
102
20.00
65.63
2Q803
12813
6.95
0.69
99
20.84
68.36
0.289
30444
13089
7.20
0.86
No fly ash reinjection
C-75
-------
Plant HH
Plant HH contains a Keeler traveling chaingrate stoker boiler with a
rated capacity of 70,000 pounds of steam per hour. There are two rows
of overfire air (OFA) jets on the front wall. At maximum flow the OFA
pressure is about 10 inches of water. Particulate emissions are
controlled by a mechanical dust collector.
Eight tests were conducted according to EPA Method 5 to determine
the particulate emission rate. Overfire air pressure was varied from
0.8 to 7.8 inches of water. Boiler load ranged from 48 to 100 percent of
17
rated capacity. The series of 8 tests were divided into two sets of
data: low and high load tests. The data in each set are averaged and
presented separately from the other sets.
C-76
-------
PLANT HH
Low Load Tests
TEST SUMMARY SHEETS (Particulates Only)
17
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Over fire Air pressure (in
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
6/3/70
0.103
Q.Q45
49.45
0.115
31569
13572
1.06
6/16/79
5.92
19.41
0.124
0.054
79.55
0.185
29101
12511
11.76
2.57
48.9
1.55
0.11
0.050
64.50
0.150
30335
13042
9.04
1.82
C-77
-------
PLANT HH
High Load Tests
TEST SUMMARY SHEETS (Particulates Only)
17
Test Number
One
Two
Three
Four
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Overfire Air Pressure (in.
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
6/15/79
73.1
6.53
21.42
0.108
0.047
49.02
0.114
1.40
6/4/6Q
fi/14/79
6/20/79
0.149
0.065
80.84
0.188
D.153
0.067
71.81
0.167
0.089
96.32
0.224
30473
13101
8.23
1.82
C-78
-------
PLANT HH
High Load Tests
TEST SUMMARY SHEETS (Particulates Only)
17
Test Number
Five
Six
Seven
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Overfire Air Pressure (in.hLO)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
98.6
4.0
9.66
31.69
0.179
32485
13966
4.18
1.30
102.6
7.8
19.10
62.67
0.211
0.092
98.04
0.228
29238
12570
10.22
2.18
0.167
0.073
79.05
0.184
Average Opacity (%)
-------
Plant UU
Plant UU has a Babcock and Mil cox stoker with a rate capacity
of 160,000 pounds of steam per hour. It is equipped with a multiclone
mechanical dust collector.
Nine particulate emission tests were conducted according to EPA
Method 5. One set of tests were conducted under low excess air conditions
while the second set were conducted under normal excess air conditions.
Boiler load averaged 59 percent of design capacity for the normal excess
air tests and 58 percent for the low excess air tests. Opacity readings
were obtained using continuous transmissometers. Opacity averaged
25 and 32 percent for the low and normal excess air tests, respectively.
C-8Q
-------
PLANT UU
Low Excess Air Tests
TEST SUMMARY SHEETS (Particulates Only)
18
Test Number
One
Two
Three
Four
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
n °/
Vy/O
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
59
8.8
8.8
330
323
0.94
0.410
i.oo
0.439
450
1.05
1.30
0.569
575
1.34
25
25
25
.3D_
C-81
-------
PLANT UU
Low Excess Air Tests
TEST SUMMARY SHEETS (Particulates Only)18
Test Number Five Six Seven Average
General Data
Date 8/13/79 8/14/79
Time
Isokinetic Ratio (%)
Boiler Load (% of design) 58 59 58.5
°2% 8.5 8.4 8 6
Gas Data
Velocity (mps)'
Velocity (fps) ^
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F) 318 3Q8 32Q
Pressure (inches W.C.)
Moisture (%) •
Particulate Emissions
g/dnm3 1.02 1 T?4
Gr/dscf 0.446 Q.540
ng/J 450 543
lb/106 Btu 1.05 1.26
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%) 25 25
lC-82
-------
PLANT UU
Normal Excess Air Tests
TEST SUMMARY SHEETS (Participates Only)18
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
001
2/0
Gas" Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Part i cu1at e Em i s s i o n s
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
a/il/79
8/11/79
315
1.46
9.5
35
35
Q.SflS
1.46
25
32
C-33
-------
Plant ZZ
A compliance test was performed on plant ZZ's number two oil-fired
steam boiler for the State of Maryland, Division of Compliance. The
boiler has a rated capacity of 55,000 Ibs/hr and was run at 37,000 Ibs/hr
for the test or 67 percent of the capacity. Emissions from the boiler
are controlled by a mechanical collector, a V6M Breslove Dust Collector.
Two tests were performed using basically an EPA Method 5 except the
19
filter and probe temperature were at 300 F rather than 250°F.
C-84
-------
PLANT ZZ
TEST SUMMARY SHEETS (Particulates Only)
19
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
12/6/73
310
10,955
267
513
9.71
0.0263
0.0115
43,726
18.800
_ni.l_
.906
517
10.10
0.0240
0.0105
8.60
0.020
0.906
3Qq
10911
C-85
-------
C.I.4 PARTICULATE EMISSION DATA FOR DUAL MECHANICAL COLLECTORS
C-fif?
-------
£ Method 5 - Low
Temperature
A Method 5 High EPA Test
Temperature
200 _
(0.47)
CO
c
»^* ^3
1/1 t;
(/) CD
•r—
E WD
LU O
r— 1
0) ^s.
+j .a
(O i—
•5 ~ 100 —
2 3. (0.23)
•U 0)
&- c
Q.
O Industry Test
— r- Average of Tests
4
i
mb \y
1 1 1
Plant XX XX XX XX PP
Boiler Number 3333-
Design Capacity 75 75 75 75 145
(10° Ib steam/hr)
Operating Capacity 71 71 96- 96- ^100
(% of Design) 98 98
Fuel Sulfur 2.86 2.86 2.70 2.70 0.74
(Wt X)
Fuel Ash 8.7 8.7 7.6 7.6 6.4
(Wt X)
Fly Ash Reinjection No No No No No
Figure C.I. 4-1. Dual mechanical collector emission data.3
All tests ordered from left to right by increasing operating capacity
C-87
-------
PLANT PP
Plant PP has a B&W 145,000 Ib/hr of steam spreader stoker boiler.
The flue gas from this boiler is vented to two SUP Multiclone Collectors
(UOP) in series (Dual Mechanical Collector).
The emission tests were performed using EPA Method 5. All runs were
?0
performed at close to 100 percent of design capacity.
C-88
-------
PLANT PP
20
TEST SUMMARY SHEETS (Participates Only)
Test Number One Two Three Average
General Data
Date 11/30/77 12/1/77 12/1/77
Time
Isokinetic Ratio (%)
Boiler Load (% of design) ~1QQ ~1QQ ~1QQ ~10Q
Gas Data
Velocity (mps)
Velocity (fps) ^_
Flow (dnraVmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%) 2Z^ ^^ ^^
Particulate Emissions
g/dnm3
Gr/dscf ZZZ ^IZ
lb/106 Btu Jk"LZ2 0.197 0.169 0.179
Collection Efficiency, % 92.6 92.8 95.8 93.7
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash 5.87 7.20 6.13
% Sulfur "0.61 0.95 0.66
Average Opacity (%)
C-89
-------
Plant XX
Stack testing of Boiler No. 3, a coal-fired spreader stoker, was
conducted by EPA at Plant XX to determine the quantity of boiler emissions
and collection device efficiency. The boiler has a rated capacity of
93 million Btu/hr (thermal input) to produce 75,000 Ib/hr of steam. The
boiler emissions are controlled by a dual multi-tube cyclone dust collector
(dual mechanical collector).
The testing was conducted using EPA Method 5 at two different sample
box temperatures. In Method 5 the temperature of the filter and probe on
the sampling train is normally maintained at 120°C (248°F). In a
simultaneous Method 5 test at Plant XX,.the other sampling train was
maintained at 177°C (350°F) to avoid collection of condensed SO.,. The
results of the two tests are averaged and presented separately.
Four tests were conducted with the boiler running near 100 percent of
capacity during the first three tests and 75 to 80 percent during the fourth
run. The cyclone pressure drop for tests 1 through 4 was 6.5, 6.6, 6.6 and
21
4.0 inches W.G. for an average of 5.9 inches.
Air flow rates were higher than normal throughout the testing period at
Plant XX. This conclusion was based on previous tests conducted on this
boiler and a mass balance analysis. Estimates show that as much as
30 percent of the total flow was due to air leaking in through the collector
doors and sampling ports. This excess flow may affect the performance of
the dual mechanical collector. In addition, plant personnel indicate that
hopper ash reintrainment may occur when air leaks in through the collector
C-90
-------
it-
doors. Because of the air leaking in and the potential for hopper ash
reintrainment, this data was not included in Chapter 4.
*
Memo and attachments from Burt, R. to Sedman, C.B., EPA. May 30, 1980.
Memo regarding test results from DuPont at Parkersburg, West Virginia.
C-91
-------
PLANT XX
Method 5*
TEST SUMMARY SHEETS (Particulates Only)
21
Test Number
One
Two
Three
Four Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (raps)
Velocity 'fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture
12/16/80 12/16/80 12/1Z/80
103
96.3
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
4.74
0.3908
.1707
217.6
0.506
31866
13700
2.69
17.1
104
97.5
5.54
Q.352Q
.1538
168.7
0.392
32796
14100
7.72
103
95.7
5.03
17.1
32098
13880
21.9
107
71.3
22104
146
0.2056
Q.Q898
109.0
0.253
31866
13700
8-68
104
90.2
308
0.3239
0.1415
177.0
0.411
32157
13825
*Samp1e box temperature - 120°C (248°F).
C-92
-------
PLANT XX
Method 5*
TEST SUMMARY SHEETS (Particulates Only)
21
Test Number
One
Two
Three
Four
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
12A6/80 -12/16/80
106
'96.3
0.2674
0.1168
148.9
0.346
31866
13700
0.234
0.1022
112.1
0.261
32796
14100
7.72
17.1
2.70
17.1
104
95.7
848
5.13
0.2323
0.1015
142.3
0.331
32098
21.9
12/11/80
630
4.80
0.1370
0.0599
72.6
0.169
31866
21.9
778
27483
154
309
0.2177
0.0951
119.0
0.277
32157
13825
7.90
2.74
19.5
*Sample box temperature - 177°C (350°F).
C-93
-------
C.I.5 PARTICULATE EMISSION DATA FOR WET SCRUBBERS
C-9't
-------
Method 5 - Low
Temperature
Method 5 - High
Temperature
A
O Industry Test
EPATest
•4—
Average of Tests
Pulverized Coal Boilers
120
(.279)
100
(.233)
V*
^ 3" 8"
Sj= (.186)
fO •—
| ;> 60
£ ? (-140)
19
O.
40
(.093)
20
(.047)
Plant
4
0
O
it '
4
? i "*
n
1 1 1 1 1
00 QQ 00 L MM LL L
4
4
O
O
t
u
1
1
>
1 1
L HM LL t
1
>
1
4
t
t
L L
>
i-
i
Multlventurl
< Tray Type >
Scrubbers
li
f?
° •
""
Entralnment
Scrubbers
0
t
C
r i i i i
L H H SS AM AM 0 (
i
•»
i>
Venturl
Sieve Tray
Tower
Combination
Scrubbers
fQ
Q
O
Venturl
Spray Tower
Combination
Scrubbers
O
1
II 1 1 1
3 00 00 TT TT
Boiler No. 4 5 5 3 2 20 ?0 3 19 19 19 1 4 3 1 1 3 2 - - -
Desjqn Capacity
(106 Ib steam/hr) - - - 100 100 60 60 100 100 100 80 - - - -
(10 Btu/hr) 202 202 202 - 295 236 236 295 236 236 236 - - 137 137 100 100
Operating Capacity 80- 80- 95 93- 75 85- 85- 75 100 73 73 86- 79- 81 92 92 80- 88 100 100 100 100
(X of Design) 100 95 97 91 91 92 83 100
Emission Controls1' 55527777777333 3344 6611
Scruhber Pressure
Drop
(In 11,0 guage)
°e"9" 2* 22 22 10 17 17 17 17 17 17 17 13 13 13 13 13 12 12 - -, ...
Operating 8 8 8 10 16 17.3 17.3 17.5 18.1 19.3 19.3 7.5 7.5 7.5 7.5 7.5 12 12 12/45C 17/4SC 3d 9d
Design L/G 11.4 11.4 11.4 - 10 10 10 10 10 10 10 20 20 - - -
Fuel Sulfur Z.4- 2.4- 2.4- 0.8 2.4- 2.54 2.54 2.4- 2.4- 2.
3.4 3.4 3.4 3.4 3.4 3.4
6 2.
20 20 4 17
6 2.3 2.4 2.14 1.33 1.33 2.33 2.33 3.5 3.5 3.9 3.9
Fuel Ash (wt J) 10 10 10
Fly Ash Re1nject1on Yes Yes No
7.2 10 10.4 10.4 10 10 11.4 11.4 9.4 8.0 5 4.4
No Yes Yes Yes Yes Yes Yes Yes No No No No
4.4 10.5 9.9 12.3
No No No No
12.3 14.7 14.7
No No No
Figure C.I. 5-1. Emission data for wet scrubbers.'
C-95
-------
aVenturi tests ordered by increasing operating pressure drop.
All other tests ordered by decreasing percent ash in fuel.
PM and SCL control devices.
1. Venturi/spray tower
2. 95 percent efficient mechanical collector, FMC venturi dual
alkali scrubber.
3. Mechanical collector, multi-venturi flex tray dual alkali
scrubber.
4. Mechanical collector, Zurn entrainment type scrubber.
5. 80 percent efficient mechanical collector, venturi scrubber.
6. Venturi/sieve tray scrubber.
7. Mechanical collector, venturi scrubber with cyclonic separators
cVenturi Ap/sieve tray Ap.
Ap for venturi only.
C-96
-------
Plant L
Particulate emission tests at Plant L were conducted on a spreader
stoker unit, boiler no. 3. Boiler no. 3 has a rated capacity of 100,000
pounds of steam per hour. The boiler is equipped with a Western
Precipitator Multiclone mechanical dust collector which is vented to a
venturi scrubber using a sodium scrubbing solution for combined SOp/PM
removal. Boiler no. 3's mechanical collector is designed for 95 percent
particulate removal. The design air flow through the scrubber is
56,000 acfm at 390°F. Operating pressure drop is 10 inches of water.
All tests were conducted according to EPA Method 5. The boiler operated
at an average of 95 percent of design load with an average particulate
22
emission rate of 0.05 pounds per million Btu.
C-97
-------
PLANT L
Boiler #3
TEST SUMMARY SHEETS (Particulates Only)
22
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (in H20 gauge)
Gas Data
Velocity (mps)
Velocity (fps) '
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
9/18/75
10:30-14:30
105
18.03
537T5~
84773"
299TT
53.9
129
0_
0.046
0.02
17.2
0.04
9/22/75
10:5
-------
Plant M
Two of the four spreader stoker boilers at Plant M were tested to
determine compliance with the Ohio State EPA Standards. The tested
units (numbers 1 and 4) are each equipped with a mechanical collector
and a Koch Multiventuri Flexitray scrubber for combined SCL/PM removal
in series. Both scrubbers have a design liquid to gas ratio of 20
3
gal/10 acfm. Unit number 1, an Erie City Iron Works boiler, has a
rated capacity of 100,000 pounds of steam per hour. The Wickers boiler,
unit number 4, has a rated capacity of 60,000 pounds of steam per hour.
Three tests were conducted at each unit. Boiler load during
testing averaged 78.9% of "capacity at unit number 4 and 89.1% of capacity
at unit number 1. The emission rate was found to be above the State
limit of 0.13 pounds per million Btu and above the design limit of 0.10
pounds per million Btu. The problem was believed to be caused by mist
23
carryover from the eliminator contributing to high emission rates.
C-99
-------
TEST SUMMARY
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch hLO)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Farticulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj /kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
PLANT
Boiler
SHEETS
One
12/79
94.5
88.7
12.55
41.17
875.2
30,903
0.18
11.5
0.1762
TO77
0.194
29056
12492
8.6
2.4
M
#1
(Particulates
Two
94
86.4
12.80
42.0
895.6
31,624
0.18
11.4
0.1396
0.061
69.66
0.162
28959
12450
9.1
2.2
Only)23
Three
I£E
11.91
39.07
850.7
30.037
0
11.2
0.1945
0.085
88.58
0.206
29373
12628
10.4
Average
8Q.1
7.5
40.75
873.8
30855
0.12
0.1701
0.074
80.41
0.187
H
C-100
-------
PLANT M
Boiler #4
TEST SUMMARY SHEETS (Particulates Only)
23
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/niin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
99.8
82.5
11.95
27497
0.1304
0.057
79.12
0.184
29896
11.81
38.75
777.7
27461
15
11.48
0
14.9
0.1441
0.063
93.74
0.218
30487
2.3
11.75
38.54
771.1
22228
0
0.1327
0.058
83.42
0.194
C-101
-------
Plant 0
At Plant 0 two spreader stoker boilers each equipped with a single
stage mechanical collector and Zurn Wet Scrubber were tested. The
Zurn scrubber accomplishes combined SCL/particulate removal. Boiler
number 2 is rated at 80,000 pounds of steam per hour. Boiler number
3 has a rated capacity of 100,000 pounds of steam per hour. Sulfur
oxide control is accomplished by maintaining the scrubber liquor at
pH 12.
Three tests to determine the particulate collection efficiency were
conducted on boiler number 2. Two tests were done on boiler number 3.
All were in accordance with EPA Method 5; Boiler number 2 operated at
70,000 pounds of steam per hour during all three tests. Boiler number 3
operated at 100,000 pounds of steam per hour during the first test and
24
at 80.000 pounds of steam per hour during the second test.
C-102
-------
PLANT 0
Boiler #2
TEST SUMMARY SHEETS (Particulates Only) 24
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
96.5
_88_
12
43.7
807.12
28500
51.7
125
14.5
0.1464
0.064
58.05
07l35~
24165
10389
_9J>4
2.33
97.3
88_
12
125
14.1
0.183
0.080
99.33
0.231
97.1
13 fiQ
44.9
832.61
29400
51.7
125
^472
0.140
0.061
88.58
0.206
-11-26.
28433
51.7
125
14.3
D.156
n.nfifi
82.0
0.1907
24272
10435
9.87
2.34
C-103
-------
PLANT 0
Boiler #3
TEST SUMMARY SHEETS (Particulates Only)
24
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnmVmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
3/29/77
95.0
100
12
in.q?
11.6
0.238
0.104
119.97
0.279
24711
10624
1JLOQ_
97.4
80
12
0.167
0.073
86.86
0.202
25167
10820
10.96
2.45
96.2
90
12
30050
54.4
13.2
0.204
0.089
103.63
0.241
24939
10722
10.48
2.33
C-104
-------
Plant II
Plant II has a 55,000 Ib/hr of steam pulverized coal-fired boiler.
Flue gas from this boiler (#2) is vented to a Joy Turbulaire scrubber.
There is a multicyclone upstream of the scrubber. Tests were made at
95% of capacity and at a scrubber pressure drop of about 9 in. water.
EPA test Method 5 was used to determine particulate emission. Opacity
25
readings were taken in accordance with EPA Method 9.
When comparing the boiler heat input rates calculated in the test
report with values calculated by an alternative method, errors of 50%
were noted. The calculated heat input rate directly affects the
magnitude of the emission rate. Therefore, results from this emission
test may not be representative of normal scrubber operation. As a
result, the data is not presented with the support data for wet scrubbers.
* Memo and attachments from Phillips, W.R., Radian Corporation.
July 3, 1980. Sorg Paper Company Wet Scrubber Tests - Middletown,
Ohio Plant.
C-105
-------
Plant II
TEST SUMMARY SHEETS (Participates Only)
25
Test Number
General Data
Date
Time
Isokinetic Ratio (Z)
Boiler Load (Z of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnmVmin)
Flow (dscfm)
Temperature (*C)
Temperature (°F)
Fressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
Z Ash
Z Sulfur
Average Opacity (Z)
One
4/23/80
103.8
858
30290
44.2
111.6
8.5
0.02736
28.29
0.0658
30578
13,146
9.94
1.25
< 1
Two
4/23/80
105.0
849
29970
49.2
120.5
10.6
0.06510
67.51
0.157
32585
14,009
6.36
1.06
<1
Three*
4/23/80
106.8
811
28631
49.7
121.4
11.1
0.03989
46.87
0.109
31138
13,387
7.52
0.98
< 1
Four
4/24/80
105.1
864
30527
39.4
103.0
9.8
0.01922
20.60
0.0479
30766
13.227
9.48
0.96
0
*Included a soot blowing cycle.
c-ioe
-------
Plant LL
Plant LL has four coal-fired spreader stoker boilers. Participate
emissions were measured from Boilers #19, #20, and #22 which are each
equipped with a mechanical collector and a venturi scrubber. The scrubbers
are part of a dust alkali system designed to remove both PM and S0?.
Process data for the tests on Boiler 22 are not well documented in the
test report. In addition, plant personnel have suggested that the scrubber
was not operated in a manner to provide optimum emission control during the
*
tests. Therefore, results of testing on Boiler 22 are not included with
the support data for wet scrubbers.
There are two test reports for Boiler 19 at Plant LL. Early tests of
this 236 x 10 Btu/hr heat input capacity stoker were supplied by the
pc
plant. The Method 5 tests were conducted at a scrubber pressure drop of
18 inches of water. However, one test was conducted at low boiler load
(55 percent). The low load test is not included in the wet scrubber support
data, since low load conditions may not be fully representative of normal
scrubber operation.
27
In August 1981, EPA also conducted emission tests at Plant LL. The
tests were run according to Method 5, but in order to evaluate the effect on
sulfate and sulfuric acid formation on the measured emissions, EPA conducted
simultaneous tests at two sample box temperatures. During each of the three
runs, simultaneous tests were conducted, one at a sample box temperature of
120°C (248°F) and the other at a temperature of 160°C (320°F). Scrubber
pressure drop averaged 19.3 inches of water.
C-107
-------
During these summer tests the full output of the boiler was not
required and some steam was exhausted to the atmosphere in order to a
full load conditions. This phase of the test program was therefore limited
to the three tests described above.
In December 1981, nine additional emission tests were conducted on
28
Boiler 20. Boiler 19 was out of service for scheduled maintenance outage.
Boiler 20 is very similar to Boiler 19. These nine tests were a
continuation of the test program started in August and described above.
Before the tests, the venturi insert position on the scrubber of Boiler 20
had been adjusted to fully open and fixed in this position by welding the
adjusting mechanism. The pressure drop across the scrubber varied with gas
and liquor flow and was very steady, ranging from 17 to 18 inches of water.
Piccot, Steve. (Radian Corporation.) Telephone conversation with Plant LL
personnel. May 1981.
C-108
-------
PLANT LL
TEST SUMMARY SHEETS (Particulates Only)'
26
Test Number
Boiler 19 Boiler 19 Boiler 22
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating A? (inch H?0)
Gas Data c
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
6/13-15/79 6/13-15/79
100%
18.1
18.1
0.119
0.104
0.315
**Average throughout testing at Plant LL.
C-109
-------
PLANT LL
Boiler No. 19
Method 5 - Low Temperature
TEST SUMMARY SHEETS (Particulates Only)27
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch HLO)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
8/3/81
1:30-4:10
104.6
71
11QQ
387QQ
0.260
0.113
134
0.31
24050
10350
10.5
2.65
Two
8/4/81
9:35-1:20
98.7
75
19.6
1120
395QQ
0.230
0.100
0726~
23300
10000
13.0
2.6
Three
8/4/81
3:00-7:21
99.0
75
20.0
1160
4nqnn
138
0.185
0.081
0.20
24200
10400
10.7
2.6
Average
100.8
73
19.3
f?i
0.225
0.098
111
0.26
10250
11.4
2.62
C-110
-------
PLANT LL
Boiler No. 19
Method 5 - High Temperature
TEST SUMMARY SHEETS (Particulates Only)
27
Test Number
General Data
Bate
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (raps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
8/3/81
1:30-4:10
104.9
11UO
iayuu
135
Q.Q88
0.038
45
0.10
24050
10350
10.5
2.65
Two
8/4/81
9:35-1:20
96.5
75
19.6
~ITBD~
418UU
137
Q.Q58
Q.Q25
0.07
23300
10000
13.0
2.6
Three
8/4/81
3:00-7:21
103.0
75
20.0
1170
41300
138
n.13R
Q.05Q-
0.14
24200
10400
10.7
2.6
Average
101.5
73
^
TT50~
40667
137
o nqa
n.OAi
. 45
Q.1Q
23850
10250
11.4
2.62
C-lll
-------
PLANT LL
Boiler No. 20
Method 5 - Low Temperature
TEST SUMMARY SHEETS (Participates Only) 28
Test Number
One
Two
Three
Four
Five
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP
12/1/81 12/2/81 12/2/81
1:52^4^05 8:20-10:20 1:20-3:17 7
8.9
96.9
inch HUO)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnrrn/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches
Moisture (%)
W.G.)
Particulate Emissions
g/dnm
gr/dscf
ng/J f-
lb/10D Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
139
0.096
0.042
41.3
0.10
24400
10500
10.6
2.5
137H
48400
54
129
0.089
0.043
42.4
0.10
0.064
0.028
12/3/81
:40-9:30
102.2
87
17.75
12/3/81
11:00-12:48
100.4
129
0.075
0.033
32.3
0.08
24420
10510
10.4
129
25010
10760
C-112
-------
PLANT LL
Boiler No. 20
Method 5 - Low Temperature
TEST SUMMARY SHEETS (Particulates Only) 28
Test
Number
Six
Seven
Eight
Nine
Average
General Data
Date ip/3/ai
Time 2:01-3:53
Isokinetic Ratio (%) 100.0
Boiler Load (% of design) 91
Operating AP (inch H00) 17
c.
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnnvYmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
1290
45600
54
129
Particulate Emissions
g/dnm
gr/dscf
ng/J c
lb/10° Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Q.Q62
0.027
24660
10610
12/4/81 12/4/81 12/4/81
7:50-9:46 11:02-12:57 2:43-3:50
100.9
90
17
1350
47500
53_
128
Q.Q69
0.030
29.8
0.07
25360
10920
97.3
1360
128
Q.Q81
0.036
35.7
0.08
24120
10380
11.8
3.1
99.7
17
130
0.096
0.042
41.4
0.10
24760
10660
100.0
17
1331
46989
54.
130
Q.Q79
0.035
34.2
0.08
24708
10634
10.4
2.54
C-113
-------
PLANT LL
Boiler No. 20
Method 5 - High Temperature
TEST SUMMARY SHEETS (Participates Only)28
Test Number
One
Two
Three
Four
Five
General Data
Date
Time 1
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dniTH/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
Parti cul ate Emissions
g/dnm
gr/dscf
12/1/81
:52-4:05
102.0
lb/10 Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
24400
10500
12/2/81
8:20-10:20 1:20-3:17 7:40-9:30
18
0.092
0.040
39.8
0.09
100.4
85
18
1300
45800
100.2
87
17.75
12/3/81
11:00-12:48
99.2
90
17
0.070
0.030
24420
10510
10.4
2.5
1340
47300
0.066
0.029
28.3
0.08
25010
10760
9.8
2.5
C-114
-------
PLANT LL
Boiler No. 20
Method 5 - High Temperature
TEST SUMMARY SHEETS (Participates Only)
28
Test Number
General Data
Date
Time 2
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H^O)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm^/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
Particulate Emissions
g/dnm
gr/dscf
ng/J f.
lb/10° Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Six
I?/ -V81
" 102.9
91
17
1260
44600
54
129
0.060
0.026
25.7
0.06
24660
10610
10.3
2.3
Seven
12/4/81
7:50-9:46
90
17
1370
48300
53
128
n.DfiQ
0.030
29.7
0.07
25360
10920
10.3
2.2
Eight
12/4/81
99.1
17
1380
48800
53
128
n.nai
0.06
24120
10380
11.8
3.1
Nine
12/4/81
101.0
17
1390
48900
130
n nofi
n.n2Q
28.9
0.07
24760
10660
10.0
2.8
Average
100.3
88
17
1336
47122
54
130
n n«o
n,n32^
31 q
0.07
24708
10634
10.4
2.54
C-115
-------
Plant MM
Plant MM contains five spreader stoker boilers equipped with
mechanical collectors and Venturi dual alkali scrubbers for combined
SCL/PM removal. Fly ash from the mechanical collector hoppers is
reinjected into the boiler. Boilers #2 and #3 have identical 295 million
Btu/hr ratings. Design pressure drop across the scrubbers is
approximately 17 inches of water.
All tests were run using EPA Method 5. Both boilers were tested
o/-
at 75 percent load, with fly ash reinjection during both tests.
C-116
-------
PLANT MM
TEST SUMMARY SHEETS (Particulates Only)26
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating P (Inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis *
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Boiler #2
6/5/79
Boiler #3
6/6/79
16
68.8
Q.16Q
*Fuel analysis is for a representative coal burned at Plant MM,
C-117
-------
Plant NN
Plant NN contains two spreader stoker boilers equipped with mechanical
collectors and Zurn entrainment type dual alkali scrubbers. Both boilers
are rated at 71 million Btu/hr. Pressure drop during the tests is
approximately eight inches of water.
All test runs were made using EPA Method 5. Boiler #2 was tested
at 100 percent load, and then tested at 50 percent load. Fly ash was
oc
being reinjected during both tests. Scrubber pressure drop during the
tests were not presented in the test report. For this reason the
scrubber operation cannot be fully characterized. Therefore, the data
from Plant NN are not included with the support data for wet scrubbers.
4
C-118
-------
PLANT NN
TEST SUMMARY SHEETS (Particulates Only)26
Boiler 12
Test Number One * Two * Three Average
General Data
Date
Time
Isokinetic Ratio (Z)
Boiler Load (Z of design) ' '00 50
Gas Data
Average Opacity (Z)
Velocity (mps)
Velocity (fps)
Flow (dmn3/min)
Flow (dscfm)
Temperature (*C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J 64.5 61.49
lb/106 Btu OJ5Q 0.143
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
Z Ash
Z Sulfur
ash reinjection both tests.
c-n?
-------
Plant 00
Plant 00 consists of two 40 MW (136.5 x 106 Btu/hr) pulverized, dry
bottom boilers retrofitted with three 20 MW prototype flue gas desul-
furization units. One of these units is a concentrated dual alkali
scrubber supplied by Combustion Equipment Associates/Arthur D. Hill.
The scrubber consists of a venturi followed by a sieve tray tower.
Three series of-tests were conducted using EPA Method 5 to evaluate
particulate removal efficiency. One series of tests was made with
the upstream electrostatic precipitator fully charged, (Tests 2-4).
A second series was made with half the precipitator out of service
(Tests 5-7). All tests where the ESP was in service are not included
in the support data for wet scrubbers.
A third series of tests was conducted with the precipitator turned
off (Tests 8 - 13). Results from this series are averaged and presented
as support data for wet scrubber performance. In all three test series,
venturi pressure drop was compared at 12 inches w.g. and 17 inches w.g.
for effects upon outlet emissions. Tests are averaged separately
depending on the pressure drop used during testing. Boiler load
29
averaged 95 percent.
C-120
-------
PLANT 00
Low Pressure Drop Tests
pq
TEST SUMMARY SHEETS (Participates Only)
Test Number One Two Three Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Venturi AP (inch H?0)
Sieve Tray AP (incfi H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm-Ymin)
Flow (dscfm)
Temperature (°C)
Temperature (°F) ^^ _____
Pressure (inches W.C.)
Moisture (%) ~
Particulate Emissions
g/dnm3 0.85 0.055 Q.Q78 0.328
Gr/dscf 0.037 0.024 0.034 0.032
ng/J 6 32.2 21.1 29.7 27.7
lb/10 Btu 0.075 0.049 Q.Q69 0.064
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb) '
% Ash ~~ ~~
% Sulfur
Average Opacity (%)
C-121
-------
PLANT 00
TEST SUMMARY SHEETS (Participates Only)
29
Test Number
One(
Two0
Three a
Four
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnra3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
6/15._to_7/l/76
0.027
0.012
10.3
0.024
Q.Q34
0.015
0.030
12200
12.3
3.5
0,025.
0.011
9.46
0.022
0.059
0.026
.053
a) ESP at full operating capacity
b) ESP at half operating capacity
C-122
-------
PLANT 00
TEST SUMMARY SHEETS (Particulates Only)
29
Test Number
General Data
Date
T i me
Isokinetic Ratio (%)
Boiler Load (% of design)
Gas'Data
Velocity (inps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Five
0.048
"0.021
18.5
0.043
Six
6/15/7.6-7/1/76
0.062
0.027
0.055
AVERAGE
12.3
ESP at half operating capacity
C-123
-------
PLANT 00
High Pressure Drop Tests
TEST SUMMARY SHEETS (Participates Only)29
Test Number One Two Three Average
General Data
Date 6/15/76 - 7/1/76
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Venturi AP (inch H20) .. „
Sieve Tray AP (incn H^O) 4.5 4.5
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnrrP/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
/^ 3
9/dnm 0.085 0.076 Q.ORn
Gr/dscf 0.037 0.033 0.035
ng/J 6 32.2 28.8 30.5
lb/10 Btu 0.075 0.067 0.071
Fuel Analysis AVERAGE
Heating Value (kj/kg) 12200
Heating Value (Btu/lb) 12.3
% Ash 3.5
% Sulfur
Average Opacity (%}
C-i.24
-------
PLANT QQ
Boilers No. 4 and No. 5 at Plant QQ are both spreader stokers.
Both use a mechanical collector and venturi dual alkali scrubber
for combined SCL/PM removal. The boilers are each rated at 202 x 10
Btu/hr heat input. Load was varied during the EPA-5 tests as shown on
the following table. The pressure drop through the scrubber was about
?fi
eight inches of water during all tests.
Low load tests conducted on boilers 4 (65%) and 5 (50%) may not
be representative of normal scrubber opperation. Therefore, these
tests are not included in the support data for wet scrubbers. The
average of tests conducted on boilers 4 and 5 do not include these low
load tests.
Fly ash from the mechanical collector hoppers was reinjected into
both boilers 4 and 5. However, one test on boiler 5 (Test 2) was
conducted without the use of fly ash reinjection. This test is presented
separately from the other boiler 5 tests, and is not included in the
average of tests presented on the Summary Sheet.
C-125
-------
PLANT QQ
TEST SUMMARY SHEETS (Particulates Only)
Boiler #4
26
Test N7umber
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
Two
Three
Average*
4/23-27/79 4/23-27/79 .2/23-27/79
90-100
80
"65
8
71.81
0.167
60.?
0.140
w rn
n inn
66.0
0.154
* Tests One and Two only. Test Three not included because of low load,
C-126
-------
PLANT QQ
TEST SUMMARY SHEETS (Particulates Only)26
Boiler #5
Test Number One Two** Three Four Five Average11
Generaj_ _Da_ta_
Date 6/26-29/79 6/2J5-29/79 6/26^29/79 6/26^.29/79
Time
Isokinetic Ratio (%) ^1 " L_~_
Boiler Load (% of rating) 95 95 80 80 _5CL_ 80
Operating AP (inch H20) "_ " _'_ ~§~
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dniTH/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
Particulate Emissions
g/dnm
gr/dscf
ng/J fi 113.9 103.2 68.8 60.2 41.28 80.97
lb/10° Btu 0.265 0.24 0.16 0.14 Q.Q96 0.19
Fuel Analysis ***
Heating Value (kJ/kg)
Heating Value (Btu/lb) ____ '_ "_
% Ash ~~ ~_ 10
* Sulfur I .J ~~_.__ " 274^374
Average Opacity (%)
* Test 5 not included in average because of low load. Test 2 not included because
fly ash reinjection was not used.
** Fly ash reinjection not used during this run.
***
Fuel analysis is for a representative coal burned at Plant QQ.
C-127
-------
PLANT SS
Plant SS contains four spreader stoker boilers each equipped with a
mechanical dust collector and a multiventuri flex tray double alkali scrubber.
Particulate emission tests were conducted on boiler number 3 which has a rated
capacity of 60,000 pounds of steam per hour. Boiler load ranged from 71 to 81
percent of capacity during testing. Neither boiler nor scrubber was operating
in a stable manner. Boiler load fluctuated between 40,000 and 52,000 pounds
of steam per hour.
The two low load tests (<75%) run on boiler number three are not included
in the support data for wet scrubbers. These data are not included because
operation under low load conditions may not be representative of normal scrub-
ber operation.
It should be noted that the testing contractor felt that the scrubber was
not operating representatively. The outlet scrubber liquor pH varied from 3.6
to 7.6 because of problems with the lime feed system. This may have
30
affected the measured particulate emissions.
C-12P
-------
PLANT SS
•3f)
TEST SUMMARY SHEETS (Particulates Only)
Test Number One Two Three Average
General Data
Date 12/20/79 12/20/79 12/20/79
Time
Isokinetic Ratio (%)
Boiler Load (% of design) gJL
Operat
Gas Data
Operating AP (inch H20) 7.5
Velocity (mps)
Velocity (fps)
Flow (dnnrVmin) _„__
Flow (dscfm) "2T808" 2T7PT
Temperature (°C) 59 60. 57_
Temperature (°F) 139 140 134
Pressure (inches W.C.)
Moisture (%) 15. U 1_4_
Particulate Emissions
g/dnm3 0.098 0.08 0.094
Gr/dscf 0.043 0.035 0.041
ng/J , 68.8 60.2 81.7
lb/10° Btu 0.16 0.14 0.19
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur 2.14
Average Opacity (%}
C-12?
-------
PLANT TT
A pulverized coal boiler with a rated capacity of 100 x 106
Btu/hr was tested at Plant TT. It is equipped with a venturi/spray
tower FGD scrubber system using a lime slurry scrubbing solution. Ten
particulate tests were performed to determine the effect of major
operating variables. These variables included MgO addition, venturi
pressure drop, gas rate, slurry rate, mist eliminator configuration, and
percent solids recirculated. All tests were conducted in accordance
with EPA Method 5.
Tests 2 and 3 were performed on a ESP treated gas stream. These
tests are not included in the support data for wet scrubbers. In
addition, test 5 was not included in the support data for wet scrubbers
because of low load conditions. Operation at low load may yield results
that may not be representative of normal scrubber operation.
The tests are arranged according to the scrubber operating pressure
drop. Normal pressure drop tests (5-9 inches H20) are grouped and
averaged together. The one low pressure drop test (3 inch H20) is not
included in this averaging and is presented separately.
C-130
-------
PLANT TT
Normal Pressure Drop Tests
TEST SUMMARY SHEETS (Particulates Only)31
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (raps)
Velocity (fps)
Flow (dnraVmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
Two
Three
100
9.4
53520
23388
1QQ
9
JL-JL
53520
23388
100
9
9.4
53520
23388
0.073
0.032
26.2
flJJA
0.005
5.16
n.m?
o.nns
0.061 0.012 0.012
AVERAGE FOR ALL TESTS
14.7
3.9
Four
1Q/W76 10/20/76 10/20/76 10/29/76
0,0,44.
0.019
16.8
0.039
* ESP was in service during these two tests.
C-131
-------
PLANT TT
Normal Pressure Drop Tests
TEST SUMMARY SHEETS (Particulates Only)
31
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dntn3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Five
57
0.6Q_
0.026
21.1
0.049
Six
Seven
Eight
U/2/Z6 l.U.fi/26 liyjO/76 Ua8/76
100
5.3
53520
0.064
0.028
24.1
0.056
53J20
2_3JBB_
53520
222S&
0.062
0.027
22.8
0.053
0.048
0.021
17.2
0.040
C-132
-------
PLANT TT
Normal Pressure Drop Tests o-i
TEST SUMMARY SHEETS (Particulates Only)
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
Nine
Average*
11/22/76
9.4
53520
23388
0.060
100
8.4
53520
23388
0.059
0.037
21.25
0.049
* Average does not include tests 2 and 3 where an ESP was used. Also does
not include Test 5 which was conducted at an average 57% load.
C-133
-------
PLANT TT
Low Pressure Drop Test
TEST SUMMARY SHEETS (Participates Only)31
Test Number
GejTer_al_ Data
Date
Time
Tsokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (,%)
Pa_r_t_i.cu_lat_e_ Emissions;
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
11/27/76
100
3
0.082
0.036
_
0.072
14.7
3.9
C-13*
-------
Plant AAA
Emissions from boiler no. 1 at Plant AAA were tested by EPA to
determine the quantity of emissions and the effectiveness of the control
device. The spreader stoker boiler tested has a steam capacity of
100,000 Ib/hr firing waste oil and coal. Waste oil was not fired during
the testing period. It is equipped with an economizer, multiclone and
double alkali scrubber. The scrubber has four, three-stage multiventuri
flexi-tray scrubber modeules with a pressure drop of 19 cm H^O (7.5 in.
H20). The design flow if 65,500 acfm at 80°F (30.9 m3/s at 27°C).
Testing was performed using simultaneous EPA Method 5 at different
sample box temperatures. In one sample train the filter and probe
temperature was maintained at 177°C (350°F) to avoid collection of
condensed SO-. The other sample train was maintained at the more common
Method 5 temperature of 120°C (248°F). Three simultaneous tests were
32
run with the boiler operating at about 92 percent capacity.
C-135
-------
Plant AAA
Method 5*
TEST SUMMARY SHEETS (Particulates Only)32
Test Number
General Data
One
Two
Three
Average
Da t e
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP(inch rLO)
Data
11/13/80 11/13/80 ll/1.4/80
7.5
7.5
99.4_ 1.01. Z.
9.2L_. -9Z- -
7.5 7.5
Velocity (mps)
Velocity (fps)
Flow (dmn3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Pa r t j_c_ul_a_t e_ Emissions^
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
813
0.114
32872
14142
5.13
1.09
0.134
32965
14182
4.43
1.48
789
0.115
32979
0.0968
0.0423
48.9
0.1154
0.0504
57.8
o'.0444
49.6
0.1046
0.0457
52.1
0.121
32939
14171
4.36
1.33
*Sample box temperature (filter and probe) = 120°C (248°F).
C-136
-------
Plant AAA
Method 5*
TEST SUMMARY SHKKTS (Particulates Only) 32
Test Number
One
Two
*High sample box temperature [177°C (350°F)].
Throe
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Operating AP (inch H20)
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
11/1.3/80
9972"
92
7.5
~~82T
29185
48
118
7.9
11.69
0.0489
0.0213
23.8
0.055
32872
14142
1.09
11713/80
98. 4~
92
7.5
"834"
29438
48
118
7.9
13.08
0.0976
0.0426
48.5
0.113
14182
U48_
11/1.4/80
100.1"
92
7.5
" 79 2~
27953
47
•117
7.3
12.56
OJ159.8
0.0261
31.1
0.072
32979
14188
3.51
1.43
Average
99.2
92^.
7.5
818 _
2885_9.
48
118
7.7
12.44
3Z9_39_
L4J1L
C-137
-------
C.I.6 PARTICULATE EMISSION DATA FOR SIDE STREAM SEPARATORS
C-138
-------
O Industry Test
4- Average of Tests
80—
(0.186)
•1 P 60—
% S (0.140)
UJ O
91 "^
^J ^
^* ^J
(O r—
r— «•»•
3 -3 40
5 1 (0.093)
(Q
Q.
(0.0477"
O
i i
"v~ i
1
Plant ODD CCC
Boiler Number
Design Capacity 45 70
(10-5 Ib steam/hr)
Operating Capacity 68b 71-
(X of Design) 80
Average Opacity (X) Oc
Fuel Sulfur 0.82 0.80
(Wt X)
Fuel Ash 9.7 10.1
(Wt X)
% of Flow to 16b 31
Baghouse
•»
Figure C. 1.6-1. Side st
J|-" cauci -J uui^ci j
0
9 "i"
o X
Q
o
1 1 i
GGG EEE FFF EEE BBS
1 3 3 3
60 40 100 55 52
74- 84- 85- 99- 97-
80 93 97 105 108
6.9 0 Oc 6C
0.94 1.79 1.67 2.09 0.80
4.3 9.0 6.1 8.8 7.8
30 37 15 15 17
ream separator emission data.a
All tests ordered from left to right by increasing operating capacity
3Data presented are averages for all tests
C-139
-------
Plant BBB
Boiler no. 3, a Babcock and Wilcox unit with a traveling grate
spreader stoker, at Plant BBB was tested under a U. S. EPA Innovative
Technology Order. The boiler is rated at a continuous capacity of
52,000 pounds of dry saturated steam per hour.
The boiler is equipped with a mechanical cyclone (Joy 9 VM with a
design pressure drop of 3.8 in. W.G.), and a bag filter (a Pulse Flow
FP SQ4508). The filter consists of a rectangular housing containing 144
filter bags, 4 1/2 inches in diamter by 8 ft. The filter provides a
2
total filter area of 1395 ft with a design air-to-cloth ratio of 6.45
2
scfm/ft . The bag filter receives a side stream which represents
between 16 to 18 percent of the boiler exhaust after it has passed
through the cyclone. The side stream is taken from the base of the
cyclone.
Eight particulate emission tests were taken using EPA Method 5.
During the first four tests the bag filter received 18 percent of the
total boiler exhaust flow and 16 percent during the last four tests.
33
Boiler load averaged 103 percent. Opacity was determined with a Bailey
smoke density recorder.
C-140
-------
PLANT BBB
TEST SUMMARY SHEETS (Particulates Only)
33
Test Number
One
Two
Three
Four
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Percent flow to baghouse
Gas Data
Velocity (raps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
3/31/80 4/1/SO
4/1/80
4/1/80
16
105
16
16
73.5
n
Average for Tests 1-4
C-141
-------
PLANT BBB
TEST SUMMARY SHEETS (Participates Only)
33
Test Number
Five
Six
Seven
Eight
General Data
Average
Date 4Z2/80 4/2/80 4/2/80 4/2/8.0
Time
Isokinetic Ratio ("J)
Boiler Load (?, of rating) 101 98 108 104
Percent flow to baghouse* 18 18 ~T8 18
103
17
Gas Da_ta
Velocity (mps)
Velocity (fps)
Flow (dnm^/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
Particulate Fmissions
q/dnm
qr/dscf
na/J , 74.4 66.2 71.8 70.5
lb/10D Btu 0.173 0.154 0.167 0.164
Fuel Analysis Average for Tests 5-8
Heatina Value (kJ/ka) 30529
Heating Value (Btu/lb) 13125
% Ash 7.65
% Sulfur 0.81
Avpragp Dparit.y (%) 666 6
71.0
0.165
30420
13078
7.8
0.80
6
C-142
-------
Plant CCC
Plant CCC's boiler No. 3 is a Riley boiler with a traveling grate
spreader stoker rated at a continuous capacity of 70,000 Ib/hr of dry
saturated steam.
The boiler is equipped with a mechanical cyclone, a Joy 9 VM with
a design pressure drop of 2.95 inches W.G., and a bag filter, a pulse
flow PF SQ4508. The filter has a rectangular housing containing 144
filter bags, each 4 1/2 inches in diameter by 8 ft. The filter provides
2
a total filter area of 1395 ft. with a design air-to-cloth ratio of
2
6.45 scfm/ft . The bag filter receives approximately 15 percent of
the boiler exhaust after it has passed through the cyclone. The gas
stream going to the bag filter is taken at the base of the cyclone.
The particulate collection system was tested under a U. S. EPA
Innovative Technology Order. Four tests were conducted using EPA
Method 5. During testing approximately 31 percent of the total boiler
exhaust flow was sent to the bag filter. Boiler load averaged 76
percent.
C-143
-------
PLANT CCC
TEST SUMMARY SHEETS (Particulates Only)33
Test Number
One
Two
Three
Four
Average
Gene_ra 1 _ Da_ta
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of rating)
Percent flow to baghouse*
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnnH/min)
Flow (dscfrn)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
Parti cu late Emissions
g/dnm
gr/dscf
February 26 and 27, 1980
71
80
31
77
31
31
31
610
21530
560
535
18880
580
lb/10 Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
43.0
Qr1Q
11417
10.13
o.sn
* Average for all tests
C-144
-------
Plant ODD
Boiler no. 1 is a Babcock and Wilcox unit with a traveling grate
spreader stoker. The capacity is 45,000 Ibs/hr of steam.
The participate collection equipment consists of a Joy 9 VM series
mechanical cyclone with a 3.5 inch W.G. pressure drop and a Pulse
Jet PF SQ4508 bag filter. The bag filter has a rectangular housing
containing 144, 4 1/2 inch diameter by 8 ft., filter bags. The filter
2
has a total filter area of 1395 ft with a design air-to-cloth ratio of
2
6.45 scfm/ft . The filter receives approximately 15 percent of the boiler
exhaust after it has passed through tha mechanical cyclone. The gas
to the filter is taken at the base of the cyclone.
Four tests were conducted using EPA Method 5 under a U. S. EPA
Innovative Technology Order. During testing approximately 16 percent
of the total boiler exhaust flow was sent to the filter. The boiler
33
load averaged 68 percent.
C-145
-------
PLANT ODD
TEST SUMMARY SHEETS (Particulates Only)33
Test Number
One
Two
Three
Four
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of rating)* 68
Percent flow to baghouse* 16
4/15/80 4/16/RO
68
16
fia
16
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnnvVmin)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
Particulate Emissions
g/dnm
gr/dscf
ng/J f-
lb/10D Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity
15350
389 425
13731 15001
483
17Q4Q
433
15281
55.9
0.130
49.9
44.7
0.1Q4
0
30084
12934
9.74
0.82
0
* Average for all tests. Test specific data was not recorded.
C-146
-------
Plant EEE
Two boilers, boilers 1 and 3, were tested at Plant EEE under a U. S.
EPA Innovative Technology Order. Boiler 1 is a Babcock and Wilcox unit
with a traveling grate spreader stoker rated at 40,000 Ib/hr of dry
saturated steam. Boiler 3 is also a Babcock and Wilcox unit with a
traveling grate spreader stoker rated at 55,000 Ib/hr of dry saturated
steam.
Both boilers are equipped with a mechanical cyclone and bag filter
particulate control system. The filter receives only a portion (approximately
15 percent) of the exhaust gas after it has passed through the cyclone. The
mechanical cyclone on boiler no. 1 is a Joy 9 VGA-107 with a 3.8 inch W.G.
pressure drop and boiler no. 3 also has a Joy 9 VG-107 with a 3.8 inch W.G.
pressure drop. Both boilers have a pulse flow PF SQ4508 fabric filter with
144, 4 1/2 inch diameter by 8 ft., filter bags. The filter has a total
2 9
filter area of 1395 ft with a design air-to-cloth ratio of 6.45 scfm/ft .
Eight particulate emission tests were conducted on boiler no. 3 and
three tests on boiler no. 1 using EPA Method 5. During testing approximately
37 percent of the boiler no. 1's exhaust gas flow was sent to the filter
and 15 percent of the boiler no. 3's exhaust gas flow was sent to its filter.
The boiler load averaged 89 percent and 93 percent for boiler no. 1 and 3
33
respectively.
C-147
-------
PLANT EEE
BOILER NO. 1 33
TEST SUMMARY SHEETS (Particulates Only)
Test Number
One
Two
Three
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of design)
Percent flow to baghouse*
Gas Data.
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
2/6/80
37
_2/6/80
37
89_
37
12789
12826
3fifi
13159
52.8
0.123
51.6
0.120
«.QQ
1.79
* Average for all tests,
C-H8
-------
PLANT EEE
BOILER NO. 3
TEST SUMMARY SHEETS (Particulates Only)
33
Test Number
One
Two
Three
General Data
Four
Date
Time
Isokinetic Ratio
Boiler Load (% of design)a
Percent flow to baghouse
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm3/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.C.)
Moisture (%)
Particulate Emissions
g/dnm3
Gr/dscf
ng/J
lb/106 Btu
Fuel Analysis
Heating Value (kj/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
3/24/SO
101
15
350
0.119
0.0518
3/25/80
3/25/80
3Z25/BO
_19_ 103
0.104
0.0453
52.9
0.123
0
2.09
0
0.112
0.0491
54.2
0.126
Average for Tests 1-4
_JLQ£L
15
338
0.120
0.0523
58.5
0.136
Average during testing.
Opacity was determined by Bailey Smoke Density recorder.
C-HP
-------
PLANT EEE
BOILER NO. 3
TEST SUMMARY SHEETS (Participates Only)
Test Number
Five
Six
Seven
Eight
Average
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of rating)a
Percent flow to baghouse
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnirr/min)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
Particulate Emissions
g/dnm
gr/dscf
ng/J 6
lb/10° Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
b
Average Opacity (%)
3/26/80
105
15
596
21039
170
0.133
0.0583
64.1
0.149
Average
_^
3/26/80 3/26/80
104 102
15 15
20913 20801
341 350
0.126 0.132
0.0551 0.0577
61.9 65.8
0.144 0.153
for Tests 5-8
2R?Q1
17163
8. 76
2.09
0 0
3/26/80
100
15
596
21039
175
347
0.142
JLM21
70. 9
0.165
0
JO-2.
15
593
20936
172
341
0.124
0.0540
61.2
0.142
28853
12405
8.76
2.09
Average during testing.
b Opacity was determined by Bailey Smoke Density recorder,
C-150
-------
Plant FFF
Boiler No. 3, a Babcock and Wilcox traveling grate spreader stoker,
with a capacity of 100,000 Ib/hr of dry saturated steam was tested under
a U, S. EPA Innovative Technology Order.
The particulate control system consists of a Universal Oil BT-6-
UPE-WHT mechanical cyclone with a design pressure drop of 11 inches W.G.
and a Standard Havens Beta Mark III bag filter containing 156, 6 1/2
inch diameter by 14 ft., filter bags. The filter thus provides a total
filter area of 3259 ft.2 and has a design air-to-cloth ratio of 3.44
2
scfm/ft . The bag filter receives only a portion of the total boiler
exhaust. Approximately 15 percent of the gas flow is ducted from the
base of the cyclone to the bag filter.
Four particulate emission tests were conducted using EPA Method 5.
During testing 17 percent of the total boiler gas flow was sent to the
33
filter. Boiler load averaged 89 percent.
C-151
-------
PLANT FFF
TEST SUMMARY SHEETS (Particulates Only)33
Test Number
One
Two
Three
Four
Average
G en e raJ__Da_ta_
Date
Time
Isokinetic Ratio (%)
Boiler Load (% of rating)
Percent flow to baghouse*
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnm-^/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
Particulate Emissions
g/dnm
gr/dscf
ng/J fi
lb/10° Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
January 8-9^
86
965
33704
86.0
0.200
85
958
33830
65.8
944
33322
961
954
337QQ
0.136
57.6
0.134
67, n
n IRK
30503
13114
1.67
Average for all tests.
One-hour opacity evaluation.
C-152
-------
Plant GGG
Boiler No. 3, a Babcock and Wilcox unit with a traveling grate
spreader stoker, was tested under a U. S. EPA Innovative Technology
order. The boiler is rated at 60,000 Ib/hr of dry saturated steam.
The particulate control system consists of a mechanical cyclone and
a bag filter. The mechanical cyclone is a Western Precipitation 9 VG12
with a 2.5 inch pressure drop. The bag filter receives only a portion
of the total boiler gas flow, approximately 15 percent. The bag filter
gas flow is ducted from the mechanical cyclone therefore there is some
treatment of the gas prior to the filter. The filter is a Pulse Flow PF
SQ4508 consisting of a housing containing 144, 4 1/2 inch diameter by 8
foot, filter bags. The filter provides a total filter area of 1395 ft.
2
with a design air-to-cloth ratio of 6.45 scfm/ft .
Four particulate emission tests were performed using EPA Method 17,
a modification of Method 5.
During the tests the filter received approximately 30% of the total
33
boiler gas flow. The boiler loading averaged 77 percent.
C-153
-------
PLANT GGG
TEST SUMMARY SHEETS (Participates Only)33
Test Number
General Data
Date
Time
Isokinetic Ratio (%)
Boiler Load (/; of rating)
Percent flow to baghouse*
Gas Data
Velocity (mps)
Velocity (fps)
Flow (dnnP/min)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Pressure (inches W.G.)
Moisture (%)
Particulate Emissions
3
g/dnm
gr/dscf
lb/106 Btu
Fuel Analysis
Heating Value (kJ/kg)
Heating Value (Btu/lb)
% Ash
% Sulfur
Average Opacity (%)
One
12/4/79
80
JO
600
21200
230
446
0.11
0.05
55.9
0.13
Two Three Four
12/4/79 1275779 12/5/79
78 74 76
2Q50Q 19900 ?D?nn
448 435 44?
0.09 0.11 0.09
0.04 0.05 0.04
55.9 55.9 43.0
0.13 0.13 0.10
Average
J7_7
__10_
579
20450
228
443
0.10
0.05
52.7
0.12
31381
13689
4.28
0.94
* Average for all tests.
C-15/1
-------
C.2 VISIBLE EMISSION DATA
Table C.2-1 lists visible emission data collected with trans-
missometers, while Table C.2-2 lists data obtained with EPA Method 9
visual methods.
C-155
-------
TABLE C.2-1. OPACITY TRANSMISSOMETER DATA
Boiler Loa<
Type of Boiler 10J lb/hr'
Pulverized Coal
(Plant KK)
Spreader Stoker
(Plant UU)
Spreader Stoker
(Plant VV)34
Spreader Stoker
(Plant EE #2)
Spreader Stoker
(Plant EE #4)
168
166
164
215
173
189
167
185
170
94
96
95
94"
94
88
95
93
95
70
70
72
71
56
61
60
70
69
49
52
16
50
49
49
77
78
78
Parti cu late
d Mass Loading
Control Equipment ng/J lb/10D Btu
Fabric Filter 12.8
8.4
7.8
7.8
6.4
4.3
2.5
3.2
3.2
Mechanical Collector 670
610
600
570
540
500
450
450
420
Mechanical Collector 400
360
360
350
300
260
250
240
220
220
180
160
Mechanical Collector 3.9
and Fabric Filter 6.5
8.6
Mechanical Collector 3.0
and Fabric Filter 4.3
5.6
0.030
0.020
0.018
0.018
0.015
0.010
0.006
0.007
0.008
1.55
1.42
1.40
1.34
1.26
1.16
1.05
1.05
0.99
0.931
0.839
0.842
0.827
0.690
0.596
0.577
0.553
0.516
0.513
0.426
0.380
0.009
0.015
0.020
0.007
0.010
0.013
Opacity
Percent
0
0
0
0
0
0
0
0
0
35
35
25
30
25
25
25
25
25
10
10
10
10
10
12
11
10
10
10
10
11
<10
<10
<10
<10
C-15C
-------
TABLE C.2-1. (CONTINUED)
Parti cu late
Boiler Load Mass Loading
Type of Boiler 10J lb/hra Control Equipment ng/J 1b/10° Btu
Spreader Stoker
(Plant EE #5)
Vibrating Grate
Stoker (Plant R)
Spreader Stoker
(Plant BBB)
Spreader Stoker
(Plant EEE)
Boiler #1
Spreader Stoker
(Plant EEE)
Boiler #3
145
144
78
78
55
77
58
80
57
79
71
78
59
57
59
58
55
53
50
56
55
54
51
55
37
34
36
40
41
42
42
40
40
41
40
Mechanical Collector 7.7
and Fabric Filter 16
Mechanical Collector 320
290
260
250
240
210
210
180
180
170
160
150
140
140
Sidestream Separator 75
74
74
72
72
71
66
65
Sidestream Separator 53
52
50
Sidestream Separator 71
66
64
62
61
59
54
53
0.018
0.038
0.754
0.667
0.595
0.574
0.557
0.490
0.488
0.424
0.421
0.393
0.372
0.354
0.328
0.319
0.175
0.173
0.171
0.167
0.166
0.164
0.154
0.151
0.123
0.120
0.117
0.165
0.153
0.149
0.144
0.143
0.136
0.126
0.123
Opacity
Percent
<10
<10
35
19
11
23
30
29
12
19
19
32
12
12
12
12
6
6
6
6
6
6
6
6
10
5
5
0
0
0
0
0
0
0
0
Steam output from boiler.
C-157
-------
TABLE C.2-2. OPACITY EPA REFERENCE METHOD 9
Boi:
Type of Boiler 101
Pulverized Coal
(Plant C)
Spreader Stoker
(Plant JO)
(Pulse Jet Cleaning
Mode)
Spreader Stoker
(Plant JJ)
(Reverse Air
Cleaning Mode)
Spreader Stoker
(Plant J2)
Pulverized Coal
(Plant II)
Residual Oil Fired
(Plant HHH)
Spreader Stoker
(Plant K-Boiler #9)
Underfeed Stoker
(Plant H)
Spreader Stoker
(Plant XX)
ler Loa
3 lb/hr
250
250
250
80
75
45
52
3744
3789
3735
124
126
124
31
27
28
75
75
75
60
Particulate
d Mass Loading
Control Equipment ng/J lb/10 Btu
Fabric Filter 18
15
14
Fabric Filter 6
Fabric Filter 5
4
4
Fabric Filter 9
9
10
23
Scrubber 67
47
28
21
ESP 44
30
28
ESP 5.6
5.2
4.3
Mechanical Collector 30
30
26
Mechanical Collector 220
170
210
110
0.043
0.034
0.032
0.013
0.011
0.010
0.009
0.020
0.021
0.023
0.054
0.157
0.109
0.066
0.048
0.102
0.070
0.065
0.013
0.012
0.010
0.09
0.07
0.06
0.506
0.392
0.494
0.253
Opacity.
Percent
2.5C
2.5
2.5
0
<1
0
0
oc
-------
TABLE C.2-2. (CONTINUED)
Type of Boiler
Boiler Load
1(T lb/hra
Particulate
Mass Loading Opacity.
Control Equipment ng/J lb/10 Btu Percent
Spreader Stoker
(Plant FFF)
90
Sidestream Separator 70 0.156
<1
Spreader Stoker
(Plant ODD)
31
31
31
31
Sidestream Separator 56
55
50
45
0.130
0.128
0.116
0.104
0
0
0
0
Steam output from boiler.
Average of six-minute readings.
clncluded a soot blow cycle.
Soot blown continuously.
C-159
-------
C.3 S02 EMISSION REDUCTION DATA
This section presents continuous monitoring data for eight industrial
boiler wet FGD systems, one lime spray drying FGD system, and one fluidized-
bed combustion system. The test data for five of the wet FGD systems were
presented and discussed in Chapter 4 with regard to the level of S02 removal
achievable with well designed, operated, and maintained FGD systems. Test
data for the first large scale lime spray drying system is also presented
and discussed. This section contains daily test results for each of these
sites as well as the continuous monitoring data for three wet FGD systems
that were, for various reasons, not considered to be representative of well
designed and operated FGD systems. The reasons why these latter sites were
not considered to be representative are documented in their respective site
descriptions.
All the continuous monitoring tests of FGD systems were conducted
by EPA. At the start of each test program, the continuous monitors
were subjected to performance specification tests as delineated in
40 CFR 60, Appendix B (proposed revisions as of 10 October 1979). All
sampling and analysis during the performance tests were performed
according to EPA 40 CFR 60 Appendix A, Methods 1 through 6. S02
emission rates in ng/J (lb/10 Btu) were calculated from measured gas
stream concentrations combined with ultimate analyses and heating values
of the fuel fired at each site. The S02 removal efficiencies were then
determined by comparison of inlet and outlet emission rates. Only test
days with more than 18 hours of test data are reported.
Each site description that follows provides a brief process description
and daily average monitoring results in both tabular and graphical form.
References for original tests can be found at the end of this Appendix.
C-160
-------
Location I
The FGD system monitored at plant location I is a Peabody tray and
quench water scrubber. The scrubbing medium is a 50 weight percent
sodium hydroxide (NaOH) aqueous solution with a 35 gallon per minute
make up. A scrubber handling flue gases from a 150,000 Ibs. steam/hr
capacity Babcock and Wilcox (B&W) pulverized coal boiler was monitored.
The boiler is fired using Southern Illinois subbituminous coal with a
sulfur content between 3.55 to 3.73 weight percent.
The daily averaged test results are presented in Table C.3-1 to
C.3-3. Continuous monitoring data was obtained for 30 test days.
The hourly averaged boiler loadings ranged from 55,000 to 120,000 Ibs/hr.
35
with an average of about 72,000 Ibs/hr during the test period.
Figure C.3-1 illustrates daily average S02 removal efficiency, boiler
load, and scrubbing solution pH.
C-161
-------
TABLE C.3-1. DAILY AVERAGE S09 REMOVAL RESiJLTS
SODIUM SCRUBBING PROCESS -LOCATION I* ™
S02 Emission Rate at
Scrubber Inlet
a
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
30 Day
Average
ng/J
2380
2377
2403
2385
2274
2341
2406
2420
2396
2404
2392
2433
2450
2372
2433
2461
2420
2421
2376
2365
2354
2335
2480
2724
2229
2132
2109
2125
2072
1961
2348
1L
b
million/Btu
5.5
5.5
5.6
5.5
5.3
5.4
5.6
5.6
5.6
5.6
5.6
5.7
5.7
5.5
5.7
5.7
5.6
5.6
5.5
5.5
5.5
5.4
5.8
6.3
5.2
5.0
4.9
4.9
4.8
4.6
5.5
S02 Emission Rate at
Scrubber Outlet
ng/J
55
58
59
64
54
69
83
96
108
81
74
85
90
83
87
96
83
99
81
91
90
92
80
112
267
90
85
86
62
62
87
T i
lb
million/Btu
0.1
0.1
0.1
0.1
0.1
0.2
0.2
0.2
0.3
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.3
0.6
0.2
0.2
0.2
0.1
0.1
0.2
Percent
S02
Removal
97.7
97.6
97.6
97.3
97.3
97.0
96.5
96.1
95.5
96.7
96.9
96.5
96.3
96.5
96.4
96.1
96.6
95.9
96.6
96.2
96.2
96.1
96.7
95.4
88.3
95.7
96.0
96.0
96.9
96.8
96.2
a 18 Hours/day minimum test time,
C-162
-------
TABLE C.3-2. DAILY SUMMARY OF HOURLY BOILER LOADS ~fi
SODIUM SCRUBBING PROCESS - LOCATION I
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Minimum Hourly
Boiler Load
(1000 Ib steam/hr)
77
70
75
73
73
81
66
61
70
67
70
61
60
70
55
55
55
60
78
65
65
70
78
70
70
65
60
60
65
50
24-Hour Average
Boiler Load
(1000 Ib steam/hr)
81
77
79
83
77
84
68
69
73
70
73
67
66
70
58
55
55
73
81
67
71
79
80
78
77
65
76
70
65
62
Maximum Hourly
Boiler Load
(1000 Ib steam/hr)
86
81
98
120
80
90
75
80
75
73
77
72
68
70
60
55
55
80
85
70
80
82
82
80
80
70
80
85
65
110
a!8 Hours/day minimum test time.
C-163
-------
TABLE C.3-3.
DAILY SUMMARY OF pH LEVELS
SODIUM SCRUBBING PROCESS -
LOCATION 137
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Minimum pH
Reading
7.8
7.7
7.8
7.7
7.8
7.8
' 7.9
8.2
7.9
8.1
7.8
8.2
8.0
8.0
8.0
8.1
8.0
7.8
-
-
8.0
7.8
-
-
_
8.0
_
_
8.0
7.8
Daily Average
pH Level
8.0
8.1
7.9
8.0
8.0
7.9
8.0
8.2
8.0
8.1
8.1
8.8
8.1
8.0
8.0
8.1
8.0
7.8
7.9
8.5
8.1
8.0
8.0
8.3
8.2
8.4
8.2
8.2
8.2
8.1
Maximum pH
Reading
8.2
8.3
8.2
8.3
8.1
8.0
8.2
8.2
8.1
8.2
8.7
9.4
8.1
8.0
8.0
8.1
8.0
7.9
-
-
8.1
8.3
-
-
-
8.8
-
-
8.4
8.4
JNo minimum or maximum readings are given on those test days for which only
one reading was taken.
C-1641
-------
ro
>
O
CM
O
100
90
80
70
10
15
Average S02 Removal = 96.2%
20
25
30
-o
0}
O
90
80
70
60
cu
i so
CO
40
30
10
15
20
25
30
10 15 20
Test Days
25
30
Figure C.3-1. Daily average S02 removal, boiler load, slurry
pH for the sodium scrubbina process at Location I.
C-165
-------
Location II
The FGD system monitored at plant location II is an Airpol Venturi
scrubber. The scrubbing medium is an aqueous solution of sodium hydroxide
(NaOH) and sodium carbonate (^COs). The scrubber handles flue gases from
two oil-fired steam generators, a hog fuel-fired steam generator and a
recovery boiler. The boilers are fired with No. 6 fuel oil containing four
percent sulfur with Gross Calorific Value (GCV) of 39,929 kJ/kg (17,167 Btu/lb)
Each unit produces 100*000 Ib of steam/hour. These units operate in tandem
with the hog-fueled unit which supplied up to 50 percent of the total process
steam demand. The amount of steam produced by the hog-fired unit depended on
the supply of the hog fuel. Therefore, under normal operating conditions,
there were large and unpredictable fluctuations in the steam demand on the
two oil-fired units.
The daily averaged test results are presented in Table C.3-4. Continuous
monitoring data was obtained for 22 test days. The hourly combined averaged
boiler loadings ranged from 35,000 to 265,000 Ibs/hr with an average of
38
about 103,000 Ibs/hr during the test period.
Despite the fact that average S02 removal for the test period was greater
than 90 percent, the wide fluctuations in removal efficiency are not
39
considered to be representative of a well-operated FGD system.
.C-lCf'
-------
TABLE C.3-4.
DAILY AVERAGE S02 REMOVAL RESULTS
SODIUM SCRUBBING PROCESS - LOCATION II
Test
Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
22 Day
Average
SOo
at
ng/J
1827
1830
1829
1986
2088
2334
2220
1960
2116
2224
2089
1882
1591
1429
1692
1532
2101
1670
1803
1889
1627
2818
1934
Emission Rate
Scrubber Inlet
Lb
Million Btu
4.3
4.3
4.3
4.6
4.9
5.4
5.2
4.6
4.9
5.2
4.9
4.4
3.7
3.3
3.9
3.6
4.9
3.9
4.2
4.4
3.8
6.6
4.5
SO,
at2
ng/J
52.
27.
480.
46.
149.
67.
140.
119.
28.
109.
99.
544.
12.
23.
15.
347.
28.
24.
43.
752.
338.
69.
160
Emission Rate
Scrubber Outlet
Lb
Million Btu
0.1
0.1
1.1
0.1
0.3
0.2
0.3
0.3
0.1
0.3
0.2
1.3
0.0
0.1
0.0
0.8
0.1
0.1
0.1
1.7
0.8
0.2
0.4
Percent
S02
Removal
97.2
98.5
73.7
97.7
92.9
97.1
93.7
93.9
98.7
95.1
95.3
71.1
99.3
98.4
99.1
77.3
98.7
98.6
97.6
60.2
79.2
97.6
91.7
18 hours/day minimum test time
C-167
-------
Location III
Two FGD systems were monitored at plant location III. Both systems
consist of dilute double alkali scrubbing in valve tray type absorbers
supplied by Koch Engineering Company. SCL in the flue gas is absorbed
by a regenerated caustic soda solution (0.1 M NaOH), forming a solution
of soluble sodium salts. The absorber has a quench spray section at the
inlet and full diameter chevron mist eliminators at the outlet. A portion
of the circulating liquor containing a mixture of sodium sulfate is bled
to a reactor/clarifier system where active alkali is regenerated by
reacting the solution with a slurry of lime. The precipitated solids
are further reacted and concentrated in a clarifier.
The individual scrubbers handle flue gases from coal-fired boilers
No. 1 and No. 3. Each boiler is a spreader-stoker unit with a maximum
rated capacity of 100,000 and 60,000 Ibs/hour of steam, respectively, for
41
boilers No. 1 and No. 3. Normal burning of eastern coal containing
1.7 to 2.7 percent sulfur, plus occasional lower sulfur waste oil results
in flue gas generally containing 800 to 1,300 ppm of S02.
The daily average test results are presented in Tables C.3-5 through
C.3-10. Continuous monitoring data was obtained for 17 and 24 test days
for the FGD systems on boiler No. 1 and No. 3, respectively. Figures
C.3-2 and C.3-3 present daily S02 removal boiler load, and slurry pH
for the two boilers.
C-1C8
-------
TABLE C.3-5.
DAILY AVERAGE S02 REMOVAL RESULTS
DUAL ALKALI PROCESS
LOCATION III (BOILER NO. 1)
42
S02 Emission Rate
at Scrubber Inlet
Test
Daya
1
2
3
4
5
6
7
8
9
10
n
12
13
14
15
16
17
17 Day
Average
ng/J
1659
1720
1698
1634
1594
1320
1235
1539
1806
2000
1680
1670
1619
1722
1811
1564
1706
1646
Lb
Million Btu
3.8
4.0
4.0
3.8
3.7
3.1
2.9
3.6
4.2
4.7
3.9
3.9
3.8
4.0
4.2
3.6
4.0
3.8
S02 Emission Rate
at Scrubber Outlet
ng/J
194
165
163
117
97
134
93
138
101
137
156
81
172
213
134
no
135
138
Lb
Million Btu
0.5
0.4
0.4
0.3
0.2
0.3
0.2
0.3
0.2
0.3
0.4
0.2
0.4
0.5
0.3
0.3
0.3
0.3
Percent
S02
Removal
88.2
90.3
90.4
92.8
93.6
89.9
92.4
90.8
94.6
93.0
90.6
95.2
89.4
87.6
92.6
93.0
92.1
91.6
18 Hours/day minimum test time.
C-159
-------
TABLE C.3-6. DAILY AVERAGE S02 REMOVAL RESULTS
DUAL ALKALI PROCESS
LOCATION III (BOILER NO. 3)
42
S02 Emission Rate
at Scrubber Inlet
Test
Day a
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
24 Day
Average
ng/J
1534
1223
1246
1247
1180
1275 '
1284
1215
1634
1678
1892
1631
1647
1715
1934
1997
2285
2084
1648
1652
1707
1628
1561
1647
1606
Lb
Million Btu
3.6
2.9
2.9
2.9
2.8
3.0
3.0
2.8
3.8
3.9
4.4
3.8
3.8
4.0
4.5
4.6
5.3
4.8
3.8
3.8
4.0
3.8
3.6
3.8
3.7
S02 Emission Rate
at Scrubber Outlet
ng/J
62
64
78
70
82
73
37
40
446
342
201
85
61
70
153
177
110
137
133
139
132
108
128
150
128
Lb
Million Btu
0.1
0.1
0.2
0.2
0.2
0.2
0.1
0.1
1.0
0.8
0.5
0.2
0.1
0.2
0.4
0.4
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
Percent
S02
Removal
95.9
94.8
93.7
94.5
93.0
94.1
97.1
96.7
73.6
79.2
89.3
94.9
96.3
95.9
92.2
91.1
95.1
93.2
92.0
91.6
92.3
93.4
91.9
91.1
92.2
18 Hours/day minimum test time.
C-170'
-------
TABLE C.3-7. DAILY SUMMARY OF HOURLY BOILER LOADS
DUAL ALKALI PROCESS A9
LOCATION III (BOILER NO. 1)
Test Daya
1
2
3
4
5
6
7
8
9
10
n
12
13
14
15
16
17
Minimum Hourly
Boiler Load
(1000 Ib steam/hr)
60
60
65
67
60
55
53
52
55
52
47
60
53
42
49
53
50
24-Hour Average
Boiler Load
(1000 Ib steam/hr)
74
80
73
74
76
68
67
68
66
56
53
71
67
65
54
67
65
Maximum Hourly
Boiler Load
(1000 Ib steam/hr)
88
96
80
80
93
84
76
89
76
63
60
86
83
82
59
81
76
a!8 Hours/day minimum test time.
C-171
-------
TABLE C.3-8. DAILY SUMMARY OF pH LEVELS
DUAL ALKALI PROCESS ,~
LOCATION III (BOILER NO. 1)
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Minimum pH
Reading
6.0
6.0
6.0
6.0
5.6
• 5.8
6.0
6.0
5.7
5.8
5.9
5.7
5.9 '
6.0
6.0
6.0
6.0
Daily Average
pH Level
6.0
6.0
6.0
6.0
5.8
5.9
6.0
6.0
6.0
5.9
6.1
6.0
6.1
6.0
6.0
6.1
6.0
Maximum
Readi
6.0
6.0
6.0
6.0
6.0
6.0
6.0
6.0
6.0
6.0
6.3
6.2
6.3
6.0
6.0
6.5
6.0
PH
ng
C-172
-------
TABLE C.3-9. DAILY SUMMARY OF HOURLY BOILER LOADS
DUAL ALKALI PROCESS .9
LOCATION III (BOILER NO. 3)4^
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Minimum Hourly
Boiler Load
(1000 Ib steam/hr)
3
22
25
26
34
37
36
38
30
28
27
5
38
19
38
34
29
27
29
25
24
20
28
24
24-Hour Average
Boiler Load
(1000 Ib steam/hr)
32
34
34
36
39
40
40
41
41
37
38
42
43
38
46
42
39
39
35
32
32
31
35
32
Maximum Hourly
Boiler Load
(1000 Ib steam/hr)
43
48
40
46
43
43
42
42
56
47
49
53
50
45
57
50
50
50
45
42
41
39
43
42
a!8 Hours/day minimum test time.
C-173
-------
TABLE C.3-10.
DAILY SUMMARY OF pH LEVELS
DUAL ALKALI PROCESS
LOCATION III (BOILER NO. 3
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Minimum pH
Reading
5.2
5.0
5.8
5.8
5.8
5.8
5.9
5.8
6.0
-
-
-
-
-
5.9
5.9
6.0
6.0
6.0
4.7
6.0
6.0
6.0
6.0
Daily Average
pH Level
5.8
6.0
6.0
6.0
6.0
5.9
6.0
6.0
6.0
-
-
-
-
-
6.0
6.0
6.1
6.0
6.0
5.8
6.0
6.0
6.0
6.0
Maximum pH
Reading
6.2
6.5
6.1
6.0
6.2
6.0
6.2
6.2
6.0
-
-
-
-
-
6.1
6.2
6.1
6.0
6.0
6.1
6.1
6.1
6.0
6.0
*No pH data available for test days 10 through 14,
C-17/1-
-------
lOOr
•5 90
>
o
Ol
on
o
t/J
80
Average S02 Removal = 91.6%
10
15
20
25
30
90
80
70
60
£ 50
40
30
-a
(O
o
i.
01
o
CQ
10
15
20
25
30
• • •
10 15 20
Test Days
25
Figure C.3-2.
Daily average S02 removal, boiler load, and
slurry pH for the dual alkali scrubbing
process at Boiler No. 1, Location III.
30
C-175
-------
100
90
oo
o
80
Average S02 Removal = 92.2%
10
15
20
25
30
•a
1T3
o
80
70
60
Ol
i 50
CD
** 40
30
10
15
20
25
30
10 15 20
Test Days
25
Figure C.3-3.
30
Daily average 502 removal, boiler load, and
slurry pH for scrubbing process at Boiler No. 3
Location III.
C-17S
-------
Location IV - Lime System
Three data sets were taken on a lime/limestone FGD system at location
IV. One of the tests monitored the system under lime sorbent operations
and the two other tests monitored the system while it operated using limestone
as a sorbent. In one of the two limestone tests, adipic acid was added
to improve SCL removal efficiency.
Particulates are removed from the flue gas in a mechanical collector
upstream of the absorber. The absorber is a two-stage unit with fresh
solvent make-up being introduced at the second stage. Flue gas from the
absorber enters a cyclonic mist eliminator before going to the stack.
The scrubber system was designed to treat the combined flue gas from
seven small stoker boilers at the peak winter load of approximately
210 x 10 Btu/hr. Typical fuel burned at the facility is mid-west
coal with a sulfur content of about 3.5 percent. The system has essentially
unlimited turndown capability since it mixes air with flue gas to maintain
a constant flue gas rate at low boiler loads. Consequently, 502
concentrations will vary from about 200 to 2000 ppm depending upon the
boiler load. S02 emissions averaged 194 ng/J during the tests.
The daily average test results for operation with lime sorbent
are presented in Tables C.3-11 through C.3-13. Continuous monitoring
data was obtained for 29 days with overall average S0£ removal of 91.2.
Figure C.3-4 shows the daily S02 removal boiler load, and slurry
pH levels.
C-177
-------
TABLE C.3-11.
DAILY AVERAGE S02 REMOVAL RESULTS
LIME SLURRY PROCESS
LOCATION IV45
SC>2 Emission Rate
at Scrubber Inlet
Test
Day a
1
2
3
4
5
6
7
8
9
10
n
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
29 Day
Average
ng/J
2021
2175
2293
2277
2245
2344 '
2333
2310
2355
2318
2220
2334
2432
2418
2390
2255
2272
2318
2299
2262
2145
2273
2359
2116
2207
2245
2125
1990
1927
2250
Lb
Million Btu
4.7
5.1
5.3
5.3
5.2
5.5
5.4
5.4
5.5
5.4
5.2
5.4
5.7
5.6
5.6
5.2
5.3
5.4
5.4
5.3
5.0
5.3
5.5
4.9
5.1
5.2
4.9
4.6
4.5
5.2
SOo Emission Rate
at Scrubber Outlet
ng/J
211
230
160
179
237
194
260
186
146
189
124
94
194
127
128
205
201
218
216
1:99
131
185
213
150
294
279
285
149
190
192
Lb
Million Btu
0.5
0.5
0.4
0.4
0.6
0.5
0.6
0.4
0.3
0.4
0.3
0.2
0.5
0.3
0.3
0.5
0.5
0.5
0.5
0.5
0.3
0.4
0.5
0.4
0.7
0.6
0.7
0.3
0.4
0.4
Percent
S02
Removal
89 7
\j *J • /
89 4
\j •/ • ~
93 0
J*J • W
92 2
^ L_ * (_
89 4
\j -s • ~
91 .6
88 8
\J\S • W
92.0
93.8
91 .8
94.4
96.0
92.0
94.7
94.6
91 .0
91.2
90.6
90.6
91 .3
93.8
91.9
90.9
93.4
86.7
87.6
86.8
92.4
90.6
91.5
18 Hours/day minimum test time.
C-178
-------
TABLE C.3-12.
DAILY SUMMARY OF HOURLY BOILER LOADS
LIME SLURRY PROCESS
LOCATION IV45
Test Dayc
Minimum Hourly
Boiler Load
(million Btu/hr)
24-Hour Average
Boiler Load
(million Btu/hr)
Maximum Hourly
Boiler Load
(million Btu/hr)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
99
98
102
100
104
106
103
94
102
99
99
97
99
78
72
111
96
98
106
109
90
81
105
90
86
88
90
72
78
106
107
110
108
113
113
116
110
112
113
112
109
113
112
93
120
115
113
121
125
110
102
116
104
107
99
97
82
93
118
119
120
120
125
127
131
118
119
122
123
118
129
126
109
132
127
132
134
136
128
117
134
127
127
109
106
95
105
18 Hours/day minimum test time,
C-171?
-------
TABLE C.3-13.
DAILY SUMMARY OF pH LEVELS
LIME SLURRY PROCESS
LOCATION IV46
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Minimum pH
Reading
7.8
7.9
4.6
7.6
5.8
1 8.0
7.2
7.5
7.1
7.0
7.4
8.0
7.4
7.2
7.6
6.2
6.8
7.8
6.6
7.8
7.8
7.8
8.0
7.8
5.6
4.8
3.8
6.3
4.7
Daily Average
pH Level
7.9
8.3
6.3
7.7
6.6
8.2
7.4
7.9
7.4
7.3
7.5
8.5
7.5
7.3
8.4
6.5
6.8
8.3
7.4
7.9
7.9
7.9
8.1
7.9
6.3
5.3
4.3
6.6
5.6
Maximum pH
Reading
8.0
8.5
8.0
7.8
7.6
8.4
7.6
8.2
8.0
7.8
7.6
9.2
7.6
7.4
9.9
7.0
6.9
8.8
8.3
8.0
8.0
7.9
8.2
8.0
6.8
6.0
4.7
7.0
6.1
C-180
-------
100
5 90
o
CVJ
o
80
10
15
Average S02 Removal = 91.5%
20
25
30
03
O
CD
10 15 20
Test Days
25
Figure C.3-4.
Daily average S02 removal, boiler load, and
slurry pH for lime slurry scrubbing process
at Location IV.
30
C-181
-------
Location IV - Limestone (with and without Adipic Acid Addition)
The FGD system at Location IV was also monitored during limestone
operation. Tests were conducted both with and without adipic acid
addition (References 47 and 48, respectively).
In 36 days of testing without adipic acid addition, SCL removal
averaged 58.7 percent (Table C.3-14). This relatively low SO^ removal
is attributed to two factors: (1) the system is not designed for high
SOp removal with limestone and (2) evidence that the system was
operated at gas flows of about 20 percent greater than the design
39
value. For these reasons, the results from limestone only tests
are not considered representative of a well designed and operated
industrial boiler wet FGD system.
As shown in Table C.3-15, S02 removal averaged 94.3 percent
during 30 days of testing with adipic acid addition. This higher removal
was attributed to the effects of adipic acid as well as the effort
during the test program to maintain higher limestone feed rates than
47
those used during limestone only testing. Table C.3-16 presents
daily average outlet S02, boiler load, adipic acid concentration, and
slurry pH for the test period. Figure C.3-5 shows daily average
SO removal, boiler load, adipic acid concentration and slurry pH.
C-182
-------
TABLE C.3-14.
DAILY AVERAGE S02 REMOVAL RESULTS
LIMESTONE SLURRY PROCESS
LOCATION IV48
a
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
36 Day
Average
Emission
Scrubber
ng/J Mil
2351
2705
2792
2590
2670
2652
2681
2705
2691
2762
2983
2922
2740
2551
2764
2744
3043
2897
3038
2435
2340
2484
2686
2672
2662
2882
3197
3646
3349
3386
3296
3484
3446
3227
3219
2991
2880
Rate at
Inlet
Lb
lion Btu
5.5
6.3
6.5
6.0
6.2
6.2
6.2
6.3
6.3
6.4
6.9
6.8
6.4
5.9
6.4
6.4
7.1
6.7
7.1
5.7
5.4
5.8
6.2
6.2
6.2
6.7
7.4
8.5
7.8
7.9
7.7
8.1
8.0
7.5
7.5
7.0
6.7
Emission
Scrubber
Rate at
Outlet
Lb
ng/J Million Btu
1334
1290
912
945
1189
1283
1318
1549
1635
1627
1723
1496
1300
1298
1285
1471
1237
1218
1417
1253
1013
928
994
1102
989
1101
832
806
903
1040
946
1002
764
758
1012
1256
1173
3.1
3.0
2.1
2.2
2.8
3.0
3.0
3.6
3.8
3.8
4.0
3.5
3.0
3.0
3.0
3.4
2.8
2.8
3.3
2.9
2.4
2.2
2.3
2.6
2.3
2.6
1.9
1.9
2.1
2.4
2.2
2.3
1.8
1.8
2.4
2.9
2.7
Percent
S02
Removal
43.3
51.9
66.8
63.6
55.3
51.5
50.9
42.7
39.4
41.1
42.5
48.8
52.4
49.0
53.5
46.5
59.6
57.9
52.9
48.4
56.5
62.5
63.0
58.7
62.8
61.1
72.5
76.4
73.1
68.9
71.2
71.4
77.8
76.5
68.3
57.9
58.2
18 Hours/day minimum test time.
C-183
-------
TABLE C.3-15.
DAILY AVERAGE S02 REMOVAL RESULTS
FOR LIMESTONE SLURRY PROCESS WITH ADIPIC
ACID ADDITION - LOCATION IV47
Emission Rate at
Scrubber Inlet
Emission Rate at
Scrubber Outlet
Percent SO,
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
30 Day
Average
ng/J
1720
1333
1767
1642
1789
1793
2098
1879
1913
2661
2240
2128
2244
1995
2356
2137
2644
2085
1943
2765
2313
2077
2180
2060
2266
2214
2322
2365
2648
2176
2125
1i_
b
Million Btu
4.0
3.1
4.1
3.8
4.2
4.2
4.9
4.4
4.5
6.2
5.2
5.0
5.2
4.6
5.5
5.0
6.2
4.9
4.5
6.4
5.4
4.8
5.1
4.8
5.3
5.2
5.4
5.5
6.2
5.1
4.9
ng/J
129
60
103
129
159
116
116
90
95
194'
129
138
65
108
237
138
138
125
165
262
155
60
56
77
142
82
73
90
146
69
122
1i
b
Million Btu
0.3
0.1
0.2
0.3
0.4
0.3
0.3
0.2
0.2
0.5
0.3
0.3
0.2
0.3
0.6
0.3
0.3
0.3
0.4
0.6
0.4
0.1
0.1
0.2
0.3
0.2
0.2
0.2
0.3
0.2
0.3
Removal
92.5
95.5
94.2
92.1
91.1
93.5
94.5
95.2
95.1
92.7
94.2
93.5
97.1
94.6
90.0
93.6
94.8
94.0
90.5
90.5
93.3
97.1
97.4
96.2
93.7
96.3
96.9
96.2
94.5
96.8
94.3
a!8 Hours/day minimum test time.
C-184
-------
TABLE C.3-16.
DAILY AVERAGE BOILER LOAD, ADIPIC ACID
CONCENTRATION AND SLURRY pH
LIMESTONE SLURRY PROCESS WITH ADIPIC ACID
ADDITION - LOCATION IV47
Test Day
Boiler Load
Adi pic Acid Cone,
(ppm)
Slurry pH
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
30 day average
Minimum
Maximum
49
55
64
64
67
60
59
49
46
50
49
62
55
48
48
48
46
48
46
38
34
37
30
30
36
33
33
32
31
36
46
30
67
2305
2920
2090
2290
2150
1770
2165
1890
1855
1870
2050
3000
2680
2420
2200
2240
2150
2130
-
-
1920
1950
2040
2160
2200
2170
2820
2850
2510
2400
2257
1770
3000
4.7
4.9
4.7
4.9
-
5.0
5.0
5.0
4.8
4.9
4.7
-
5.2
5.4
5.4
4.7
5.2
5.3
5.0
-
-
4.9
5.5
4.8
4.7
4.6
5.1
5.1
4.6
4.7
5.0
4.6
5.5
18 Hours/day minimum test time.
-------
o
o>
CM
O
-o
.
O. i-
3000
2500
2000
K 1500
7.Q
6.0
5.C-
4.0
3.0
10
10
15
15
Test Days
20
20
25
25
Figure C.3-5.
Daily average S02 removal, boiler load, adipic
acid concentration, and slurry pH for limestone
system at Location IV.
30
30
C-1P6
-------
Location V
The FGD system monitored at plant location V is a turbulent contact
absorber (TCA) prototype installation. The TCA unit, constructed by
Universal Oil Products, uses a fluid bed of low density plastic spheres
that migrate between retaining grids. The scrubbing medium is a lime
slurry. The pilot plant scale wet scrubber handles a side stream of the
flue gases from a coal-fired boiler power station having 10 turbines.
The daily averaged test results are presented in Table C.3-17.
49
Continuous monitoring data was obtained for 42 test days.
Because this unit is designed and operated as pilot plant, it is
not considered to be representative of industrial boiler wet FGD
39
systems designed and operated for maximum S0? removal.
C-187
-------
TABLE C.3-17. DAILY AVERAGE S02 REMOVAL RESULTS
LIME SLURRY PROCESS
LOCATION V50
SO?
Emission Rate
at'Scrubber Inlet
Test
Day3
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
42 Day
Average
ng/J
2541
2566
2549
2331
2270
2589
2588
2572
2449
2460
2266
2393
2274
2546
2711
2616
2322
2532
2250
2365
1961
2150
2440
2295
2313
1680
2163
2053
2132
2360
2635
2617
2594
2580
2579
2580
2315
2365
2486
2549
2225
2061
2389
Lb
Million Btu
5.9
6.0
5.9
5.4
5.3
6.0
6.0
6.0
5.7
5.7
5.3
5:6
5.3
6.0
6.3
6.1
5.4
5.9
5.2
5.5
4.6
5.0
5.7
5.4
5.4
3.9
5.0
4.8
5.0
5.5
6.1
6.1
6.0
6.0
6.0
6.0
5.4
5.5
5.8
5.9
5.2
5.6
S02 Emission Rate
at Scrubber Outlet
ng/J
264
289
306
283
237
354
380
395
347
331
247
215
240
326
314
301
227
255
194
233
160
200
253
229
331
164
270
222
351
415
367
350
309
295
319.
375
258
255
280
308
210
172
282
Lb
Million Btu
0.6
0.7
0.7
0.7
0.6
0.8
0.9
0.9
0.8
0.8
0.6
0.5
0.6
0.8
0.7
0.7
0.5
0.6
0.5
0.5
0.4
0.5
0.6
0.5
0.8
0.4
0.6
0.5
0.8
1.0
0.9
0.8
0.7
0.7
0.7
0.9
0.6
0.6
0.7
0.7
0.5
0.4
0.7
Percent
S02
Removal
89.6
88.8
88.0
88.0
89.7
86.4
85.5
84.6
85.8
86.5
89.1
91.0
89.5
87.2
88.4
88.5
90.5
90.1
91.4
90.3
92.1
91.1
89.7
90.0
85.9
90.2
88.0
89.2
83.7
82.5
86.1
86.6
88.1
88.5
87.6
85.5
88.9
89.2
88.8
88.0
90.9
91.7
88.4
18 Hours/day minimum test time.
C-lSf
-------
Location VI
The FGD system monitored at plant location VI is a spray drying
scrubber. The scrubbing-sorbent is a 26 percent high quality lime
(90-94% calcium oxide) slurry. Approximately 2 percent sulfur coal
was burned during most of the test period. Efficiencies found when
the daily inlet S02 concentrations are high (above 4.0 lb/10 Btu)
51
average 75 percent.
The daily averaged test results are presented in Table C.3-18 for the
23 test days. During this period, boiler load averaged 114 million
52
Btu/hr, with hourly loads ranging from 12 to 152 million Btu/hr. Figure
C.3-6 illustrates S02 removal and inlet S02 emissions for each test day
at this site.
C-189
-------
TABLE C.3-18. DAILY AVERAGE S02 REMOVAL RESULTS
SPRAY DRYING PROCESS
LOCATION VI52
Test
Day a
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
23 Day
Average
SO
at
ng/J
1471
1316
1230
1613
1312
1436
1178
1118
1269
1372
1475
1449
1122
1578
1810
1557
1905
1888
1711
1608
1578
1578
1746
1492
2 Emission Rate
Scrubber Inlet
Lb
Million Btu
3.4
3.1
2.9
3.8
3.1
3.3
2.7
2.6
3.0
3.2
3.4
3.4
2.6
3.7
4.2
3.6
4.4
4.4
4.0
3.7
3.7
3.7
4.1
3.5
SO
at
ng/J
400
390
517
634
702
568
415
452
433
638
347
393
397
460
473
627
530
418
340
340
375
339
387
460
2 Emission Rate
Scrubber Outlet
Lb
Million Btu
0.9
0.9
1.2
1.5
1.6
1.3
1.0
1.1
1.0
1.5
0.8
0.9
0.9
1.1
1.1
1.5
1.2
1.0
0.8
0.8
0.9
0.8
0.9
1.1
Percent
sn
b02
Removal
72.7
70.3
58.0
60.7
46.4
60.4
64.8
59.5
65.9
53.5
76.5
72.8
64.6
70.9
73.8
59.8
72.2
77.9
80.1
78.9
76.2
78.5
77.9
68.4
118 Hours/day minimum test time,
C-190
-------
-------
Location VII
The location monitored is a 100,000 Ib steam/hr coal/limestone feed
fluidized-bed boiler (FBB). The coal sulfur content of the bituminous coal
burned during testing ranged from 1.5 - 2.5 weight percent. The boiler load
during the period ranged from 50 to 60 percent.
The S0£ control used at this location was coal/limestone injection.
The design limestone flow rate was 3,133 Ib/hr, with actual conditions
ranging from 1,500 to 4,500 Ib/hr. The Ca/S ratio varied from
2-10 compared to a design value of 3. Low fly ash reinjection rates may
53
have increased S0? emissions by decreasing sorbent residence times.
The plant was being operated in an extended shakedown phase so that
operating conditions were not always in the intended design range.
C-192
-------
TABLE C.3-19. DAILY AVERAGE S09 REMOVAL RESULTS
FLUIDIZED-BED-COMBUSTION PROCESS
LOCATION VIIbJ
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
14 Day
Average
S0? Emission
Rate - Inlet
ng/J
1030
1030
1030
1090
1030
1030
1030
1030
1120
1236
1245
1439
1477
1679
1178
Ib
million Btu
2.4
2.4
2.4
2.5
2.4
2.4
2.4
2.4
2.6
2.9
2.9
3.3
3.4
3.9
2.7
Ra?
ng/J
197
256
220
171
62
55
47
88
78
49
178
242
215
224
149
Emission
e - Inlet
Ib
million Btu
0.5
0.6
0.5
0.4
0.1
0.1
0.1
0.2
0.2
0.1
0.4
0.6
0.5
0.5
0.3
Percent S02
Removal
80.9
75.1
78.7
84.3
94.0
94.7
95.4
91.4
93.1
96.2
85.7
83.2
85.4
86.3
87.5
a!8 Hours/day minimum test time.
-------
C.4 NOV EMISSION REDUCTION DATA
X
This section presents emission test data for NO reduction by
A
combustion modifications. The data include results of continuous
monitoring tests at five sites and the results of short-term (30-
minute to 2-hour) tests at a large number of sites. The short term data,
which were used to construct the plots in Section 4.3.7 of this report,
are presented in tabular form. Information given in these tables includes:
' test location,
' unit number (boiler designation),
* test number,
' test type,
fuel nitrogen content,
' combustion air temperature,
' heat release rate,
' excess oxygen, and
' NO emissions.
A
More information on the boiler design and operating parameters can be found
in Reference 54 and a complete description of the short-term emission testing
program can be found in References 55 and 56.
Descriptions of each continuous monitoring site are provided, along
with tabular and graphical presentations of daily average NO emissions,
A
02 levels, and boiler load. Only test days with 18 or more hours of
data are reported, unless noted otherwise.
Prior to commencing the monitoring programs, the NO monitoring
A
systems were certified in accordance with Performance Specification 2
(PS2) and Performance Specification 3 (PS3), 40 CFR 60, Appendix B.
Relative accuracy for the analyzers was tested using EPA Reference
Method 7. NO emission rates are given in ng/J (Ib/million Btu).
A
iC-194
-------
Location I
Low excess air (LEA) and staged combustion air (SCA) were the NO
/\
control technologies used at location I. Twenty-four months (681 days) of
24-hour average data was obtained for this pulverized coal-fired unit.
The unit consists of two boilers, numbered 3 and 4, sharing a common
stack, each with a rated capacity of 250,000 Ib steam/hr. Boilers 3 and
4 averaged 177,000 and 142,000 Ib steam/hr during the test period,
respectively, and were fired by coal that had a nitrogen content of
about 1.6 percent and a heat content of about 14,000 Btu/lb. The daily
results are summarized in Table C.4-1.
t-195
-------
TABLE C.4-1. DAILY AVERAGE NO EMISSIONS, OXYGEN LEVELS, AND
BOILER. LOADS PULVERIZEDXCOAL-FIRED - LOCATION I
(a) Month 1
Test Day
l
9
3
A
5
6
•j
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Monthly
Average
N0y
ng/J
236.5
236.5
258.0
215.0
258.0
358.0
258.0
236.5
236.5
2S8.0
258.0
258.0
238.0
279.5
236.5
249.4
236.5
236.5
215.0
249.4
2 7V. 5
279.5
322.5
331.1
313.9
258.0
258.0
236.5
236,5
236.5
236.5
255.4
Emission Rate
Ib
million Btu
0.55
0,55
0.60
0,50
0.60
0.60
0.60
0>55
0.55
0.60
0.60
0.60
0.60
0.65
0,55
0.58
0.55
0.55
0.50
0.58
0.65
0.65
0.75
0,77
0,73
0.60
0,60
0,55
0,55
0,55
0.55
0.59
00 Level
— L.
%
4.98
4,42
4,65
4,81
5,15
4,98
4.81
4,81
4,65
4,81
4.65
4.65
4,81
4.98
4,98
4,65
4,81
4,65
5,48
4,98
4,48
4,32
4,65
4,98
4,81
6,47
5,81
5,81
5.81
5,81
5.81
5.02
Boiler No.
3 Load
1000 Ib steam
hr
195
200
205
220
215
205
205
208
205
195
215
220
215
210
212
215
205
208
190
180
187
190
197
191
190
180
188
192
207
190
192
201
Boiler No.
4 Load
1000 Ib steam
hr
168
172
180
181
145
153
157
158
171
161
174
186
167
158
165
169
168
164
163
168
170
171
163
167
170
168
169
175
175
170
172
168
C-19S
-------
TABLE C.4-1. (CONTINUED)
(b) Month 2
N0%, Emission Rate
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Monthly
Average
A
ng/J
236,5
193*5
215.0
258.0
245.1
184.9
172.0
172.0
150,5
150.5
150.5
193.5
193.5
193.5
215.0
236.5
258.0
279*5
258.0
236.5
236.5
236,5
215.0
215.0
215.0
236.5
236.5
236,5
238 , 0
216.5
Ib
million Btu
0,55
0,45
0.50
0,60
0,57
0.43
0.40
0,40
0,35
0,35
0.35
0,45
0.45
0.45
0.50
0.35
0.60
0,65
0,60
0,55
0,55
0.55
0.50
0,50
0.50
0.55
0.55
0.55
0,60
0.50
00 Level
"~ L.
%
5,65
3,63
9,13
6,31
7.47
9.96
11,79
11,95
11,62
11,62
11,95
11,45
11,79
12,12
10,79
10,46
6,97
6,81
6,47
6,14
6,14
5,81
!j,64
5,64
5,64
6,31
6,47
6,81
8,47
8.48
Boiler No.
3 Load
1000 Ib steam
hr
191
'208
212
194
206
197
197
197
210
207
200
206
187
199
210
105
146
160
196
213
218
220
214
228
233
203
196
214
180
198
Boiler No.
4 Load
1000 Ib steam
hr
170
130
165
167
165
163
168
177
175
180
173
175
173
182
180
184
209
199
156
108
170
C-197
-------
TABLE C.4-1. (CONTINUED)
(c) Month 3
Test Day
i
'.•>
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
1?
20
21
22
23
24
25
26
27
28
29
30
31
Monthly
Average
NO
A
no/..)
2 -..ft .
:•'. / ri t 5
258,0
258 .0
215,0
234.5
236,5
258 »0
279,5
236.5
279*5
227.9
236,5
266.6
258,0
275.2
258,0
279,5
279,5
344,0
258,0
236,5
215,0
215,0
236,5
245,1
2/0,9
262,3
233,0
215,0
215.0
253.1
Emission Rate
Ib
mill ion Btu
'."i . f-. 0
0 , o5
• 0.60
0,60
0,50
0,55
0,55
0,60
0,65
0,55
0,65
0,53
0,55
0,62
0,60
0,64
0,60
0.65
0,65
0,80
0.60
0,55
0.50
0.50
0,55
0.57
0.63
0,61
0,60
0.50
0.50
0.59
00 Level
%
c .13
8,30
8.63
8,63
11.12
6,47
9.96
6,31
6.14
5.98
5.98
5,64
5.64
'j,98
5.98
7,80
7.97
3>SO
8,80
8,47
8.13
7,97
7.80
7.47
7,97
8,30
8,47
8.80
8,47
8.30
3,30
7.76
Boiler No.
3 Load
1000 Ib steam
hr
230
225
225
205
206
220
223
222
223
221
207
223
233
197
206
217
215
224
221
212
214
209
203
207
199
211
224
204
197
198
214
Boiler No.
4 Load
1000 Ib steam
hr
112
100
99
93
77
188
180
180
173
172
170
187
168
110
121
93
94
100
100
103
105
105
100
92
88
93
97
103
122
C-198
-------
TABLE C.4-1. (CONTINUED)
(d) Month 4
Test Day
1
2
3
A
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Monthly
Average
NO
A
ng/J
215,0
236.5
236.5
258.0
266.6
215.0
193.5
279.5
279.5
227.9
279.5
:•>:•> 3, 6
227.9
215.0
223.6
215.0
213,0
236.5
236.5
223.6
215.0
223.6
270.9
301.0
241). 1
223.6
253.7
258.0
270,9
258.0
223.6
240.2
Emission Rate
Ib
mill ion Btu
0,50
0.55
0.55
0.60
0.62
0,50
0.45
0.65
0,65
0,53
0,65
0,52
0.53
0.50
0.52
0,50
0,50
0.55
0.55
0.52
0.50
0.52
0,63
0.70
0,57
0.52
0,59
0.60
0.63
0.60
0.52
0.56
00 Level
£
%
8*30
8.30
8.80
6,97
6.81
7,47
7.64
9,46
8.47
9,96
9.96
8,30
7,97
8,47
8.47
8,17
8,80
8,96
3,63
8,30
8.13
8.13
8,13
8.30
8,13
8.30
8.30
8.13
7,97
8.30
7.47
8.32
Boiler No.
3 Load
1000 Ib steam
hr
190
186
185
188
208
215
200
132
133
206
193
186
178
175
170
156
155
161
158
J.64
174
175
169
171
161
162
173
180
166
194
175
Boiler No.
4 Load
1000 Ib steam
hr
105
100
100
100
147
120
120
156
174
177
186
200
140
C-199
-------
TABLE C.4-1. (CONTINUED)
(e) Month 5
Test Day
l
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
no
JL *.
23
24
25
26
Monthly
Average
NO
A
ng/J
279,5
322,5
279,5
292,4
292.4
270,9
180.6
193,5
180.6
236,5
215,0
215,0
215.0
227,9
236,5
1*27.9
245,1
279,5
236.5
215,0
2U5.0
236.5
','36.5
270.9
249.4
258,0
242.6
Emission Rate
Ib
mill ion Btu
0,65
0.75
0.65
0.68
0,68
0,63
0,42
0,45
0.42
0,55
0.50
0.50
0,50
0,53
0,55
0*53
0,57
0,65
0,55
0.50
0.50
0.55
0,55
0.63
0,58
0.60
0.56
00 Level
L.
%
8,13
7.64
7,47
7,14
7.97
10,29
12.45
11.12
11.62
9,13
8,30
7,97
7,97
3,17
8,30
8,47
8,13
8,80
8,30
7.80
7,47
7.80
8,30
7.97
7,97
8.13
8.58
Boiler No.
3 Load
1000 Ib steam
hr
193
205
193
169
161
174
171
182
206
176
172
166
170
175
183
189
177
172
169
180
179
Boiler No.
4 Load
1000 Ib steam
hr
215
190
210
220
213
200
102
110
107
107
103
100
95
98
98
93
108
105
95
100
95
90
90
128
C-20G
-------
TABLE C.4-1. (CONTINUED)
(f) Month 6
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
.17
18
19
20
21
22
23
24
25
26
Monthly
Average
NO
A
ng/J
258.0
245.1
301,0
279.5
279.5
292.4
279.5
258*0
288.1
275.2
296.7
270.9
227.9
301.0
270.9
266.6
236.5
215.0
215*0
266.6
270.9
292.4
240.8
163.4
129.0
236.5
256.0
Emission Rate
Ib
million Btu
0.60
0.57
0.70
0,65
0.65
0.68
0.65
0.60
0.67
0,64
0.69
0,63
0.53
0,70
0.63
0,62
0.55
0.50
0,50
0.62
0,63
0.68
0,56
0.38
0.30
0.55
0.60
00 Level
L. '
°/
h
7.97
9,63
11.29
6.31
6.81
6.81
6.47
5,81
6,64
6.31
6.81
5,98
6.14
6,64
6.64
5.81
5.64
10,99
7.80
7.97
7:97
8.13
7,97
7.80
7.35
Boiler No.
3 Load
1000 15 steam
hr
187
1.87
160
197
197
199
186
192
204
201
191
Boiler No.
4 Load
1000 Ib steam
hr
98
139
199
178
163
165
165
165
167
173
168
175
177
177
182
181
185
175
116
93
100
102
98
104
94
102
148
C-201
-------
TABLE C.4-1. (CONTINUED)
(g) Month 7
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Monthly
Average
NO
A
ng/J
215.0
258.0
258.0
305.3
236.5
245.1
243.1
258.0
'•! -115.1
245.1
215.0
215.0
215.0
193.5
236.5
240.8
236.5
215.0
163.4
193.5
215.0
184.9
184.9
215.0
223.6
243.1
258.0
238.0
229.3
Emission Rate
Ib
million Btu
0,50
0.60
0.60
0,71
0.55
0.57
0.57
0.60
0,57
0.57
0.50
0.50
0,50
0.45
0.55
0.56
0>55
0.50
0,38
0.45
0.50
0.43
0.43
0.50
0.52
0.57
0.60
0>60
0.53
00 Level
— L.
°l
h
7.80
8.13
8.63
9.13
6.97
5.98
6,97
6.97
7,64
7.64
6.31
6.14
5.98
9.96
9.13
8.30
8,47
7.80
7,14
7.30
7.47
7,47
7.30
7,47
7.80
8,13
8.13
3>30
7.66
Boiler Mo.
3 Load
1000 Ib steam
hr
167
167
173
164
167
185
167
168
162
156
162
173
179
198
198
163
159
183
188
167
113
139
170
168
180
173
177
171
169
Boiler No.
4 Load
1000 Ib steam
hr
66
99
102
94
109
121
159
136
106
105
99
95
97
95
106
C-202
-------
TABLE C.4-1. (CONTINUED)
(h) Month 8
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Monthly
Average
N0y
A
ng/J
249.4
258,0
270,9
258.0
258.0
279.5
258.0
258.0
266.6
270.9
236.5
258.0
227.9
245.1
266.6
279.5
266.6
270.9
236,5
249.4
279.5
258,0
266.6
245.1
236.5
232.2
238.0
279.5
215.0
215.0
202.1
253.3
Emission Rate
Ib
million Btu
0,58
0.60
0.63
0,60
0,60
0,65
0,60
0>60
0,62
0,63
0,55
0>60
0,53
0.57
0,62
0,65
0,62
0.63
0,55
0,58
0.65
0.60
0,62
0.57
0,55
0,54
0,60
0.65
0,50
0,50
0,47
0.59
00 Level
%
8,30
9,63
7,80
7,47
7.80
7,64
8,13
8,30
8,80
8,47
8,13
7,97
6.64
6,81
6,64
7.30
7.80
7,14
7,30
6.80
6,97
6.81
6,81
7,47
7>30
7,14
7,30
7,64
7,64
7,14
6,64
7.54
Boiler No.
3 Load
1000 Ib steam
hr
171
184
187
188
192
187
183
171
169
169
189
170
187
189
188
185
175
177
178
171
165
144
1.72
170
172
168
165
168
162
156
160
175
Boiler No.
4 Load
1000 Ib steam
hr
93
95
95
91
88
88
86
93
93
94
95
95
120
112
101
90
91
99
102
102
108
149
102
100
100
106
91
84
105
106
103
99
C-203
-------
TABLE C.4-1. (CONTINUED)
(i) Month 9
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Monthly
Average
NO
ng/J
206,4
232,2
202,1
219,3
227,9
206.4
193.5
210,7
245,1
236,5
258,0
266,6
258.0
266,6
258,0
238,0
249.4
270,9
253.7
236.5
215.0
215,0
279.5
292.4
296.7
279.5
279.5
236.5
243.1
262,3
245.2
Emission Rate
15
million Btu
0,48
0,54
0,47
0,51
0.53
0.48
0.45
0,49
0,57
0>55
0,60
0.62
0.60
0,62
0,60
0.60
0.58
0,63
0.59
0.55
0.50
0,50
0.65
0.68
0.69
0,65
0,65
0,55
0.57
0.61
0.57
00 Level
— c.
V
h
6.81
6,81
6.14
6,47
6,97
6,47
5,64
5,98
7,14
6,97
6,81
7,14
7,14
6,97
6.81
6,97
6,81
7,64
6.97
7,14
6.64
6,47
6.64
6,47
6,31
6.47
6,31
5,98
6,31
6.47
6.66
Boiler No.
3 Load
1000 Ib steam
hr
161
170
185
179
165
166
171
168
178
178
186
184
179
176
179
173
182
177
175
156
163
194
194
184
177
185
187
178
187
188
178
Boiler No.
4 Load
1000 Ib steam
hr
99
97
95
89
95
111
114
108
92
90
84
84
86
84
84
87
92
95
89
91
91
93
91
96
99
96
92
100
104
97 -
94
C-204
-------
TABLE C.4-1. (CONTINUED)
(j) Month 10
Test Day
1
2
3
4
5
6
7
8
9
10
11
12-
13
14
15
16
17
13
19
20
21
22
23
24
25
26
Monthly
Average
NO..
X
ng/J
236,5
215.0
219,3
213.0
219,3
232.2
236,5
258.0
236.5
236.5
266.6
249.4
245,1
270,9
240.8
223.6
245.1
236.5
245.1
219.3
206.4
215,0
258,0
275,2
258.0
258,0
239.1
Emission Rate
Ib
mill ion Btu
0.55
0.50
0,51
0>50
0.51
0.54
0,55
0.60
0.55
0.55
0,62
0.58
0.57
0.63
0.56
0>52
0.57
0.55
0.57
0>51
0.48
0,50
0,60
0.64
0.60
0.60
0.56
00 Level
— c.
°/
h
5.48
5.15
5,31
4,98
4.98
5,64
6.64
5.81
5.48
5,31
5.48
5.48
5.64
6.31
5.64
5.98
5,81
5,64
5,15
4.98
5,15
5,15
4,65
4.48
4.48
5.39
Boiler No.
3 Load
1000 Ib steam
hr
187
190
187
191
193
187
167
1.62
177
188
206
190
180
180
201
180
186
184
190
193
197
219
175
162
168
172
185
Boiler No.
4 Load
1000 Ib steam
hr
114
111
112
114
119
105
105
109
116
123
116
109
113
107
115
114
103
117
107
123
125
112
154
166
166
166
121
C-205
-------
TABLE C.4-1. (CONTINUED)
(k) Month 11
Test Day
1
9
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
23
29
30
31
Monthly
Average
NO.,
' A""
ng/0
240,8
2ri8,0
258,0
232.2
227,9
219,3
215,0
223,6
227.9
245.1
227.9
215.0
223,6
210.7
215.0
215.0
215,0
279,5
215,0
215,0
206,4
227,9
219,3
227,9
215.0
215.0
219.3
202.1
215.0
206.4
1.93,5
223.5
Emission Rate
Ib
million Btu
0,56
0.60
0.60
0.54
0.53
0,51
0,50
0,52
0,53
0,57
0,53
0,50
0,52
0,49
0,50
0,50
0,50
0,65
0,50
0.50
0.48
0,53
0,51
0,53
0,50
0,50
0,51
0,47
0,50
0,48
0.45
0.52
00 Level
— ^
%
4,65
4,65
4.81
4,32
5,48
5,15
5,64
5,31
6,14
5,81
5,81
5,31
5,48
4,98
4,81
4,65
4,98
6,64
4,81
4,65
4,81
4,81
4,81
4,81
4,65
4.98
4,76
5,48
4,65
4,65
4,65
5.07
Boiler No.
3 Load
1000 Ib steam
hr
179
184
182
182
216
213
191
201
200
212
192
193
201
195
193
202
176
1.86
186
193
202
212
206
179
175
180
177
173
179
173
191
191
Boiler No.
4 Load
1000 Ib steam
hr
164
156
162
173
115
119
114
111
109
107
110
118
118
123
130
130
133
97
122
133
133
133
136
137
139
135
132
128
133
140
133
130
C-20£
-------
TABLE C.4-1. (CONTINUED)
(1) Month 12
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Monthly
Average
NOX
ng/J
197,8
215.0
197,8
215.0
202,1
107.5
137.6
262.3
301.0
322.5
266.6
258.0
249.4
270.9
258.0
193.5
202.1
213.0
258.0
219.3
219,3
245,1
262.3
227,9
253.7
253.7
262.3
223.6
236.5
258.0
233.1
Emission Rate
Ib
million Btu
0,46
0,50
0.46
0,50
0,47
0,25
0,32
0,61
0,70
0,75
0,62
0,60
0,58
0,63
0.60
0,45
0,47
0,50
0,60
0,51
0,51
0.57
0.61
0.53
0.59
0.59
0,61
0,52
0,55
0.60
0.54
00 Level
— ^
o/
h
4,65
4,65
4,48
4>81
8,13
8.80
9,63
8.47
6.64
4,32
4.98
4,98
4.98
4,31
4.65
8.80
6,64
4,48
4,32
4,32
4,15
3.98
3,82
3.98
4.32
3.82
4,32
4.98
7,97
4.32
5.44
Boiler No.
3 Load
1000 Ib steam
hr
176
182
186
172
211
204
190
199
212
235
220
201
199
172
181
198
182
195
Boiler No.
4 Load
1000 Ib steam
hr
126
118
125
125
187
122
119
107
139
168
177
177
171
185
189
189
210
189
202
210
194
231
235
228
220
173
130
163
163
171
C-207
-------
TABLE C.4-1. (CONTINUED)
(m) Month 13
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Monthly
Average
NO
ng/J
245.1
234.5
223.6
206.4
227.9
227.9
227.9
202.1
206.4
233.7
279.5
•>23.6
292.4
'!83.3
258.0
266.6
241.3
Emission Rate
Ib
million Btu
0.57
0.55
0.52
0.48
0.53
0.53
0.53
0.47
0.48
0.59
0.65
0.52
0.68
0.66
0.60
0.62
0.56
00 Level
%
4.81
6.64
6.14
4,81
6.47
5,81
5.64
5,15
5.31
5,48
6.64
7,30
7.30
7,30
6.47
6.31
6.10
Boiler No.
3 Load
1000 Ib steam
hr
170
175
182
179
160
168
189
204
201
197
197
133
126
139
145
155
170
Boiler No.
4 Load
1000 Ib steam
hr
176
101
109
124
125
128
125
128
132
134
117
120
119
117
127
123
125
C-208
-------
TABLE C.4-1. (CONTINUED)
(n) Month 14
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Monthly
Average
NO
x~
ng/J
219,3
236,5
215,0
227,9
232,2
223,6
236,5
215.0
227,9
223.6
236.5
227.9
236,5
206,4
202.1
215,0
215.0
219,3
243.1
215.0
236.5
219,3
215.0
249*4
215.0
'MO. 3
223.6
227.9
245,1
219,3
225.6
Emission Rate
Ib
million Btu
0.51
0,55
0,50
0,53
0,54
0,52
0,55
0.50
0.53
0.52
0.55
0.53
0,55
0,48
0,47
0.50
0,50
0.51
0.57
0.50
0.55
0.51
0.50
0,58
0.50
0,56
0.52
0.53
0,57
0.51
0.52
00 Level
c.
%
6,81
5,81
5,81
5,31
5,31
5,81
5,98
5,98
5,81
5,98
7,30
7.47
6>97
6.47
6,31
6,47
6,31
6,47
6,97
6,64
7.47
6,47
6.64
5,81
6.31
6.31
6.14
6,31
7.14
6,47
6.37
Boiler No.
3 Load
1000 Ib steam
hr
151
165
161
159
179
168
169
170
164
154
153
163
148
145
146
148
150
131
1.58
160
161
152
157
164
151
161
164
170
188
179
160
Boiler No.
4 Load
1000 Ib steam
hr
120
125
132
129
127
125
125
127
120
123
119
143
125
125
133
132
130
129
138
134
121
133
130
129
129
130
127
124
129
137
128
C-209
-------
TABLE C.4-1. (CONTINUED)
(o) Month 15
Test Day
1
9
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Monthly
Average
N0y
A
ng/J
189,2
202.1
206,4
210,7
223*6
215,0
215.0
227,9
215.0
206.4
215,0
219.3
223.6
215.0
215,0
206.4
21.rj.0
219,3
223,6
22.3,6
223.6
215,0
236.5
240.3
258.0
245.1
262,3
262,3
227.9
236,5
236.5
223.6
Emission Rate
Ib
million Btu
0,44
0,47
0,48
0,49
0,52
0.50
0,50
0,53
0,50
0,48
0,50
0.51
0*52
0,50
0.50
0,48
0>50
0.51
0.52
0.52
0,52
0.50
0.55
0.56
0.60
0,57
0.61
0>61
0.53
0.55
0,55
0.52
00 Level
£
%
6,47
6,14
6,64
7,30
7,30
7,14
6,97
6,64
6,81
6,64
6,97
7.30
6,81
6,81
7,14
6.97
7.30
6.97
7.97
7,47
7.64
6,64
8,30
6,97
6,64
6,97
6,31
6,47
6.47
6,64
6,97
6.96
Boiler No.
3 Load
1000 Ib steam
hr
170
170
169
174
169
173
173
166
166
167
168
169
161
168
176
170
170
169
170
171
189
188
172
167
198
194
211
189
173
170
169
174
Boiler No.
4 Load
1000 Ib steam
hr
135
131
135
127
121
128
117
129
111
123
124
118
123
121
121
114
123
129
107
122
125
125
129
119
129
132
128
123
126
125
118
124
C-210
-------
TABLE C.4-1. (CONTINUED)
(p) Month 16
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Monthly
Average
NO
A
ng/J
258,0
258.0
249.4
258.0
339.7
301.0
279.5
288.1
215.0
236.5
172.0
279.5
288.1
V.66.6
279.5
270.9
262.3
270,9
279,5
279.5
301,0
313.9
296,7
313,9
305,3
258,0
245,1
335.4
335 . 4
270,9
258.0
276 ..3
Emission Rate
Ib
million Btu
0,60
0.60
0,58
0,60
0.79
0.70
0,65
0,67
0,50
0.55
0.40
0.65
0,67
0,62
0,65
0,63
0,61
0.63
0.65
0,65
0.70
0,73
0,69
0,73
0,71
0,60
0,57
0,78
0,78
0,63
0.60
0.64
00 Level
01
h
6,97
5,81
5,81
6.31
6,64
8,13
7,80
8,30
9>96
7.80
6,81
6,64
6,31
5,98
6,31
6,14
5,98
6,47
5.81
5,81
5.81
5,81
5.81
5,81
5,81
6,64
6,81
6,14
6,31
5,81
5,98
6.53
Boiler No.
3 Load
1000 Ib steam
hr
188
169
169
175
167
169
205
151
121
181
177
159
155
153
150
151
165
178
166
115
160
155
148
144
150
168
174
145
157
166
177
162
Boiler No.
4 Load
1000 Ib steam
hr
128
132
128
129
103
105
154
163
133
131
129
173
169
164
155
165
163
141
157
163
165
164
164
162
152
127
132
151
151
172
165
148
C-211
-------
TABLE C.4-1. (CONTINUED)
(q) Month 17
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
IB
19
20
21
22
23
24
25
26
Monthly
Average
NO
ng/J
245,1
215,0'
236,5
223,6
262,3
236,5
249,4
258,0
245.1
245.1
27V . 5
288.1
258.0
262,3
249.4
206.4
206.4
236,5
210,7
215.0
202.1
206.4
215.0
184.9
193.5
206.4
232.2
Emission Rate
Ib
million Btu
0,57
0,50
0.55
0.52
0.61
0.55
0>58
0.60
0.57
0,57
0,65
0,67
0,60
0,61
0,58
0.48
0,48
0,55
0.49
0.50
0>47
0.48
0.50
0.43
0,45
0.48
0.54
00 Level
%
6.14
5.98
6.31
5.64
5.48
5.64
5,48
5.48
4,98
5.48
5.48
5.98
5,48
5,81
5>81
5.48
S>31
5.31
5,31
5.15
5,48
5.64
5,64
5,64
5,64
5,64
5.59
Boiler No.
3 Load
1000 Ib steam
hr
174
169
146
142
191
200
202
189
187
169
178
166
171
180
176
171
167
167
170
175
165
165
164
162
160
168
172
Boiler No.
4 Load
1000 Ib steam
hr
168
160
176
179
152
150
154
175
179
182
179
181
195
174
166
161
174
185
169
159
163
169
167
168
164
154
169
C-212
-------
TABLE C.4-1. (CONTINUED)
(r) Month 18
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Monthly
Average
NO
ng/J
223*6
215,0
210.7
204 . 4
258,0
215.0
223,6
227.9
206.4
184.9
180,6
236.5
236.5
202.1
216.2
Emission Rate
Ib
mill ion Btu
0.52
0>50
0,49
0.48
0.60
0,50
0.52
0.53
0.48
0,43
0,42
0.55
0.55
0.47
0.50
00 Level
%
5,48
7,97
7.97
5,48
6.47
5,48
5.48
5,64
4.98
4,81
4.98
4.98
5.15
5,15
5.72
Boiler No.
3 Load
1000 Ib steam
hr
200
193
169
181
177
165
168
167
167
176
174
166
171
183
176
Boiler No.
4 Load
1000 Ib steam
hr
169
153
160
172
169
165
160
168
157
161
150
150
161
C-213
-------
TABLE C.4-1. (CONTINUED)
(s) Month 19
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Monthly
Average
NO
ng/J
193,5
lrJ9.l'
172.0
172.0
163.4
223.6
197.8
210.7
176.3
180.6
180.6
176.3
215.0
210.7
184.9
184.9
1.84.9
202.1
1/2.0
193.5
21-3.0
193.5
180.6
202.1
206,4
210,7
206.4
227.9
;?rJ8.0
258.0
197.1
Emission Rate
Ib
million Btu
0.45
0.37
0.40
0.40
0.38
0>52
0.46
0.49
0.41
0.42
0.42
0,41
0.50
0.49
0.43
0.43
0.43
0.47
0,40
0.45
0,50
0.45
0.42
0.47
0.48
0.49
0,48
0.53
0.60
0.60
0.46
00 Level
°/
10
5.48
5,81
5.64
6.31
9.46
13,61
15.77
9,46
6.64
6:81
6.64
6,14
4.98
5>15
5.15
4.98
4,98
5.64
5,31
5.64
5,81
5.81
4,98
4.81
5,31
5.15
5,50
5.00
5.00
5.16
6.40
Boiler No.
3 Load
1000 Ib steam
hr
176
184
172
181
114
83
100
177
175
158
172
179
181
167
164
168
167
165
166
171
171
168
165
169
170
168
170
142
135
133
161
Boiler No.
4 Load
1000 Ib steam
hr
123
134
122
132
89
89
111
115
107
111
129
157
173
175
155
184
172
157
159
159
178
179
170
175
177
162
158
156
147
C-214
-------
TABLE C.4-1. (CONTINUED)
(t) Month 20
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Monthly
Average
NO
A
ng/J
266,6
292,4
266,6
258.0
227.9
197.8
184.9
:-!27,9
189.2
180,6
197,8
202.1
163.4
163.4
163.4
163.4
172,0
215.0
193.5
206.4
163.4
159.1
150.5
141.9
133.3
HI. 9
141.9
150.5
150.5
HI. 9
172.0
186.4
Emission Rate
Ib
mill ion Btu
0,62
0.68
0.62
0.60
0,53
0,46
0.43
0.53
0,44
0,42
0,46
0,47
0,38
0.38
0.38
0.38
0,40
0,50
0,45
0,48
0,38
0,37
0,35
0.33
0.31
0.33
0.33
0,35
0,35
0,33
0.40
0.43
09 Level
— £
%
5,48
5,31
5.64
5>64
5,15
5,81
6,31
6,64
5,98
5,31
5.98
4,14
5,81
6,47
6,47
5,81
6,31
6,31
6,47
5,64
5>31
4.98
4,65
4,98
4.98
4.81
5.71
Boiler No.
3 Load
1000 Ib steam
hr
139
160
165
156
165
177
174
165
170
177
172
166
166
163
169
171
J.72
166
154
165
162
158
147
167
164
182
200
193
191
194
167
169
Boiler No.
4 Load
1000 Ib steam
hr
157
156
155
150
157
122
123
103
114
113
116
128
139
122
125
123
121
131
134
121
117
120
130
119
127
123
137
134
135
141
197
132
C-215
-------
TABLE C.4-1. (CONTINUED)
(u) Month 21
Test Day
1
T
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Monthly
Average
NO
A
ng/J
176,3
184.9
202,1
193,5
206.4
206.4
219.3
206,4
189,2
184.9
193.5
202,1
219,3
223,6
236.5
215.0
215.0
;!l!j,0
227.9
206,4
193,5
202.1
215,0
236.5
227.9
223*6
236.5
266.6
258.0
236.5
214.0
Emission Rate
Ib
million Btu
0,41
0,43
0,47
0,45
0,48
0,48
0,51
0,48
0,44
0.43
0,45
0.47
0.51
0.52
0,55
0.50
0,50
0.50
0.53
0.48
0,45
0 = 47
0,50
0,55
0,53
0,52
0,55
0.62
0.60
0,55
0.50
00 Level
c.
"I
h
4,65
4,98
4,98
4.81
4,98
4.65
4,65
4.81
4,81
4.81
4,32
4.65
4,98
4.65
4,81
4,81
4.81
4,31
5.15
5.15
4.65
4>65
4,81
4.81
4,65
4,65
4.98
4,81
4,81
4,81
4.80
Boiler No.
3 Load
1000 Ib steam
hr
166
165
182
168
152
173
171
166
156
174
187
167
166
148
1.62
150
153
160
150
175
175
173
177
178
177
171
175
167
166
163
167
Boiler No.
4 Load
1000 Ib steam
hr
197
180
160
159
140
179
176
166
170
192
186
166
163
174
153
160
165
153
170
173
167
184
157
150
164
159
160
175
178
167
168
C-216
-------
TABLE C.4-1. (CONTINUED)
(v) Month 22
Test Day
1
2
3
A
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Monthly
Average
NO,,
A
ng/J
258.0
258,0
258,0
249.4
227,9
215,0
215,0
184,9
172,0
159,1
184,9
172,0
163.4
159.1
139.1
159.1
176.3
159.1
130,5
141,9
139.1
172.0
139,1
159.1
159.1
159,1
172.0
193,5
189,2
193,5
163,4
183,9
Emission Rate
Ib
million Btu
0.60
0,60
0.60
0.58
0.53
0.50
0,50
0.43
0.40
0.37
0.43
0.40
0.38
0.37
0.37
0.37
0.41
0,37
0.35
0,33
0.37
0.40
0.37
0.37
0.37
0,37
0,40
0,45
0.44
0,45
0.38
0.43
00 Level
— L
%
4.98
5.15
4,81
4.81
4,48
4,32
4,32
4,48
4,32
4,15
4,15
4.32
4,15
4,48
4,15
4,32
4,32
4.32
3,82
4,15
4,15
4,32
4,15
4,32
4,15
3,98
4;15
6.14
4,32
5,48
5,64
4.48
Boiler No.
3 Load
1000 Ib steam
hr
152
150
151
147
152
168
1.71
169
168
170
178
179
176
185
193
196
1.83
174
174
169
166
171
1.83
167
170
177
170
183
189
177
166
172
Boiler No.
4 Load
1000 Ib steam
hr
161
164
165
166
168
182
175
179
192
199
199
196
183
181
137
186
189
193
197
183
132
179
189
217
'201
197
199
201
177
136
138
183
C-217
-------
TABLE C.4-1. (CONTINUED)
(w) Month 23
Test Day
1
9
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
9-7
28
29
30
31
Monthly
Average
NO
ng/J
137,6.
172.0
176.3
176,3
180.6
184,9
184,9
184,9
172.0
180,6
184.9
184,9
184,9
184,9
1.89,2
215.0
129.0
172.0
236*5
236,5
116.1
107,5
120.4
172.0
163.4
133.3
HI, 9
141.9
141.9
141.9
141. 9
167.4
Emission Rate
Ib
nil lion Btu
0.32
0.40
0.41
0.41
0.42
0.43
0>43
0,43
0.40
0.42
0.43
0.43
0.43
0.43
0,44
0.50
0,30
0,40
0.55
0,55
0.27
0.25
0,23
0.40
0.38
0.31
0.33
0.33
0.33
0,33
0,33
0.39
00 Level
— c.
°/
lo
4,98
4.65
4,65
6.14
4>18
4.48
4,32
4.15
4,32
4.81
9.13
7>47
7.97
9,79
12.45
10,29
6.14
4,98
5.15
5.31
5.31
5,31
5.31
6>64
6.18
Boiler No.
3 Load
1000 Ib steam
hr
165
159
156
156
172
175
176
173
172
171
178
165
164
171
149
84
101
99
J.33
106
89
112
182
167
174
167
163
181
176
161
165
154
Boiler No.
4 Load
1000 Ib steam
hr
153
169
169
165
173
177
176
184
186
172
168
174
168
182
130
10
162
133
136
125
123
124
125
122
150
C-218
-------
TABLE C.4-1. (CONTINUED)
(x) Month 24
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Monthly
Average
24 Month
Average
NO,,
ng/J
150.5
159.1
167.7
210.7
215.0
206.4
193.5
172.0
193.5
172,0
159.1
150.5
202.1
193.5
202.1
206.4
163.4
146.2
172.0
163.4
172.0
167.7
172.0
163.4
176.3
193.5
167.7
206.4
202.1
189.2
180.3
225.9
Emission Rate
Ib
million Btu
0.35
0.37
0.39
0.49
0.50
0.48
0.45
0.40
0.45
0.40
0,37
0.35
0.47
0.45
0.47
0.48
0.38
0.34
0.40
0.38
0.40
0.39
0.40
0.38
0.41
0.45
0.39
0.48
0.47
0.44
0.42
0.53
00 Level
— i-
°/
h
6.31
6,31
I5>81
5.15
5,48
5.15
15.81
5.48
5.15
7.47
7.47
7,89
6,97
4.98
4,93
4.98
8.30
7.89
5,98
6.14
5,48
6.14
5,81
5.81
5.48
4.98
4.81
4.81
4.81
4,81
5.89
6.43
Boiler No.
3 Load
1000 Ib steam
hr
174
188
166
167
166
163
169
173
161
175
104
116
160
173
182
162
133
140
182
186
181
202
181
165
177
Boiler No.
4 Load
1000 Ib steam
hr
121
124
147
139
H5
149
121
141
145
139
210
225
208
203
195
192
200
183
159
118
122
120
133
168
183
190
178
181
181
182
163
142
C-219
-------
Location II
The coal-fired spreader stoker boiler at Location II employed low
excess air (LEA) as the NO control technology. The boiler currently has a
X
100,000 steam/hr capacity. During the test period the actual maximum
capacity was 90,000 Ib steam/hr. However, for the purposes of showing
percent of boiler load, the rated capacity of 100,000 Ib steam/hr was used.
During the test period, midwestern coal containing 1.27 to 1.42 weight
percent nitrogen and about 12,000 Btu/lb heat content was burned.
Continuous monitoring data was obtained for 30 days. The 24-hour data
is presented in Tables C.4-2 through C.4-4. During the test period the
average boiler load was 70,000 Ib steam/hr, with hourly readings ranging
from 50,000 to 85,000 Ib steam/hr. Figure C.4-1 shows the emissions,
boiler load, and oxygen level for each test day.
C-220
-------
TABLE C.4-2.
DAILY AVERAGE NOX EMISSIONS
SPREADER STOKER-LOCATION II59
NO Emission Rate
A
a
Test Day*
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
30 Day Average
ng/J
174.8
167.7
181.7
189.1
185.1
184.4
187.4
181.9
167.7
177.7
182.6
180.4
169.9
171.1
161.9
159.3
153.9
161.8
165.4
168.4
180.1
161.8
160.1
161.1
159.1
159.9
156.2
162.4
164.0
164.3
170.0
Ib
Million Btu
0.41
0.39
0.42
0.44
0.43
0.43
0.44
0.42
0.39
0.41
0.43
0.42
0.40
0.40
0.38
0.37
0.36
0.38
0.39
0.39
0.42
0.38
0.37
0.38
0.37
0.37
0.36
0.38
0.38
0.38
0.40
18 Hours/day minimum test time.
C-221/
-------
TABLE C.4-3. DAILY SUMMARY OF HOURLY 02 LEVELS
SPREADER STOKER - LOCATION I:I59
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Minimum Hourly
02 Level (%)
6.43
6.43
6.80
6.68
. 6.43
7.00
6.45
6.55
6.73
6.68
6.93
7.08
6.28
5.45
5.73
4.78
5.18
4.68
5.93
6.20
6.75
6.28
6.18
5.70
5.90
5.78
4.48
5.98
6.38
6.65
24-Hour Average
02 Level (%)
7.05
6.88
7.58
7.69
7.53
7.82
7.76
7.44
7.40
7.59
7.83
7.60
7.11
7.34
6.74
6.90
6.52
6.58
6.82
7.21
7.43
7.21
7.10
6.94
6.31
6.58
6.02
6.87
7.84
7.90
Maximum Hourly
02 Level (%)
7.83
7.50
9.15
8.68
8.98
10.00
9.83
8.30
8.58
9.08
8.73
8.37
7.75
9.10
7.93
7.95
8.00
7.75
7.70
8.28
8.70
8.35
8.35
8.05
7.58
7.93
7.50
8.05
9.58
9.25
118 Hours/day minimum test time.
C-222
-------
TABLE C.4-4. DAILY SUMMARY OF HOURLY BOILER LOADS
SPREADER STOKER - LOCATION II59
Test Day9
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Minimum Hourly
Boiler Load (MW)
20.5
20.5
19.9
18.8
20.5
16.1
20.5
19.3
20.2
16.1
19.0
19.9
19.9
16.1
17.6
17.6
20.5
19.0
19.6
19.9
18.5
17.0
16.1
17.0
19.0
17.6
20.5
19.6
14.6
16.4
24-Hour Average
Boiler Load (MW)
20.5
20.5
20.6
21.0
20.7
20.1
20.9
21.4
21.2
20.1
20.4
20.6
21.0
20.5
20.5
21.1
21.6
22.0
21.1
20.8
20.6
19.7
18.1
19.3
21.5
20.2
21.2
20.6
17.8
17.9
Maximum Hourly
Boiler Load (MW)
20.5
20.5
22.0
23.4
22.3
21.7
22.9
23.4
22.9
22.0
20.8
21.4
22.3
22.9
22.9
23.1
24.0
24.9
23.1
22.0
22.0
21.4
19.6
22.9
22.9
22.9
22.9
22.0
22.0
20.5
a!8 Hours/day minimum test time,
C-223
-------
190
182
174
166
158
150
CM
O
8.0
7.6
7.2
6.8
6.4
6.0
O
cC
O
O
CQ
95
85
75
65
55
45
L
V
\
10
15
TEST DAYS
20
25
Figure C.4-1,
Continuous monitoring data for LEA combustion
modification on a spreader stoker coal-fired
boiler at Location II.
30
C-224
-------
Location III
The 160,000 Ib steam/hr coal-fired spreader stoker boiler at Location III
used LEA as the NO control technology. However, this technique was
A
only used during non-holiday, weekday dayshifts. The hours where LEA
was not used were low demand periods, so that increased excess air
operation coincided with low steam demand. The capacity rating was
based on coal with a heat content of 12,000 Btu/lb. The daily results
are given in Tables C.4-5 through C.4-7.
During the 18-day test period, a western coal having a heat content
of about 8,500 Btu/lb and a nitrogen content of 0.76 to 0.80 weight
percent was burned. The hourly average boiler load ranged from 59,000
to 122,000 Ib steam/hr while averaging 97,000 Ib steam/hr during the
test period. The 8-hour averaged emission rates, boiler loads, and
oxygen levels are illustrated in Figure C.4-2.
C-225
-------
TABLE C.4-,-5. 8-HOUR AVERAGE NQX EMISSIONS
SPREADER STOKER - LOCATION III60
NO Emission Rate
A
a
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
18 Day Average
ng/J
203.9
190.3
222.3
200.5
209.0
230.9
189.6
214.9
206.0
216.1
198.9
208.3
213.6
194.4
208.1
214.1
211.5
202.9
207.5
Ib
Million Btu
0.47
0.44
0.52
0.47
0.49
0.54
0.44
0.50
0.48
0.50
0.46
0.48
0.50
0.45
0.48
0.50
0.49
0.47
0.48
*6 Hours LEA operation/day minimum test time.
C-22S
-------
TABLE C.4-6. DAILY (8-Hour Average) SUMMARY OF HOURLY 02 LEVELS
SPREADER STOKER - LOCATION III60
Test Day3
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Minimum Hourly
02 Level (%)
8.50
8.30
9.20
8.80
8.10
7.90
7.60
8.40
8.80
8.40
7.70
6.90
8.10
6.90
6.70
7.20
8.80
8.50
8-Hour Average
02 Level (%)
8.93
9.04
9.40
8.98
8.45
8.29
8.11
8.55
9.08
8.69
8.31
7.55
8.45
7.24
7.54
7.80
8.88
8.86
Maximum Hourly
02 Level (%)
9.30
9.50
9.50
9.30
8.80
8.80
8.40
8.80
9.50
9.30
8.90
8.40
8.90
7.80
8.90
8.40
9.00
9.30
a6 Hours LEA operation/day minimum test time.
C-227
-------
TABLE C.4-7. DAILY (8-Hour Average) SUMMARY OF HOURLY BOILER LOADS
SPRFARFR STOKFR - I nrflTTOM TTl60
SPREADER STOKER - LOCATION III
Test Day3
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Minimum Hourly
Boiler Load (MW)
17.3
24.3
20.2
24.0
- 26.4
27.8
28.1
26.1
24.0
26.1
26.1
30.2
27.0 '
30.8
29.3
27.2
26.7
24.3
8-Hour Average
Boiler Load (MW)
19.4
25.6
24.2
25.7
28.1
30.9
30.1
28.3
25.9
28.1
29.8
32.8
29.7
32.5
34.0
30.9
27.6
26.9
Maximum Hourly
Boiler Load (MW)
22.0
27.8
26.1
27.2
29.9
33.4
33.1
29.3
27.8
29.3
32.8
34.6
30.8
34.0
35.7
32.5
28.4
28.4
*6 Hours LEA operation/day minimum test time.
C-228
-------
<-s
en
c
A
X
o
**
A
evi
o
235
225
215
205
195
185
9.5
9.0
8.5
8.0
7.5
7.0'
^
•
-
-
•
^B
-
•
•
-
-
_
\
a
§
an
LU
o
CO
90
80
70
60
50
40
10
TEST DAYS
15
Figure C.4-2.
Continuous monitoring data (8-hour average) for
LEA combustion modification on a spreader stoker
coal-fired boiler at Location III.
C-229
-------
Location IV
The residual oil-fired boiler at location IV used low excess air
(LEA) and staged combustion air (SCA) as control technologies. The
boiler has a capacity of 79,000 Ib steam/hr which falls to 60,000 Ib
steam/hr during SCA operation. During the 29-day test period, high
demand precluded the use of SCA on 16 days.
The fuel used during the test period had a 0.24 to 0.28 weight
percent nitrogen content and a heat content of about 15,500 Btu/lb.
During that time, the boiler load averaged 57,000 Ib steam/hr, with
hourly averages ranging from 36,000 to 73,000 Ib steam/hr. Tables
C.4-8 through C.4-10 show the daily emissions, 0,, levels, and boiler
load. Figure C.4-3 shows the daily emissions, boiler loads, and
oxygen levels for each day.
C-230
-------
TABLE C.4-8.
DAILY AVERAGE NOX EMISSIONS
RESIDUAL OIL-FIRED - LOCATION IV61
a
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
29 Day Average
NOV
X
ng/J
129.3
121.0
149.9
121.2
111.4
95.8
89.5
87.7
100.4
106.9
100.2
82.7
120.1
117.9
108.8
90.4
87.7
106.5
113.9
125.5
127.0
119.7
127.6
128.4
119.9
126.3
120.0
103.3
104.5
111.8
Emission Rate
Ib
Million Btu
0.30
0.28
0.35
0.28
0.26
0.22
0.21
0.20
0.23
0.25
0.23
0.19
0.28
0.27
0.25
0.21
0.20
0.25
0.27
0.29
0.30
0.28
0.30
0.30
0.28
0.29
0.28
0.24
0.24
0.26
NOV Control
b
Technique
L
L
L
L
S
S
S
S
S
S
S
S
L
L
S
S
S
L
L
L
L
L
L
L
L
L
L
S
S
18 Hours/day minimum test time.
bL = LEA only.
S = LEA/SCA.
C-231
-------
TABLE C.4-9.. DAILY SUMMARY OF HOURLY 02 LEVELS
RESIDUAL OIL-FIRED - LOCATION IV61
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Minimum Hourly
02 Level (%)
7.00
7.60
6.73
7.20
7'. 10
7.00
7.40
7.10
7.63
8.10
7.50
7.30
8.20
10.20
7.70
6.98
6.70
6.40
6.18
6.05
6.25
7.18
7.03
7.40
6.90
7.30
6.90
7.33
7.65
24-Hour Average
02 Level (%)
8.50
8.06
8.07
7.72
7.57
7.48
7.61
7.60
7.91
8.46
7.96
7.82
9.98
10.79
9.16
7.25
7.09
6.78
6.64
6.31
7.03
10.13
8.05
8.79
7.25
7.42
7.69
7.94
9.16
Maximum Hourly
02 Level (%)
9.18
8.58
9.33
8.38
8.13
7.90
7.90
7.98
8.30
8.78
8.65
8.10
10.23
11.95
11.10
7.55
7.40
7.20
7.30
6.75
10.60
11.40
10.58
11.98
7.60
7.65
8.68
8.73
12.60
NO Control
Technique
L
L
L
L
S
S
S
S
S
S
S
S
L
L
S
S
S
L
L
L
L
L
L
L
L
L
L
S
S
18 Hours/day minimum test time.
L = LEA only.
S = LEA/SCA.
C-232
-------
TABLE C.4-10. DAILY SUMMARY OF HOURLY BOILER LOADS
RESIDUAL OIL-FIRED - LOCATION IV61
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Minimum Hourly
Boiler Load (MW)
14.5
14.4
15.6
15.4
16.4
16.4
16.4
16.2
16.1
16.1
16.2
16.4
13.5
13.3
13.3
15.9
16.1
16.2
19.7
18.9
14.8
10.7
16.2
18.5
18.7
18.0
15.9
15.9
16.1
24-Hour Average
Boiler Load (MW)
15.4
15.3
16.5
16.5
16.7
16.6
16.6
16.5
16.4
16.3
16.5
16.6
13.9
13.6
15.8
16.4
16.8
17.4
20.6
20.7
19.3
14.0
17.4
19.2
19.0
19.4
17.1
16.8
16.7
Maximum Hourly
Boiler Load (MW)
18.2
19.1
18.5
18.5
17.9
16.8
16.9
16.8
17.7
16.4
16.7
16.7
14.1
15.4
17.0
18.2
19.5
19.9
21.1
21.5
20.1
18.2
19.5
19.9
19.5
19.9
18.8
17.5
17.5
NO Con trey
Technique
L
L
L
L
S
S
S
S
S
S
S
S
L
L
S
S
S
L
L
L
L
L
L
L
L
L
L
S
S
a!8 Hours/day minimum test time,
bL = LEA only.
S = LEA/SCA.
C-233
-------
^}
CT)
15Q
135
120
105
90
75
• - LEA only
A- LEA/SCA
CM
O
11
10
9
8
7
6
• - LEA only
A- LEA/SCA
o
o
Of.
o
CO
95
85
75
65
55
• - LEA only
A- LEA/SCA
10
15
TEST DAYS
20
25
Figure C.4-3.
Continuous monitoring data for LEA/SCA
combustion modification on a residual
oil-fired boiler at Location IV.
'C-23/1
-------
Location V
Location V is a 6,900 Ib steam/hr capacity natural gas-fired boiler.
The boiler is only in operation approximately 19 hours a day during
non-holiday weekdays. Thus, only 21 days of data were gathered during
the 36-day test period. The daily emissions data are presented in
Tables C.4-11 to C.4-12. Low excess air (LEA) was the NO control
A
fi?
technique used during operation. The 19-hour average emission rates
and oxygen levels are shown in Figure C.4-4.
C-235
-------
TABLE C.4-11. 19-HOUR AVERAGE NO EMISSIONS fi?
NATURAL GAS-FIRED - LOCATION V
NO Emission Rate
/\
a
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
21 Day Average
ng/J
30.2
27.9
28.9
29.0
28.2
28.8
28.7
29.6
29.6
28.1
28.7
29.0
30.9
31.4
30.9
26.7
29.7
30.4
31.8
33.5
33.1
29.8
Ib
Million Btu
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.06
.0.07
0.07
0.07
0.08
0.08
0.07
115 Hours/day minimum test time.
C-236
-------
TABLE C.4-12. DAILY (19-Hour Average) SUMMARY OF HOURLY 02 LEVELS
NATURAL GAS-FIRED - LOCATION
Test Day3
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Minimum Hourly
02 Level (%)
6.70
6.35
5.78
5.68
4.80
6.20
4.80
5.03
5.40
6.40
4.68
5.48
4.00
4.80
7.00
4.90
3.88
4.60
4.75
2.60
6.93
19-Hour Average
02 Level (%}
8.34
7.28
6.41
6.81
7.42
7.91
7.50
7.70
6.95
7.34
6.59
7.62
5.58
5.62
9.56
7.64
5.79
5.94
6.19
8.49
9.67
Maximum Hourly
02 Level (%)
10.43
10.10
8.30
8.68
10.08
10.33
10.23
9.45
9.00
8.93
9.08
9.43
6.55
9.83
12.87
11.20
6.90
6.90
7.15
10.53
11.13
a!5 Hours/day minimum test time.
C-237
-------
40 r
30-
20
CM
o
u
X
10
10.Cr
10
15
10 15
Test Days
Figure C.4-5.
20
25
30
25
30
Continuous NOX emission data for a smal'
natural gas boiler at Location V.
C-238
-------
Location VI
The location monitored is a 100,000 Ib steam/hr coal/1imestone feed
fluidized-bed boiler (FBB). The plant was not always operated in the
intended design range since the test period covered an extended shakedown
period. The coal nitrogen content during testing was approximately
1.5 percent. Daily boiler loads during the period ranged from 50 to
60 percent.
Low excess air was the only NO control technology used. However, due
/\
to shakedown operating conditions, high excess air conditions were recorded
during the test. Daily 0 levels ranged from 8.8 to 12.3 percent.
C-23?
-------
TABLE C.4-13. DAILY AVERAGE EMISSION RATES, 09 LEVELS,
AND BOILER LOADS
LOCATION VI - FLUIDIZED BED
Test Data
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
16 day
Average
NO
ng?J
313
282
237
226
256
251
342
441
323
288
250
262
289
267
255
218
281
Emission Rate
Ib/million Btu
0.7
0.7
0.6
0.5
0.6
0.6
0.8
1.0
0.8
0.7
0.6
0.6
0.7
0.6
0.6
0.5
0.7
09 Level
^ %
12.1
11.8
9.2
8.8
10.4
9.5
11.2
12.3
10.7
10.0
8.9
8.8
10.2
11.4
10.3
8.8
10.3
Boiler Load
1000 Ib steam/hr
52
50
53
56
55
57
54
53
56
59
61
62
54
48
56
57
55
18 Hours/day minimum test time.
C-240
-------
Key to Symbols for Short-Term Data Tables
LN Location number as given in Reference 54
UN Boiler designation (unit number) - Reference 54
TN Test number - Reference 54
TT Test type
FN Fuel nitrogen content (lb/10 Btu)
CT Combustion air temperature (°F)
HR Heat release rate (103 Btu/hr ft2)
EO Excess oxygen in flue gas (%)
NE NO emissions (ppm at 3% 09 dry)
A cL
BA Baseline air (boiler operating at at least 80% capacity)
LA Low excess air
NA "Normal" excess air - Reference 54
HA High excess air
LL Low load
HL High load
SC Staged combustion
BO Burner-out-of-service
75 ppm NO at 3% 09 dry is approximately 0.1 lb/106 Btu.
X L.
C-241
-------
SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-14:
A
TABLE C.4-14: ;
-UNSTAGED COMBUSTION IN COAL-FIRED SPREADER STOKER BOILERS54
LOCATION
NUMBER
11
11
11
11
11
11
11
11
11
11
11
o 11
ro 11
ro 11
11
11
11
11
11
11
11
14
14
14
14
14
14
14
14
14
14
14
14
UNIT
NUMBER
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
TEST E
NUMBER
18.01
18.02
18,03
18.04
18.05
18,06
18.07
18.08
18.09
18.10
18.11
18.12
18,13
18,14
18.15
18,16
18,17
18.18
18,19
18.20
18.21
27.01
27.02
27.03
27.04
27.05
27.06
27.07
27.08
27.09
27.10
27.11
27.12
NOX
:MISSIONS
(PPM) <
390
389
373
379
367
338
373
379
417
460
353
464
174
431
359
374
404
337
429
423
385
550
540
487
470
571
509
519
610
564
564
449
475
FUEL
NITROGEN
:LB/MILLION BTU
1. 10
1 ,10
1 .10
1.10
1. 10
1.10
1 , 10
1.10
1.10
1 .10
1.10
1,10
1. 10
1,10
1.10
1.10
1.10
1.10
1,10
1.10
1.10
1.01
1.01
1 .01
1,01
1 .01
1 ,01
1.01
1.01
1.01
1.01
1,01
1 ,01
EXCESS
OXYGEN
) (VOL. 7.)
8,0
7,7
7,0
5,5
6,0
4.9
5.8
6.5
6,9
7.5
5,3
9,7
11.6
9.0
6.5
8,1
8.4
6,5
7.4
7.2
6.5
10.3
10.1
9.5
8,9
10,8
11.8
13.4
15,8
10,2
9.0
9,0
11 ,8
COMBUSTION
60,0
60.-0
60,0
60.0
60.0
60,0
60.0
60,0
60.0
60,0
60,0
60.0
60,0
60.0
60,0
60.0
60.0
60,0
60.0
60.0
60,0
350.0
350,0
350.0
350.0
350,0
350.0
350.0
350,0
350.0
350,0
350,0
350.0
HEAT RELEASE RATE
(1000 BTU/HR'FT'FT)
49,27945
55.0/703
60,70493
59,71510
59.13534
65,28643
63,19364
61,45437
63.77340
60.87461
63,77340
37.68428
28.98791
43,48187
43,48107
42,3^235
41,74259
41.74259
70.15074
76.31067
63.77340
90.90493
90,98129
90.98129
92.11856
89.90047
67,74914
52,16368
36,78567
91,42421
116,54961
90,98129
89.88163
-------
TABLE C.4-14 (Continued): SHORT-TERM N0x EMISSION DATA FOR FIGURE 4.3-14:
UNSTAGED COMBUSTION IN COAL-FIRED SPREADER STOKER BOILERS54
LOCATION
NUMBER
14
14
14
14
14
14
14
14
14
14
14
14
21
21
21
21
21
21
21
21
21
21
21
21
21
21
21
21
21
21
21
UNIT
NUMBER
4
4
4
4
4
4
4
4
4
4
4
4
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
NOX
TEST EMISSIONS
NUMBER (PPM) (
28.01
28.02
28.03
28.04
28.05
28.06
28.07
28.08
28.09
28.10
28.11
28.12
19.01
19.02
19.03
19.04
19.05
19.06
19.07
19.08
19,09
20.01
20,02
20.03
20.04
20,05
20.06
20.07
20.08
20.09
20,10
540
542
631
540
427
358
595
461
494
571
598
538
476
431
396
355
471
464
462
448
330
506
487
526
359
435
463
414
506
489
389
FUEL
NITROGEN
[LB/MILLION BTU
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
,35
.35
.35
.35
.35
.35
.35
.35
.35
.35
.35
.35
.05
.05
.05
.05
.05
,05
.05
,05
,05
,04
.04
,04
,04
,04
.04
.01
.04
,04
.04
EXCESS
OXYGEN
) (VOL, X)
10
10
12
11
10
8
15
13
11
10
10
10
9
8
6
5
7
8
9
7
5
7
8
9
5
6
7
5
9
9
5
,6
,8
.5
,3
.1
,9
.5
.0
.9
,6
.8
.6
.4
,3
.4
.5
.4
,0
.0
,3
,8
.6
,2
.0
,5
,6
,8
,9
,3
,9
,9
COMBUSTION
TEMP, (°F> (
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
,0
.0
.0
,0
.0
,0
.0
,0
.0
,0
,0
.0
.0
.0
.0
,0
,0
.0
.0
,0
,0
.0
,0
.0
,0
.0
.0
,0
,0
.0
.0
HEAT RELEASE RATE
[lOOO BTU/HK'FT' FT)
75
78
73
72
73
70
37
47
62
87
95
78
39
43
46
48
50
38
31
40
39
37
38
37
38
39
39
47
32
28
38
.80146
.82650
.94167
.80000
,28533
,16867
,60526
,90417
,61125.
,56250
,64228
.24667
. 12590
.03858
,95591
.91732
,52726
,64684
.69700
.10413
.12992
.91450
.55030
,91830
.67340
,29720
.81420
.40130
,86250
.1/470
.29850
-------
TABLE C.4-15: SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-15:
STAGED COMBUSTION IN COAL-FIRED SPREADER STOKER BOILERS54
o
I
ro
LOCATION
NUMBER
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
UNIT
NUMBER
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
TEST
NUMBER
134,01
134,02
134.03
134.05
134.06
135.01
135.02
135.03
136.01
136.02
136.03
139.01
139.02
139.03
139.04
139.05
139,06
139.07
139.08
139.09
139.10
TEST
TYPE
NA
BA
NA
NA
NA
LA
LA
LA
SC
SC
SC
NA
LA
LA
LL
NA
NA
SC
NA
NA
SC
NOX
EMISSIONS
(PPM) {
323
320
298
312
274
237
233
216
295
319
237
312
263
195
351
360
371
342
327
330
269
FUEL
NITROGEN
ILB/MILLION BTU
1.19
1.19
1.19
1,19
1.19
1.19
1.19
1.19
1,19
1.19
1.19
1.19
1.19
1.19
1,19
1.19
1,19
1.19
1,19
1.19
1.19
EXCESS
.OXYGEN
) (VOL. %)
6.2
6,2
6,1
6,2
6.2
5.4
4.7
5.2
6.3
6,6
6.1
10. 3
9,0
7,4
10,3
10.0
9.4
9.6
9.3
9,4
7.7
COMBUSTION
TEMP. ( F>
200
200
200
197
198
202
205
205
200
200
200
180
190
200
190
180
180
180
180
180
182
HEAT RELEASE RATE
(1000 B1U/HR FT FT)
52.98497
51.85721
52.23784
52.12456
51.79772
51.55305
51.28136
51.55349
52.57480
52.73066
51.61704
30,08392
29.94493
29.57517
31.22r86
31,46543
31.85787
32.36538
31.86616
31.94905
31.85655
-------
TABLE C.4-16:
SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-16:
COMBUSTION IN MASS FED BOILERS54
o
ro
-^
en
LOCATION
NUMBER
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
35
35
35
35
35
35
35
35
35
35
35
35
35
35
35
35
35
35
35
35
UNIT
NUMBER
32.1
32,1
32.1
32.1
32.1
32.1
32.1
32.1
32. 1
32.1
32.1
32.1
32.1
32.1
32.1
32.1
6.0
6.0
6.0
6.0
6.0
6.0
6,0
6.0
6.0
6.0
6.0
6.0
6,0
6.0
6.0
6.0
6.0
6.0
6,0
6.0
TEST
NUMBER
16.01
16,02
16.03
16.04
16.05
16,06
16.07
16.08
16,09
16.10
16.11
16.12
16.13
16,14
16.15
16.16
165.01
165.02
165.03
166.01
166.02
166,03
166.04
166.05
166.06
166.07
166.08
167.01
167.02
167.03
167.04
168.05
168.01
168.02
168.03
168,04
TEST
TYPE
NA
LA
NA
NA
LL
LL
NA
HL
LA
LA
MA
BA
HA
NA
NA
LL
BA
NA
Nft
LA
LA
LA
LA
HA
LA
LA
LA
NA
HL
LL
LL
NA
SC
SC
SC
SC
NOX
EMISSIONS
(PPM)
331
297
255
272
186
226
294
319
179
192
264
266
273
233
207
235
164
171
170
1 22
130
140
126
154
137
157
158
147
155
193
235
164
158
150
166
174
FUEL
NITROGEN
(LB/MILLION BTU)
1.21
1.21
1.21
1.21
1.21
1.21
1.21
1.21
1.21
1.21
1,21
1 .21
1 ,21
1.21
1.21
1,21
0.79
0.79
0.79
0.79
0.79
0,79
0,79
0.79
0,79
0,79
0,79
0,79
0.79
0.79
0.79
0.79
0.79
0,79
0.79
0,79
EXCESS
OXYGEN
(VOL. X)
7.5
6.0
7.0
8,7
9,4
13.1
7. 1
6,1
6.7
4.9
7.0
6.6
8.2
7.9
9.0
12.3
9.5
9.5
9,6
9.0
8,3
8,8
8.7
10,9
8.8
8.4
8,2
9.4
8.3
11.3
12.5
9.4
9.9
8.5
9,0
10,3
COMBUSTION
TEMP. (°F)
80.0
82.0
80.0
75.0
75.0
71.0
71.0
74.0
75.0
75.0
79.0
79,0
78.0
78.0
80,0
78.0
230,0
217.0
210.0
225.0
235.0
220.0
220.0
220.0
217.0
218.0
230.0
230.0
212.0
235.0
240.0
235.0
220.0
225.0
230.0
230.0
HEAT RELEASE RATE
(1000 BTU/HR- FT'FT)
39,21404
39,21404
41.45068
33.37365
25.37135
16,93607
40.42851
51.91466
37.72030
36.39975
38.20086
39.28186
38.55853
34.62516
26. 18978
17.16034
39.35569
39.99223
39.19221
.38.78377
35.31303
39.79412
38.87876
40.9'.j380
38.77224
40.34154
41.60272
34.67047
44.98808
23.46960
20,10301
39.53084
36.09587
40.40546
38,15467
35.89736
-------
TABLE C.4-17: SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-18:
X CA
UNSTAGED COMBUSTION IN RESIDUAL OIL-FIRED BOILERS WITH AIR PREHEATOH
r>
i
ro
->
on
LOCATION
NUMBER
18
18
18
18
19
IB
18
18
18
18
18
18
18
1H
18
13
18
18
18
18
29
29
29
TO
39
?9
29
29
29
37
37
37
37
37
37
37
37
.57
37
UNIT
NUMBER
3
3
3
3
3
3
3
3
3
4
4
4
4
4
A
4
4
4
4
4
5
5
£-
,j
5
5
5
5
5
3
2
2
2
2
2
2
2
2
a
2
TEST 1
NUMBER
21,01
21,02
21,03
21,04
21,05
21,06
21,07
21.08
21,09
22,01
22,02
22,03
22,04
22.05
22.06
22.07
22,08
22.09
22.10
22.11
116.01
117.01
117.02
117,03
119.01
119.02
121.01
121.02
121.03
176.02
176.03
176,04
176.05
176,06
176,07
179,01
179,02
179.03
179,04
NOX
EMISSIONS
(PPM)
291
235
220
233
273
253
206
OT".
*- «_ *J
314
242
281
30'5
321
245
237
237
236
233
257
270
294
266
246
285
248
258
254
295
263
195
191
195
196
190
189
179
196
201
174
FUEL
NITROGEN
(LB/MILLION BTU
0,14
0, 14
0,1.4
0,11
0,14
0,14
0.14
0, 14
0.14
0, 14
0.14
0, 14
0.14
0,14
0.14
0,14
0,14
0,14
0, 14
0.14
0.17
0.17
0.17
0,17
0.17
0.17
0, 17
0.17
0.17
0,16
0.16
0.16
0.16
0.16
0, 16
0.16
0. 16
0.16
0. 16
EXCESS
OXYGEN
) (VOL, '/.)
7.0
7,0
7.7
8,7
5,0
6,3
5.3
6.1
7,6
6,8
7.8
8.1
8.2
7.1
7.1
7.2
6,5
6,0
7,8
8.6
5.0
4,1
3,1
5,6
5,5
5,2
5,4
5,4
5,5
4.3
4,6
4,3
4.6
4.4
4.6
3.8
5.2
5.7
4,0
COMBUSTION
TEMP. <°F)
120,0
390,0
370,0
358,0
135,0
110.0
410.0
415.0
418.0
518,0
525.0
505,0
480.0
550.0
550,0
5-12,0
512,0
542,0
512.0
590,0
395.0
392,0
383.0
400,0
360.0
360.0
350.0
350.0
350.0
227,0
225.0
229.0
231.0
231.0
234.0
231.0
233.0
230.0
234,0
HEAT RELEASE RATE
(1000 BTU/HR'FT'I- T )
75,36035
55,57826
43,33220
34.45101
93.25843
76,04681'
75, 14150
74,02312
75.37544
84.44150
72.74960
58,45950
46.78165
85,71060
82, 187-Ui
77,96911
77,96941.
77,96941
77,96941
76.61690
75.78997
76.18802
76.81768
75.55837
13.75209
44.07128
45.32591
44 .06685
43.75209
74.71873
73.80689
75.72910
75.93206
77.12368
75.00511
76.86716
75,65392
74,92948
74,76388
-------
TABLE C.4-18:
SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-18:
A
UNSTAGED COMBUSTION IN RESIDUAL OIL-FIRED BOILERS WITHOUT AIR PREHEAT
54
o
I
ro
LOCATION
NUMBER
16
16
16
16
16
16
16
16
10
10
10
18
10
10
10
10
18
19
19
19
19
19
19
19
19
19
19
19
19
19
1.9
19
19
19
19
1.9
I '•'••
* UNIT
NUMBER
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
I
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
TEST f
NUMBER
10.01
10,02
10.03
10,04
10.05
10,06
10,07
10.09
9.01
9.02
9,03
9,04
9.05
9,06
9.07
9.00
9,09
1,01
1.02
1.03
1.04
1.05
1.06
1.07
1.08
1.09
1,10
1.11
1,12
1 .13
1.14
2,01
2.02
2.03
2.04
2,05
2,06
NOX
EMISSIONS .
(PPM) i
180
189
197
187
210
229
266
205
246
218
192
242
259
216
285
236
256
423
338
276
338
391
336
375
120
373
390
341
357
385
414
402
388
339
286
z;w
303
FUEL
NITROGEN
CLB/MILLION BTU
0,15
0,15
0,15
0, 15
0,15
0,15
0,15
0.15
0.14
0.14
0,14
0.14
0. 14
0,14
0,14
0,14
0, 14
0.24
0,24
0.24
0,24
0,24
0.24
0,24
0.24
0,24
0,24
0,24
0,21
0.24
0,24
0,24
0,24
0.24
0.24
Q,2<\
0,21
EXCESS
OXYGEN
) (VOL, '/.)
3,7
4,7
4,0
3,6
5,1
7,6
13.3
5,2
7,4
8.7
8.6
6,8
7,0
7.0
0.5
7.4
7.5
4,4
2,3
1.6
2.7
5,0
3,6
6.4
11,0
4,2
4,2
2,3
3,6
1.9
5,8
6,6
5,7
1 .3
2.8
4 . 4
1. ;
COMBUSTION
TEMP, (°F) (
60,0
60,0
60,0
60.0
60.0
60.0
60.0
60,0
60,0
60,0
60.0
60.0
60.0
60,0
60,0
60.0
60.0
60.0
60,0
60.0
60.0
60,0
60.0
60,0
60,0
60,0
60,0
60,0
60,0
60,0
60,0
60,0
60,0
60,0
60.0
60,0
60.0
HEAT RELEASE RATE
[1000 BTU/HR' FT* FT)
61.33572
66.39590
64.55157
62.94477
63.30294
41 .19005
31.84744
61 .32338
53.04549
34.70892
30.27800
58.32301
53, 14450
52.99017
52.99017
51.69414
53.88262
50,90107
52.66695
50,91139
50,90107
50.90107
19.84795
34.05796
20,01547
44.94246
49, 11102
50,88045
51.47383
50,51931
48.04889
50,44972
50.14461
52,22083
51,51034
52.:.' 2083
51 ,10817
-------
TABLE C.4-18 (Continued): SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-18:
x 5
UNSTAGED COMBUSTION IN RESIDUAL OIL-FIRED BOILERS WITHOUT AIR PREHEAT0
o
I
ro
•P»
oo
LOCATION
NUMBER
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
19
J.9
19
19
19
19
19
20
20
20
20
20
20
20
UNIT
NUMBER
2
2
2
9
2
2
2
2
2
M
2
2
2
2
2
2
-)
2
2
2
2
2
2
2
9
2
2
2
2
2
4
4
*
4
4
4
4
TEST
NUMBER
195,01
195.02
195,03
195..04
195.05
195.06
195.07
195.08
195,09
195,10
196.01
196.02
196.03
196.04
200,01
200,02
200.03
200,04
200,05
200.06
200.07
201.01
201.02
201.03
201,04
203.01
203.02
203.03
203.04
203.05
8,01
8.02
8.03
8.04
8.05
8.06
8.07
MOX
EMISSIONS
10 5,0
103 ,0
96,0
92.0
122.0
98.0
93,0
96.0
90.0
112,0
103.0
101 ,0
100.0
100.0
102,0
97.0
109.0
108.0
101.0
108.0
103,0
105.0
104 ,0
101 .0
103,0
105,0
105,0
105,0
106,0
105,0
60,0
60.0
60,0
60.0
60,0
60.0
60.0
HEAT RELEASE RATE
(1000' BTU/HR'FT-FT)
50,321 10
50.32620
49,92118
50.32620
19.95154
49,60725
48,52392
19,60725
50,32620
48.52883
49.69887
50,42418
50,04371
49,70390
50,56361
50,93770
50.94285
52.02395
51.66015
52.39306
51,29634
50.32110
50.68567
50.32620
50.3262'0
50,33639
50, 3 -H 4V
51 .05031
52,12356
51 ,05031
91 .87270
113,28082
75.54795
60.80688
95.11122
91,67346
95. 13064
-------
TABLE C.4-18 (Continued): SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-18:
UNSTAGED COMBUSTION IN RESIDUAL OIL-FIRED BOILERS WITHOUT AIR PREHEAT
54
o
ro
LOCATION
NUMBER
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
27
27
27
27
27
27
27
27
27
27
27
27
UNIT
NUMBER
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
1
1
i
1
1
1
1
1
1
1
1
1
TEST
NUMBER
8.08
170,01
170,02
170,03
170.04
170,05
171.01
171,02
171,03
171.04
171.05
171.06
171.08
171.09
171.10
172.01
172.02
172,03
175.01
175.02
175.03
175.04
175,06
111,01
111,03
111,04
111,05
111,06
111.07
111,08
111.09
111.10
111.12
111.13
111.14
NOX
EMISSIONS
(PPM)
290
259
251
264
227
260
264
286
256
240
263
262
275
249
262
261
255
270
267
258
240
258
240
458
521
560
536
537
508
401
499
439
592
598
554
FUEL
NITROGEN
(LB/MILLIOH BTU)
0,20
0.16
0.16
0.16
0,16
0,16
0.16
0,16
0,16
0,16
0,16
0,16
0,16
0. 16
0, 16
0.16
0.16
0. 16
0.16
0.16
0,16
0, 16
0. 16
0.42
0.42
0.42
0.42
0,42
0,42
0,42
0,42
0.42
0,42
0.42
0.42
EXCESS
OXYGEN
(VOL. X)
5.4
3.5
3.5
3.3
3.3
3.7
5.5
6.3
5.0
4.2
4.5
4.5
4.6
4.2
3,8
3,7
2.7
3.8
3.4
2.8
2.0
3,4
2,8
9,3
4.5
7.3
8,2
6,2
6.0
5.9
8,9
9, 1
11,0
11 , 1
11 ,0
COMBUSTION
TEMP, <°F>
60,0
93.0
93,0
90.0
91 .0
91.5
91.0
94.0
91,0
93.0
92.0
90.0
95.0
93.0
95.0
93.0
92,0
92.0
93,0
93.0
93.0
89,0
91,0
60,0
60.0
60.0
60,0
60,0
60,0
60.0
60,0
60,0
60,0
60,0
60,0
HEAT RELEASE RATE
(1000 BTU/HR'FT- FT)
95.32175
120.19462
121 .77915
114.94754
118.08887
118.08887
58.69739
70.14066
73,29769
89,78968
91 .84764
93,16760
94.13615
95.71266
110,17700
113.93175
115.47169
114,56247
114.56247
114,56247
114.56247
116,38092
115.47169
140,04567
131,86122
135, 15775
135.30864
136.80602
138. 45428
135.08916
98,8858(1
90,59018
57.67757
32,94188
16, 17953
-------
TABLE C.4-19: SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-19: :
X , 44
STAGED COMBUSTION IN RESIDUAL OIL-FIRED BOILERSJH
o
I
t\3
tn
o
LOCATION
NUrBER
7
7
18
18
18
18
18
19
19
19
19
19
19
38
38
UNIT
NUMBER
3
3
2
3
3
3
4
2
2
2
2
2
2
2
2
TEST
NUMBER
6.19
6.36
9.10
21.13
21.15
21.16
22.13
198.02
198,03
198.04
198.09
198.10
198.11
188.01
188.21
TEST
TYPE
BO
BO
BO
BO
BO
BO
BO
SC
SC
SC
SC
SC
SC
SC
SC
NOX
EMISSION'!
(PPM)
220
174
175
220
221
217
168
108
112
126
109
120
123
173
161
FUEL.
NITROGEN
(IB/MILLION BTU)
0,17
0,17
0.14
0.14
0.14
0,14
0.14
0.07
0,07
0.07
0.07
0.07
0.07
0.25
0.25
EXCESS
OXYGEN
(VOL. Z)
8.1
6.0
8.2
6.0
6.3
6,6
8,3
2,4
2,3
3.1
2.9
2.9
3.3
2.9
3,5
COMBUSTION
TEMP, ( F)
240
242
60
410
410
410
565
101
104
105
97
97
100
320
320
HEAT RELEASE RATE
(1000 BTU/HR FT FT)
74.43371
100,67064
44.75086
71 .37009
70,43101
71 .37009
79.13102
51.53278
51 ,16"49
50,79660
51.55889
51 .53278
51.53278
-------
TABLE C.4-20: SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-20:
UNSTAGED COMBUSTION IN DISTILLATE OIL-FIRED BOILERS54
o
LOCATION
NUMBER
1
1
i
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
17
17
17
17
17
17
17
17
17
UNIT
NUMBER
1
3
3
3
3
3
2
2
2
2
2
2
2
1
1
1
1
1
1
1
1
2
2
2
2
2
2.
X.
2
2
NOX
TEST EMISSIONS
NUMBER' (PPM) (
62.01
66.01
66.02
66.03
66,04
66.05
102.01
102.02
102.03
102.04
102.05
102.06
103.01
107.01
107.02
107.03
107.04
107,05
108,01
108.02
108,03
7.01
7.02
7.03
7,04
7.05
7.06
7.07
7.08
7.09
103
123
123
116
119
104
87
106
100
92
103
90
84
79
85
92
97
96
80
84
86
164
181
203
167
204
183
165
166
158
FUEL
NITROGEN
[LB/MILLION BTU)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
,020
.020
.020
.020
.020
.020
.020
.020
.020
.020
.020
.020
.020
.020
.020
.020
.020
.020
*020
.020
,020
.006
.006
.006
,006
.006
.006
.006
.006
.006
EXCESS
OXYGEN
(VOL. %>
9
5
7
5
4
2
5
8
7
5
9
5
4
3
2
4
5
5
3
3
3
5
6
7
3
5
5
5
6
8
.0
.9
.0
.5
.8
,8
,2
.2
.5
,1
,5
,3
,7
.1
.7
.5
.9
.2
.9
,6
.8
.3
.9
.8
.8
.8
.6
.5
.8
.2
COMBUST
TEMP. (
60,
350.
350.
350.
350.
350.
60.
60.
60.
60.
60.
60.
60.
60*.
60.
60.
60.
60,
60.
60.
60.
320.
320,
320,
320,
320,
320.
320,
320.
320,
ION
°F>
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
HEAT RELEASE RATE
(1000 BTU/HR-FT'FT)
25.
55.
55.
55.
56,
56.
44.
33.
33.
33.
33.
44.
43.
52.
54.
41,
41.
40.
39,
53,
53.
85.
85.
85,
86.
107,
87,
68,
47.
31 .
307G6
03762
03/62
02652
22275
03539
07734
63119
63458
63797
63797
07734
53317
53035
78223
36617
36201
24412
13017
66423
66423
66011
66011
66011
63352
12940
64244
12491
68260
13334
-------
TABLE C.4-20 (Continued): SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-20:
x 54
UNSTAGED COMBUSTION IN DISTILLATE OIL-FIRED BOILERS3*
o
I
PO
C71
LOCATION
NUMBER
17
17
19
19
19
19
19
19
19
19
19
19
19
36
36
36
36
36
36
36
36
36
36
36
36
36
36
36
36
36
UNIT
NUMBER
2
2
1
1
1
1
1
1
1
1
1
1
1
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
TEST I
NUMBER
7.10
7,11
52,01
52,02
52.03
52.04
52.05
53.01
54.01
5-1.02
54,03
54.04
54,05
160.01
160.02
160.03
160.04
160.05
160.06
160,07
161.01
161.05
161.06
161.09
161.10
161.11
161,12
162,01
162,02
163.03
NOX
EMISSIONS
(PPM) <
181
184
71
64
76
70
66
91
83
82
85
82
82
103
98
104
93
88
89
102
103
99
108
138
99
100
108
131
87
91
FUEL
NITROGEN
(LB/MILLION BTU)
0,006
0,006
0.003
0.003
0.003
0.003
0.003
0.003
0,003
0.003
0.003
0.003
0.003
0.007
0/007
0.007
0,007
0,007
0.007
0.007
0,007
0.007
0.007
0.007
0,007
0.007
0,007
0,007
0,007
0.007
EXCESS
OXYGEN
(VOL. Z)
5.7
5.5
3.6
2.6
4.3
5.3
3,6
3,0
4,5
3,7
5.7
6,6
4,3
4.4
6,8
3.3
3.6
5.6
5,5
9,5
5.7
3.7
2.5
4,7
9.1
9.4
9.0
5.6
5.9
6.2
COMBUSTION
TEMP. (°F)
320.0
320.0
60.0
60.0
60.0
60.0
60.0
60.0
60.0
60.0
60.0
60.0
60.0
92.0
82.0
85.0
83.0
92.0
88.0
88.0
92.0
84.0
86.0
86.0
87.0
86.0
88.0
88,0
89,0
92.0
HEAT RELEASE RATE
(1000 BIU/HR'FT'FT)
85.66879
82.73149
49.73'112
49,74420
49.73412
49.72405
49.73412
49.01371
39.46831
40.74148
40.73323
40.72911
41.212-15
62.36190
55.02521
82.52941
69.71989
47.72250
55.00840
33.05210
55.04202
69.69150
72.44248
73.35948
33.91148
32.99496
32.99496
69.69150
71.51092
47.72250
-------
TABLE C.4-21: SHORT-TERM N0x EMISSION DATA FOR FIGURE 4.3-21:
STAGED COMBUSTION IN DISTILLATE OIL-FIRED BOILERS54
1
o
1
ro
ai
oo
LOCATION
NUMBER
36
36
36
36
36
UNIT
NUMBER
6
6
6
6
6
TEST
NUMBER
161.01
161.02
161.03
161.04
161,07
TEST
TYPE
NA
SC
SC
SC
SC
NOX
EMISSIONS
(PPM) <
103
96
98
103
97
FUEL
NITROGEN
1LB/MILLION BTU)
0,
0.
0,
0.
0.
007
007
007
007
007
EXCESS
OXYOEN'
(VOL. '/.)
5,7
5.5
5.4
5.5
2,5
COMBUSTION
TEMP. (°F> (
92.0
93.0
93.0
92.0
88.0
HEAT RELEASE RATE
1000 BTU/HR'FT'FT)
54
54
54
54
68
.90196
.90196
,90196
.64078
.69878
-------
TABLE C.4-22:
SHORT-TERM NOX EMISSION DATA FOR FIGURE 4.3-23:
UNSTAGED COMBUSTION IN NATURAL GAS-FIRED BOILERS54
o
!M
01
LOCATION
NUMBER
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
UNIT
NUMBER
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
'2
2
3
3
TEST
NUMBER
12,04
12,05
12,06
12,07
12,08
12,09
12,10
12.11
12.12
12,13
12.14
12.15
12,16
12.17
12.18
12,20
12,21
12.22
12.23
12.24
12,25
12.26
12.27
12.28
12.29
12.30
5.01
5.02
5.03
5.04
67,01
67,02
NOX
EMISSIONS
(PPM)
70
45
67
71
77
32
85
5?
72
71
69
72
74
72
65
83
77
68
102
53
83
84
89
94
85
77
70
76
74
72
89
83
EXCESS
OXYGEN
(VOL, %)
2.8
0,5
1,5
4,2
5.0
12,0
5,2
0,6
2.9
2,3
2,6
3,1
3,7
4,5
1,9
2.9
6.7
8.8
8.7
0.2
0.5
1,5
2..S
3,6
0,5
6.7
3,4
4.0
2,7
6,9
3.B
3.8
COMBUSTION
TEMP. (°F)
85. 0
60.0
60.0
60,0
60,0
60,0
60.0
60,0
60,0
60,0
60.0
60,0
60.0
60,0
60.0
60,0
60,0
60,0
60.0
60.0
60.0
60,0
60.0
60,0
60.0
60.0
60.0
60,0
60.0
60.0
350.0
350.0
HEAT RELEASE RATE
(1000 BTU/HR'FT'FT)
50.59983
70.93749
60,14079
48.11749
38.47457
19,23729
42,10280
57.73516
59.41910
55,32953
52,92390
52,92390
54.12671
54.12671
54.12671
56.53235
43.28389
34.24171
18,03496
56.53235
56,53235
56.53235
55.32953
56.53235
55.10115
43.30137
50.93411
54.12125
54.12125
45.70239
36,05031
73.29202
-------
TABLE C.4-22 (Continued): SHORT-TERM N0x EMISSION DATA FOR FIGURE 4.3-23:.
UNSTAGED COMBUSTION IN NATURAL GAS-FIRED BOILERS54
o
I
en
en
LOCATION
NUMBER
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
2
2
2
6
6
6
6
UNIT
NUMBER
3
3
3
3
2
2
2
2
2
2
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
4
4
4
3
3
3
3
TEST
NUMBER
67,04
67,05
67,06
67.07
101,01
101.02
101 ,03
101 .04
101,05
101 ,06
104.01
105,01
105,02
106.01
106,02
13.01
13,02
13.03
13.04
13.05
13.06
13.07
13,08
13,09
13,10
69.01
69,02
69.03
25.01
25.02
25.03
25.04
NOX
EMISSIONS
(PPM)
96
95
90
77
77
78
80
74
82
83
75
80
82
82
84
135
136
132
121
111
126
104
131
139
136
101
86
83
184
235
277
350
EXCESS
OXYGEN
(VOL. '/.)
5.7
6.4
4.5
2.7
1.8
2,2
4,9
6.4
4.0
4«7
0,9
1 .8
2,9
2,6
3,5
2,2
5,1
4.0
3,0
1.1
2.4
2.2
6.2
8.5
11 .0
3,8
3,0
4,5
14.5
13.0
11,8
11,5
COMBUSTION
TEMP. (°F)
350.0
350.0
350.0
350.0
60.0
60.0
60.0
60.0
60,0
60.0
60.0
60.0
60.0
60.0
60,0
60,0
60.0
60.0
60.0
60.0
60.0
60.0
60.0
60.0
60.0
60,0
60,0
60,0
310,0
310,0
310.0
310,0
HEAT RELEASE RATE
(1000 BTU/HR'FT'FT)
58,38517
59,62139
60,11824
60.09308
57.53863
39,92476
39,92476
39.92476
39.92476
41,09902
54,98927
54.98927
54.98927
55.67664
42,91741
43,19693
44,33369
44,33369
43,75793
55.54503
58.83025
48,53864
34.98965
28.45537
24.61736
48,18404
48.17916
48.18404
41 ,33714
48,70232
61,98009
73,23261
-------
TABLE C.4-22 (Continued): SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-23:
x 54
UNSTAGED COMBUSTION IN NATURAL GAS-FIRED BOILERS™
o
I
ro
en
LOCATION
NUMBER
&
6
6
6
6
6
6
6
6
6
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
UNIT
NUMBER
3
3
3
3
3
3
3
3
3
3
1
1
1
1
1
i
i
i
i
i
i
2
2
2
2
2
2
2
2
2
2
2
TEST E
NUMBER
25,05
25,06
25.07
25.08
25,09
25,10
25.11
25.12
25.13
25.14
15.01
15,02
15,03
15,04
15,05
15,06
15,07
15,08
15.09
15.10
15,11
24.01
24.02
24,03
24,04
24,05
24,06
24,07
24,08
24,09.
24,10
30,01
NOX
[MISSIONS
(PPM)
302
104
209
243
249
214
330
318
262
289
241
229
157
252
188
245
214
138
200
152
203
403
404
374
355
380
377
339
354
339
352
181
EXCESS
OXYGEr.N
(you. •/.)
11,5
13.5
12.0
11 ,4
10,8
12,3
13,1
12.0
11,1
14,3
2.6
1.9
1.4
3.3
1,5
2.0
1.8
1,8
1,8
1.8
2.6
3.8
3.5
3.8
4.0
3.6
3.2
2,6
3,9
4,3
3,6
3.2
COMBUSTION
TEMP. <°F) 1
332.0
310.0
310.0
315,0
315,0
310,0
307,0
303,0
297.0
303.0
400.0
400,0
400,0
400,0
400.0
420,0
430.0
400.0
395.0
390,0
390,0
330,0
340,0
330.0
325,0
320.0
322.0
322.0
322.0
322.0
322.0
401.0
HEAT RELEASE RATE
11000 BTU/HR'FT'FT)
63.54998
- 30,24199
53.06671
57,74456
57,37409
55.42487
55.19823
57.58689
55.11729
52.79831
53.99901
57.79293
54,18087
57.78132
56.57755
72.91682
52.36433
41 .46697
47.54922
48.15110
49.35488
92.84532
100.94925
99.94743
85.46178
90.17227
90.17227
90.84520
90.84520
90.84520
90.17227
95.78203
-------
o
I
ro
en
TABLE C.4-22 (Continued): SHORT-TERM N0x EMISSION DATA FOR FIGURE 4.3-23:
UNSTAGED COMBUSTION IN NATURAL GAS-FIRED BOILERS54
LOCATION
NUMBER
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
10
10
10
10
10
10
10
10
UNIT
NUMBER
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
4
4
4
4
4
4
4
4
TEST
NUMBER
30,02
30,03
30.04
30,05
30,06
30,07
30,08
30,09
30, 10
30, 12
30.13
30,14
30,15
30,16
30.17
30.18
30,19
JO. 20
30,21
30.22
30.23
30,24
30,25
30,29
14,01
14.02
14.03
14.04
14.05
14.06
14.07
14,08
NOX
EMISSIONS
(PPM)
154
194
166
171
197
195
200
195
198
215
182
205
199
218
185
191
212
217
222
216
182
168
179
183
104
102
108
110
108
115
95
90
EXCESS
OXYGEN
(VOL. %)
4.5
5,6
3,2
2,5
2.9
2,4
4,3
5.0
2,9
4,5
2.7
3,1
2,3
4,1
5.4
3.0
2,8
2,3
4,1
5.1
2,9
2,9
2,7
2,7
5,2
6,0
3,9
2,5
4,9
3,7
6,7
7.9
COMBUSTION
TEMP. <°F>
401 ,0
401,0
401 .0
401 ,0
401,0
374,0
374.0
374,0
374,0
401 ,0
374.0
392,0
392,0
401,0
101.0
392.0
392.0
401.0
396.0
406.0
383.0
374.0
383.0
383.0
60.0
60.0
60.0
60,0
60,0
60.0
60,0
60,0
HEAT RELEASE RATE
(1000 BTU/HRTT'FT)
96,56075
96,56075
96.56075
96.56075
71,64185
71,64185
71,64185
71.64185
72.03120
92.71010
55.02314
100,84369
100,84369
100,84369
99.28626
101,23304
98.89690
101.23304
102.12374
102.12374
81 .34091
68,07083
77,84271
77,48222
73.94458
/*„ 59925
76.59925
77.84985
77,06822
95,38714
64,11267
47,65986
-------
TABLE C.4-22 (Continued): SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-23::
x 54
UNSTAGED COMBUSTION IN NATURAL GAS-FIRED BOILERS3H
o
i
ro
LOCATION
NUMBER
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
12
12
12
12
12
12
12
12
12
12
12
UNIT
NUMBER
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
24
24
24
24
24
24
24
24
24
24
24
TEST
NUMBER
14.09
60,01
80.02
80.03
80.04
80.05
80.06
80.07
80.08
80.09
80,10
80.11
80.12
80. 13
80.14
80,15
80.16
80.17
80.18
80,19
80,20
75.01
75.02
75.03
75.04
75.05
75,06
75.07
75.08
75,09
75,10
75,11
NOX
EMISSIONS
(PPM)
87
96
120
135
151
154
137
137
124
107
103
94
96
124
107
107
116
163
164
161
74
171
176
191
174
203
209
200
139
190
255
173
EXCESS
OXYGEN
(VOL. X)
9.7
7,2
6,2
5.6
2,3
3.9
1,0
5,4
5,4
7.1
7,4
8,1
8,2
6.9
8.0
7.4
6,4
3,9
3,1
2,0
8.7
6.0
5,8
5.5
5,6
5.3
6.4
6,1
4.4
5,3
7.4
5.4
COMBUSTION
TEMP. (°F>
60.0
60,0
60.0
60,0
60.0
60,0
60,0
60.0
60.0
60.0
60.0
60.0
60,0
60.0
60.0
60.0
60.0
60.0
60,0
60.0
60.0
660.0
660.0
660.0
660.0
660.0
645,0
640.0
640.0
640.0
648.0
660.0
HEAT RELEASE RATE
(1000 BTU/HR'FT-FT)
32,44642
87,54286
87,51633
87,54286
91.58330
91,58330
92.25671
67.29304
55,21934
39.36839
89.56308
124.29162
125.25363
147.45481
114,47913
114.47913
115,82594
118.51957
121,22544
119,87849
100,30718
62,29022
44,09537
52,57525
68.01419
76.66026
60.60670
61,32821
62,44204
62.29022
61.28011
62,42rP7
-------
TABLE C.4-22 (Continued): SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-23:
x 54
UNSTAGED COMBUSTION IN NATURAL GAS-FIRED BOILERS0*
o
I
ro
LOCATION
NUMBER
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
19
19
19
19
19
19
19
19
19
19
19
27
27
UNIT
NUMBER
24
24
24
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
2
2
2
2
2
2
2
2
2
2
2
1
1
NOX
TEST EMISSIONS
NUMBER (PPM)
75
75
75
77
77
77
77
77
77
77
77
77
77
77
77
77
77
77
77
190
190
190
190
190
190
190
191
191
191
191
109
109
.12
,13
,14
,02
.03
.04
.05
,06
,07
,08
,09
.10
.11
.12
.13
,14
.15
.16
.17
,01
.02
.03
.04
.05
,06
,07
.01
,02
.03
.04
.01
,02
168
164
163
229
250
265
235
223
234
270
291
342
327
320
287
336
358
347
245
56
59
59
60
69
83
61
54
55
55
58
113
142
EXCESS
OXYGEN
(VOL, '/.)
5
6
6
3
'3
4
4
4
4
4
4
3
4
4
3
5
6
4
5
3
3
3
2
3
2
2
9
2
2
2
6
5
.3
,2
.7
.8
.5
.1
.9
.9
,7
,5
,2
,9
,5
,0
,5
.3
,2
,5
,8
,2
,7
,2
,8
t 2
.6
.5
,0
,9
.0
.6
.6
,0
COMBUSTION
TEMP. <°F)
660
640
645
638
627
644
610
625
635
650
665
680
655
650
640
645
645
645
645
95
110
100
98
92
115
97
100
106
111
111
60
60
.0
,0
,0
,0
,0
,0
.0
,0
.0
,0
,0
,0
.0
,0
,0
,0
.0
,0
,0
,0
,0
.0
,0
,0
.0
,0
.0
,0
,0
,0
,0
.0
HEAT RELEASE RATE
(1000 BTU/HR'FT'FT)
62
62
62
63
60
68
52
57
62
68
73
79
68
68
68
68
67
68
66
60
52
52
46
54
54
52
61
52
52
52
122
123
.58302
.27395
,42577
.04041
,26016
.13814
.63497
.88327
.98515
.23391
.48268
,66872
.40751
.40751
.40751
.40751
,09198
,23391
.75147
,38532
,78364
,84251
.04381
.72974
.35229
.85321
.89495
.83716
,83180
.83180
.09994
.59480
-------
TABLE C.4-22 (Continued): SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-23:
x 54
UNSTAGED COMBUSTION IN NATURAL GAS-FIRED BOILERS34
o
I
LOCATION
NUMBER
27
27
27
27
27
28
28
28
28
29
29
29
29
29
29
29
32
32
32
32
32
32
32
32
32
32
32
32
32
32
32
UNIT
NUMBER
1
1
1
1
1
1
1
1
1
5
5
5
5
5
5
5
4
4
4
4
4
1
1
1
1
1
1
1
1
1
1
TEST I
NUMBER
109,03
109,04
109,05
109,06
109,07
122,01
123,01
123,02
123.03
113.01
113.02
114.01
114,02
114.03
114.04
114.05
140,01
140.02
141.02
141.03
141.04
143.01
143.02
143.03
144.01
145.01
145.02
145.03
146.01
148.01
148.02
NOX
EMISSIONS
(PPM)
159
146
101
99
104
211
172
166
197
155
154
166
162
155
160
149
149
160
213
213
206
231
231
230
235
227
226
218
207
216
229
EXCESS
OXYGEN
(VOL. %)
3,9
1,3
6,9
6,5
6.1
5.7
4.1
3.7
6.2
5.4
5.3
4.7
4.0
4.4
3.2
6,0
6,8
7.1
6.1
8.2
6,6
4.3
4.5
4.4
4.4
3.7
3.1
2.2
4.0
4.2
4.2
COMBUSTION
TEMP. (°F>
60.0
60.0
60,0
60.0
60.0
335.0
338.0
336,0
333,0
375.0
380.0
390.0
390.0
376.0
375.0
383.0
390.0
390.0
398.0
385.0
388.0
390.0
390.0
390.0
390.0
390.0
390.0
390,0
390,0
390.0
390,0
HEAT RELEASE RATE
(1000 BTU/HR- FT'FT)
128,19945
128.53859
32,96530
• 19.42286
57,73612
30.98201
31,28040
30.23160
31 .28040
81.08703
81.08703
82.11283
82.78041
80.11008
79.44249
80.77766
57.66559
56.03311
56.02348
56.15356
59.20747
53.30804
53*95814
53.95814
52,00785
53.83256
53.95814
53.95814
39.19793
53.30804
53.30804
-------
TABLE C.4-23: SHORT-TERM NO EMISSION DATA FOR FIGURE 4.3-24:
STAGED COMBUSTION IN NATURAL GAS-FIRED BOILERS54
o .
I
en
LOCATIOf
NUMBER
9
9
9
9
9
9
9
32
32
32
38
38
38
38
38
38
38
39
39
39
39
39
39
39
39
39
39
< UNIT
NUMBER
1.1
1.1
1.1
1,1
2.1
2.1
2.1
1.0
1.0
1.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
108.0
108.0
108.0
108.0
108.0
108.0
108.0
108.0
108.0
108.0
TEST
NUMBER
15.04
15.12
15.13
15.14
30.29
30,26
30,27
146,01
147.07
147.08
181.02
183.44
183.47
184.01
184.05
185.03
185.05
208.06
209.01
209.02
209.03
209.04
209.05
209.06
209.10
209.11
209.12
TEST
TYPE
NA
SC
SC
SC
NA
SC
SC
NA
SC
SC
NA
SC
SC
NA
SC
NA
SC
NA
SC
SC
SC
SC
SC
SC
SC
SC
SC
NOX
EMISSIONS
(PPM)
252
228
210
190
183
102
10~5
207
146
156
233
161
102
235
110
211
117
184
114
116
126
147
137
135
126
120
122
EXCESS
OXYGEN
(VOL. •/.)
3,3
4.4
3,0
2.4
2.7
3,4
3,8
4.0
4.4
4,4
3.2
3,4
2.9
1.8
2.1
4.1
2.6
4.4
3.6
4,6
5,7
6,4
5.6
5,3
4.4
2.7
4.6
COMBUSTION
TEMP. (°F> (
400.0
385.0
384.0
385.0
383.0
388,0
388,0
*
*
*
350,0
350.0
350.0
350.0
350,0
350,0
350.0
60.0
60,0
60.0
60.0
60,0
60.0
60,0
60.0
60.0
60,0
HEAT RELEASE RATE
1000 BTU/HR-FT'FT)
57.74070
49.32018
49,32018
49.32018
92.44311
92.44311
94.76580
39.24920
39,60426
38,96548
,
,
.
.
,
,
.
26.01929
26.30332
26.16946
26.08108
25.95898
25.54517
25.81652
26.08108
24.00947
25,28061
-------
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-------
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of Industrial Boilers: Site 6 - Gas-Fired Fire-tube Boiler. (Prepared
for U. S. Environmental Protection Agency.) Research Triangle Park,
N. C. Publication No. EPA-600/7-81-095b. May 1981. 161 p.
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APPENDIX D
EMISSION MEASUREMENT AND MONITORING METHODS
D.I EMISSION MEASUREMENT METHODS
Since the characteristics of the emissions from industrial boilers
are similar to those from source categories for which new source performance
standards (NSPS) have been promulgated (e.g., Subparts D and Da 40 CFR
Part 60, Fossil-Fuel Fired Steam Generators and Electric Utility Steam
Generators), it was not necessary to develop new or modified reference
test methods for the data collection phase of this study. The emissions
measured are criteria pol lutants--particulate matter, oxides of nitrogen,
and sulfur dioxide—and applicable manual reference test methods have
been promulgated in Appendix A, 40 CFR Part 60. In addition, during the
development of the Electric Utility Steam Generator NSPS, EPA promulgated
continuous measurement compliance provisions using instrumental techniques
for S09 and NO . Finally, the Agency promulgated specifications and
£. A
operating requirements for continuous monitoring of opacity, S02 and
NO in Appendix B, 40 CFR Part 60 and proposed revisions to the monitoring
/\
performance specifications in the Federal Register on October 10, 1979.
As a result of extensive comments, the Agency reproposed requirements
for S09 and NO on January 26, 1981. The procedures used in the data
£ /\
collection study are described below by pollutant.
D.I.I Particulates
Under the Fossil-Fuel Fired Steam Generator and Electric Utility
Steam Standards, the best systems of particulate control were not considered
effective for sulfuric acid mist and EPA promulgated modifications of
Method 5 to minimize the measurement of acid mist as particulate matter.
These modifications allowed probe and filter sampling temperatures up to
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160° C (320° F). Since the best systems of participate control for
industrial boilers do not effectively collect sulfuric acid mist, similar
provisions are recommended for this standard.
When operating Method 5 at elevated temperatures, EPA has found
that special care must be taken to monitor and maintain both probe and
filter temperatures so that significant sulfuric acid mist will not be
measured. This includes monitoring probe temperatures, in addition to
the sample gas stream temperature following the filter, with calibrated
thermocouples. The EPA is currently evaluating alternative analytical
techniques to subtract acid contributions of particulate measurements.
These include: 1) extracting free acid with 100 percent isopropyl alcohol
and, 2) heating the filter and probe sample catches in the laboratory
prior to weighing. These procedures would minimize the need to carefully
maintain probe and filter temperatures. If these procedures are shown to
have sufficient precision and accuracy, they will be proposed as alternative
methods. In the interim, Method 5 operated at elevated temperatures is
the recommended method for performance tests.
D.I.2 Sulfur Dioxide
EPA performed tests at four industrial boiler sites equipped with
flue gas desulfurization systems during this study. Continuous emission
measurement procedures were used to determine the SO^ removal efficiency
and emission rates from each system. The test procedures used were
based on the continuous emission measurement requirements for new electric
utility steam generators under Subpart Da 40 CFR Part 60. These procedures
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require that SCL be measured before and after the SO^ control system. A
continuous diluent analyzer is also required. If oxygen is measured as
the diluent, it is necessary to determine the moisture content of the
sample stream as analyzed.
The S0? measurement systems used in EPA tests consisted of three
major subsystems - sample collection, analysis, and recording. A gas
sample was extracted from the source through a filter and heated Teflon
sample line system. The sample was then routed to the measurement
analyzers for SCL and oxygen, which were connected in parallel. The
outputs of the measurement equipment were recorded on analog chart
recorders.
The analyzers used for SCL measurement were of the ultraviolet
spectrophotometric type. Three different types of oxygen analyzers were
used - paramagnetic, polarographic, and zirconium oxide cell. Since
oxygen was measured as the diluent, data for moisture content were
necessary. At some of the locations, refrigeration-permeation dryer
systems were used prior to sample analysis. In those cases the sample
was assumed as dry. At the remaining sites, no dryers were used and dew
point techniques were used to correct for water content. By this procedure,
the lowest temperature in the sampling and analysis system was located
and that temperature was recorded daily. In addition, manual tests were
performed to determine the actual source moisture content. The lower of
the two determinations was used for emission calculations.
The emission measurement systems for each location were tested
using the performance specification test procedures of Performance
Specification 2, Proposed Revisions of October 10, 1979. After the
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systems were demonstrated to conform to the performance specifications,
the data collection portion of testing was started. During this nominal
30 day period, the instruments were calibrated daily. Additional reference
Method 6 samples were collected for quality assurance purposes at weekly
intervals, when possible. At the end of the test period, the performance
specification tests were repeated.
The minimum data requirements were as follows:
• Each sample point must be analyzed at least once in each
fifteen minute clock interval.
• In order to calculate a 1 hour average for a SCU result, at
least two of the four 15 minute data points for each parameter
(SCL, CL) must be available.
• In order to calculate a 24 hour (one calendar day) average
result, at least 18 one hour averages must be available.
These requirements are similar to those for Subpart Da procedures,
except that for data collection purposes, the longest averaging period
considered was 24 hours versus the 30 day averaging period of Subpart
Da.
D.I.3 Nitrogen Oxides
EPA performed studies at six industrial boiler sites where various
combustion modifications were made for NO reduction. Continuous emission
/\.
measurement procedures were used to determine the NO emissions before
A
and after the modifications. The procedures used were based on the
continuous emission measurement requirements of the electric utility
NSPS. Oxides of nitrogen were measured using chemiluminescence analyzers.
D-4
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This assumption was validated by the results of the relative accuracy
portions of the performance specification tests. Both oxygen and carbon
dioxide were measured as diluents. The sample stream was passed through
a condenser-dryer system prior to being introduced to the instrument
system. Performance specification tests and daily calibrations were
performed as described in the sulfur dioxide discussion above. The
minimum data requirements for computing averages were also similar.
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D.2 COMPLIANCE TEST METHODS
The reference test methods and procedures available for determination
of compliance with an emission limitation, along with the costs of each
type procedure, are discussed in this section. The choice between the
alternatives depends primarily on the averaging time necessary to confidently
establish an average emission level. The manual reference methods
(Method 5 for particulates, 6 for sulfur dioxide, and 7 for nitrogen
oxides) are generally only applicable for short term tests that yield
essentially one hour to three hour averages. If it is determined that a
longer term average is required, automated measurement techniques are
more appropriate. However, if the automated measurement methods incorporate
sampling and analysis principles that are different from the manual
measurement techniques, it is necessary that results from these methods
be proven comparable to results of the manual techniques. For example,
for instrumental sulfur dioxide measurement, comparative tests must be
performed initially and at specified intervals using Method 6 to demonstrate
that the results from the two techniques were within an allowable difference.
D.2.1 Emission Measurement Options
The measurement procedure options are discussed in this section.
For clarity, the procedures are grouped as alternatives by pollutant
measured.
D.2.1.1 Particulate
As with the Electric Utility Steam Generator Standard, the best
systems of particulate control for industrial boilers are not effective
for sulfuric acid removal. Therefore, Method 5 modified to allow probe
and filter temperatures up to 160° C (320° F) is recommended as the
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compliance method. In addition, the use of Method 17 is recommended as
an alternative to Method 5 whenever the average stack gas temperature at
the sampling location does not exceed 160° C (320° F).
D.2.1.2 Opacity
Method 9, "Visual Determination of the Opacity of Emissions from
Stationary Sources," is recommended as the compliance test method for
opacity. This method is applicable for the determination of opacity of
effluent streams emitted from stacks.
Continuous monitors for opacity are not recommended for use in
determining compliance with this regulation because an absolute accuracy
check is not possible with the current state-of-the-art opacity monitoring
systems.
D.2.1.3 Sulfur Dioxide
Reference Method 6
EPA Method 6 is the manual method for short term determination of
SOp emissions from stationary sources. Method 6 is a wet chemical
sample collection and analysis procedure that requires a working knowledge
of emission sampling techniques and laboratory analysis methods. Method
3 (02 and C02) must be run concurrently in order to obtain S02 emission
data in terms of the standard. The manpower requirements are one to two
people for about one day to complete three to nine test runs and analyses.
Use of Method 6 for emission monitoring purposes would be limited
to periodic tests (i.e., weekly, monthly, etc.) because of the high cost
and manpower requirements. Enforcement would be simplified as the
regulatory agency need only check the test report to establish compliance.
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A second advantage is that, although the cost of each test is high, the
annual cost of periodic tests could be less than for continuous monitoring
or on-site coal analysis, if the repetition period is appropriately
selected.
A disadvantage of the periodic emission test approach is that
continuous compliance data cannot be collected.
The Agency has proposed Method 6A, which combines the SCL measurement
capabilities of Method 6 with a CCL measurement, using ascarite absorbent,
so that measurement of SCL emissions in terms of the standard can be
completed with one sampling train. This would eliminate the need for
Method 3 measurements and decrease the manpower needs for conducting
manual tests. Method 6A was proposed in the Federal Register on
January 26, 1981.
Automatic SOp Sampling
EPA has developed Method 6B (also proposed in the Federal Register
on January 26, 1981) that makes use of the combined SCL and CCL measurement
capabilities of Method 6A in a long-term sampling method. Method 6B can
be operated intermittently for 24 hours using a timing switch to obtain
representative daily samples. Alternatively, a low-flow (50 ml/min)
pump may be used to sample continuously over 24 hours or intermittently
over longer periods (3 to 7 days) to obtain a longer-term average value.
Method 6B can be applied as an emission monitoring method by operating
the equipment automatically at the appropriate emission points and
analyzing the collected samples on-site.
Manpower requirements are less than for Method 6 as only one test
train is operated at a sampling point instead of three runs that constitute
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a Method 6 test. One person can prepare fresh chemicals, remove the
used collection section, replace with a fresh train, and analyze the
collected samples in less than one-half day. The training necessary is
a knowledge of simple laboratory techniques.
The advantage of using Method 6B as an emission monitor over the
periodic use of Method 6 or Method 6A is that Method 6B can establish
compliance on a continuous or semi-continuous basis. The capital costs
and annual costs for operating Method 6B are less than for a continuous
monitoring system.
One disadvantage associated with Method 6B is that real time data
are not provided. All data are produced one day to one week following
the emission occurrences.
The manual methods above are applicable for determining control
efficiency across sulfur control equipment. Methods 6, 6A, and 6B have
been used for this purpose and have proved satisfactory.
Continuous Emission Measurement
EPA has promulgated procedures by which sulfur dioxide and oxides
of nitrogen can be measured on a continuous basis using the instrumental
techniques. The advantage of these procedures is that the averaging time
for an emission limitation can be much longer than for manual techniques.
By using a longer averaging period, short term peaks and normal variations
in emissions can be smoothed. Also, a continuous record of emissions is
provided. A disadvantage of this procedure is that relatively sensitive
and sophisticated equipment is required, and in some cases daily inspection
and maintenance labor are necessary.
The continuous measurement procedures promulgated by EPA for Electric
D-9
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Utility Steam Generators would be applicable on a technical basis, not
considering cost. That regulation requires analyzers to be installed
and operated to measure sulfur dioxide before and, if applicable, after
a control device. In order to express the pollutant emissions in terms
of the standard (nanograms/joule), a diluent analyzer is required.
These instruments may measure either oxygen or carbon dioxide. In
addition, if oxygen measurement is performed, a method must be available
to establish the moisture content of the sample gas.
Specifications for selection and installation of the analyzer
systems are given in 40 CFR 60 Appendix B, Performance Specification 2.
Also included in this reference is a series of test procedures to which
the instrument system is subjected in order to establish stability and
accuracy. These tests are intended to determine the drift stability and
calibration repeatability using calibration materials, and to establish
accuracy by performing comparative tests using Reference Method 6 for
so2.
Once an analyzer system has been tested to show conformance with
the performance specifications, it is placed in service for data collection.
The minimum data requirements are that at least one data point be obtained
for each fifteen (15) minute clock period, and that at least two of
these data points must be available to calculate an average for a 1 hour
interval. The Electric Utility NSPS is on a 30 day average basis. At
least 18 of 24 hour averages each calendar day and 22 of 30 days must be
available to calculate a 30 day average.
D-10
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In order to insure the continuing quality of the data obtained by
the continuous emission measurement system, EPA is currently developing
requirements for quality assurance testing. Daily calibration results
would be used as a measure of precision, and relative accuracy tests
using the reference methods would be performed at quarterly or semi-
annual intervals to determine accuracy.
Continuous measurement systems can be used to determine emission
rates for S02 and also to determine removal efficiency for SCL control
devices. Instrument systems can also be used in conjunction with fuel
monitoring and analysis for SCL to determine removal efficiency. The
testing and calculation procedures required for these alternatives are
included as Reference Method 19 in Appendix A, 40 CFR 60. The quantity
of data generated by a continuous measurement system would probably
require that the calculations be performed automatically by a data
retrieval and reduction system.
Fuel Analysis
The agency has reviewed and considered use of fuel sampling and
analysis to determine potential sulfur emissions from fossil fuel-fired
boilers. This section discusses two major areas of fuel measurements:
coal sampling and analysis, and oil or gas sampling and analysis.
Coal Sampling and Analytical Options
The Agency relies on ASTM (American Society for Testing and Materials)
reference methods which clearly specify procedures for collecting and
analyzing representative coal samples. Mechanical, regularly spaced,
increment collections provide the most representative results. The
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sample analyses required are total sulfur content and the fuel high
heating value from which potential sulfur emissions in terms of the
standard (ng/J) can be calculated.
The ASTM procedures that apply are D2234 for coal sampling, D2013
for sample preparation, D271 for sulfur content analysis, and either
D271 or D2015 for heating value analysis. Several alternative analytical
procedures are available in the form of instrumental measurements of
fuel sulfur and heat contents. ASTM has not approved these procedures as
the procedures have not demonstrated a precision equivalent to the
approved AS1M methods. Others have claimed adequate or superior precision
capabilities for these procedures. The Agency will rely on the ASTM
methods until sufficient data are provided to demonstrate the adequacy
of alternative procedures.
The location specified for the collection of the coal sample can
affect the accuracy and the cost associated with each reported value.
The first option is to require the user to obtain from the coal vendor
(the mine operator or fuel treatment plant operator) a certified analysis
of the delivered coal. This certification will identify the coal delivery,
the analysis results for that coal, and document that the sampling and
analytical procedures specified by the Agency were followed. The advantages
of this option are: 1) the cost of sampling can be spread by the vendor
to all purchasers resulting in a lower cost per sample, and 2) compliance
determination is simplified as the enforcement agency need only check
the fuel certification.
D-12
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One disadvantage of this approach is the difficulty in applying an
enforcement action if the certified fuel analysis is incorrect. The
coal vendor is not the affected facility for this regulation, so direct
enforcement and policing of the fuel sampling and analytical procedures
is not possible.
A second disadvantage of the vendor supplied certification option is
the difficulty in correlating the fuel analyses data with the emission
averaging time. A short averaging time for the emission standard (one
day or less) would require strict accounting and traceability for each
parcel of delivered coal. This may not be possible or practical at most
industrial boiler facilities. A longer averaging time (10 to 30 days)
would allow an easier accounting of potential emissions with the use of
coal analyses and coal supply information.
The second sampling location option is a point in the feed to the
boiler. This point could be in the raw-coal feed stream or in the fired-
coal feed stream. Analysis of a sample from the raw-coal feed stream
would provide somewhat higher potential sulfur emissions than would
analysis of an as-fired pulverized coal sample. The difference would be
the amount of pyritic sulfur and other sulfur compounds removed in the
pulverizing process. Analyses of the raw coal samples would also show
more variability than would analyses of the pulverized coal samples.
This could result in the requirement for a greater sampling frequency
for raw coal than for pulverized coal.
The primary advantage of on-site coal sampling is the direct accountability
of the sulfur emissions. This helps in establishing shorter averaging
times for the standard as there is better correlation between the analytical
data and the emissions produced. Longer averaging times may be established,
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as well, using daily (or other short term period) analytical values in
determining a long term average. The enforceabil ity of on-site coal
sampling is more direct than for other approaches as the boiler operator
is directly responsible for the analytical data.
A major disadvantage with the on-site, coal sampling approach is
the high cost of sampling and sample preparation. Automatic coal samples,
the most convenient and accurate method, are quite costly and require
frequent and regular maintenance. Coal sampling equipment that meet
ASTM sampling requirements cost from $20,000 to over $200,000 depending
on the degree of automatic control included. Less automatic devices are
more man-power intensive in the operation of the samples and in preparation
of the sample. Collection and preparation of daily samples can cost
from $15,000 to over $50,000 on an annual basis and analysis costs are
approximately $50 to $100 per sample.
Oil and Gas Sampling and Analytical Options
Oil and gas sampling and analytical procedures are not as expensive
or involved as for solid fuels. This is because the variability of
sulfur content in oils and gas is very low compared to the variability
in coal. The inherently lower concentrations of sulfur and the low
variability allows for the use of less frequent, manual sampling procedures
for oil and gaseous fuels. Grab samples from oil feed lines or from
storage tanks are sufficient for obtaining representative liquid samples.
Procedures for collecting representative samples of gaseous fuels are
ASTM D1145 and D1247 for natural gas and manufactured gas, respectively.
Analysis of fuel oil sulfur content can be done with several different
ASTM procedures: D240, D1551, D1552, or D3177. D240 should be used for
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determination of fuel oil high heating value. The ASTM methods for
analysis of fuel gases are D1072 for total sulfur and D1826 for calorific
value. Other ASTM procedures for these measurements are also available.
The frequency of sampling required for liquid and gaseous fuels is
dependent on the averaging time for the emission standard. Daily samples
from fuel feed lines can provide adequate data for one day or longer
averaging periods. Other sampling schemes or averaging determinations
would be necessary for shorter periods. The location of the sample
collection and analyses is limited to the feed lines for gaseous samples.
Liquid fuels could be analyzed by the supplier if bulk deliveries are
made to the user. However, the ease of sample collection and the low
frequency of collection make the requirement for on-site sampling feasible
and more desirable from the Agency's point of view.
A disadvantage of any fuel sampling and analysis method is that the
data produced are not sufficient for determining efficiency of flue gas
desulfurization (FGD) units. A measure of FGD emissions is required in
addition to fuel sulfur content data. Another disadvantage is that fuel
analyses data provide no information regarding NO emissions. Again, a
^
separate emission measurement is required.
D.2.1.4 Nitrogen Oxides
Reference Method 7
EPA Method 7 is the manual method for measurement of NO emissions
^
from stationary sources. Method 7 is a grab sampling, wet-chemical
collection procedure with a colorimetric analysis procedure. The analytical
method requires considerable laboratory time and skills to complete
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successfully. As with Method 6 measurements, Method 3 must be conducted
simultaneously with the Method 7 tests in order for the NO concentration
X
data to be converted to units of the standard. The manpower requirements
and costs for analyses are approximately the same as for Method 6.
Use of Method 7 for emission monitoring purposes would be limited
to the same type of use as discussed for Method 6. In turn, the advantages
and disadvantages are also similar.
The Agency has explored the use of alternative analytical methods
for Method 7. In particular, the Agency has studied the ion chromatographic
and the specific ion electrode procedure. Both of these procedures have
proven successful for combustion emission samples and the Agency is
preparing written procedures describing the use of these analytical
methods.
Continuous Emission Measurement
The requirements for continuous measurement of NO emissions are
X
essentially identical to those described for SOp continuous measurement
systems. Commercial instruments are available to measure oxides of
nitorgen as NO, or with an appropriate oxidation device, as N02. Either
type has been shown to achieve the performance specifications of Performance
Specification 2, Appendix B, 40 CFR Part 60. The only significant
difference between the requirements for NO measurement is that only the
rt
emission rate is determined.
D.2.2 Compliance Method Costs
The costs for performing the various types of compliance tests are
discussed in this section. These costs are current to September 1980,
when this evaluation was performed. The assumptions leading to the
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estimated cost are also presented. For clarity, the procedures are
grouped according to the type of measurement.
Manual Reference Procedures
The applicable procedures are Method 5 for particulates, Method 6
for S0?, and Method 7 for NO . Each procedure is labor intensive and
£ A
results in a short-term average result, usually consisting of triplicate
one hour runs. EPA Method 3 for diluent determination is necessary for
Methods 5, 6, and 7, and can be performed concurrently.
The cost estimate for performing the emission measurement includes
all the procedures necessary to report results in terms of the required
emission factor or removal efficiency.
The costs for performing these tests are presented in Table 1.
These costs are based on an average contracted effort with a labor
charge of $30/hour. Also included are average travel charges. If a
facility has in-house measurement capabilities, or more than one pollutant
is measured during a test, the costs will be reduced.
Automated Reference Procedures
The only automated reference method emission measurement that has
been demonstrated is for S02. The primary variable that affects the
cost of this procedure is the length of time that the sampler operated
before the absorbing solution is recovered and analyzed. The estimated
costs for this procedure are presented in Table 2. Both capital and
operating costs are necessary since an initial investment for dedicated
equipment is required. The operating costs are based on average maintenance
sample recovery, and analytical labor requirements at $30/hour.
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TABLE 1. MANUAL REFERENCE PROCEDURE TEST COSTS
(SEPTEMBER 1980 $)
Pollutant Measured Method Cost, $/test
Participates, outlet only 5 10,000
S02, outlet only 6 3,000
SOpj removal efficiency 6 5,000
NO. outlet only 7 5,000
/\
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TABLE 2. AUTOMATED S09 REFERENCE PROCEDURE COSTS
(SEPTEMBER ^1980 $)
Cost
Option Capital $ Operating $/yr
Emission rate measurement
1-day interval $2000 $29,000
3-day interval 2000 14,000
7-day interval 2000 7,000
Removal Efficiency
1-day interval 4000 58,000
3-day interval 4000 28,000
7-day interval 4000 14,000
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Estimates are presented for 1 day, 3 day, and 7 day sampling intervals;
and for emission rate and SO,, removal efficiency determinations. Finally,
the facility is assumed to have only one inlet duct and one outlet
emission duct. For systems with multiple inlets or outlets that require
measurements, the costs will be increased.
Continuous Emission Measurement
Continuous emission measurement procedures are applicable for S02
and NO . These emissions can be measured and reported continuously in
/\
terms of emission factors of nanograms/joule. The analyzer systems can
be tested and demonstrated to yield results equivalent (within a specified
accuracy) to the manual reference procedures.
The continuous emission measurement procedures require that the
pollutant and a diluent concentration be measured continually. In some
cases, it is also necessary to perform additional tests, such as monitoring
dew point temperature to determine moisture content of the sample.
Since analyzers are not primary standards for SCL or NO , it is necessary
that comparability or relative accuracy tests be performed initially.
To assure data quality, regular systems calibrations and relative accuracy
checks are necessary.
The costs for continuous emission measurement systems for SO,, and
NO are presented in Table 3. The total costs are divided into capital,
^
installation, and operating charges. The estimates are based on a
boiler equipped with an FGD system with one inlet duct and one outlet
duct; with a physical layout that allows all system components to be
installed within about a 100 foot radius; that no system components are
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TABLE 3. SOX/NOX CONTINUOUS EMISSION MEASUREMENT PROCEDURE COSTS
(SEPTEMBER 1980)
Initial Costs
Operating Costs
Option
Outlet Emission
FGD Efficiency
NO Outlet
Emission
Capital
20,000
30,000
20,000
Installation
10,000
14,000
10,000
Initial
Performance
Test
10,000
14,000
10,000
Total
Initial
Capita 1,$
40,000
58,000
40,000
Routine Operation
Labor Materials
10,000
20,000
10,000
1,000
2,000
1,000
Quality
Assurance
Test
20,000
40,000
20,000
Total
Operating
$/Year
31,000
62,000
31,000
-------
shared, and that an automatic data reduction system dedicated to emission
reporting is necessary. The actual costs will vary from site to site
depending on the measurement system chosen, the degree of automation,
and the amount of labor necessary to keep the systems operational. The
costs in Table 3 are median estimates and cannot be used as universally
precise values.
Fuel Sampling Procedures
Fuel sampling for a compliance technique is only applicable to StL
determinations. Also, fuel sampling can only measure uncontrolled
emissions and cannot indicate emissions after a control device. However,
fuel analysis can be used to determine inlet SC^ rates for use with
outlet measurements for SCL removal efficiency data.
Fuel sampling can be by automatic or manual techniques. For a
result with the least amount of uncertainty, a continuous automatic
sampler is required. If an automatic sampler is not used, the primary
variable that determines annual cost is the frequency of sampling. The
costs for various sampling and analytical options are presented in
Table 4.
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TABLE 4. FUEL SAMPLING PROCEDURE COSTS
(SEPTEMBER 1980 $)
Sampling
Option Capital Labor Analysis I/Sample
Coal Fired
Automatic Sampler $20,000-$200,000 Nil $50-100
Manual samples, $/sample Nil $300-$1000 $50-100
Oil/Gas Fuel
Manual Sampling $/Sample Nil $100-$!000 $50-100
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D.3 CONTINUOUS MONITORING
The purpose of continuous monitoring is to provide qualitative or
semi-quantitative measures of continued proper operation and maintenance
when short term manual tests are used to determine compliance with an
applicable regulation. The most significant difference between continuous
emission measurement and continuous monitoring is that for monitoring
purposes, the data do not have to be accurately and precisely correlated
to true emission levels. In many cases, simpler and less expensive
instrumentation systems can be used. For example, when EPA Method 5 is
used as the measure of compliance with a particulate emission limitation,
the average test duration would be about three hours. Since it is
impractical to perform manual tests continually, a transmissometer can
be specified as a procedure to obtain continuous operation information.
Since the mass emission rate and opacity of the emission are generally
related, an increase in opacity usually indicates an increase in particulate
emissions. However, since a general, precise correlation between mass
emission rate and opacity does not exist, the results of continuous
opacity measurement cannot generally be used to enforce a mass emission
limitation. In those cases where a transmissometer cannot be used for
monitoring (e.g., a location where condensed water vapor is present), A
surrogate operating parameter can be monitored. An example would be
monitoring of the pressure drop across a wet venturi scrubber. The
available procedures for continuous monitoring are presented below.
D.3.1 Particulates/Opacity
The most direct monitoring procedure for particulate emissions is
by measuring opacity. The utility of transmissometers for monitoring
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the opacity of emissions from combustion sources has been demonstrated.
Transmissometer systems meeting the design and performance criteria of
Performance Specification 1: "Performance Specifications and Specification
Test Procedures for Transmissometer Systems for Continuous Measurement
of the Opacity of Stack Emissions," (40 CFR 60, Appendix B) are commercially
available. These systems are applicable for use on industrial boilers.
A recent (fall 1980) survey of several instrumentation vendors
indicates that the capital cost for an opacity monitoring system is
between $10,000 and $15,000. This cost is for a single unit with an
analog data recorder. Digital data handling systems which can handle up
to four opacity monitoring systems are available for an additional
$10,000 and programable digital systems for handling multiple monitors
on a single source (i.e., S09, NO ,>opacity) are available for $25,000 -
L, X
$30,000 including software.
Installation and start-up costs for a new source where ports and
access platforms are installed during construction are estimated at
under $5,000. The cost of conducting the performance test required in
Specification 1 is estimated at between $3,000 and $5,000 per instrument
while maintenance costs are estimated at $3,000 to $10,000 per year.
For the cases where instrumental measurement of opacity is not
technically possible or economically feasible, it may be acceptable to
measure a process operation parameter. Particulate scrubbers are an
example of a case where opacity measurement is usually not technically
possible due to uncombined water interferences. Gas phase pressure
differential and scrubber liquid flow have been specified in previous
regulations as indicators of proper maintenance and operation of these
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units. However, for electrostatic precipitators, fabric filters, or
high efficiency mechanical separators, there may not be a single operating
parameter that is a reliable indicator of proper operation.
D.3.2 Sulfur Dioxide
The choice of a monitoring approach for sulfur dioxide depends on
the type of regulation and the control strategy used to achieve that
requirement. If a regulation is in terms of an emission limit, an S02
analyzer can be used to measure the concentration in the flue gases.
Analyzer systems capable of meeting the performance criteria of Performance
Specification 2, Appendix B 40 CFR 60 are commercially available. If an
emission regulation is achieved by using low sulfur fuels, routine
sampling and analysis can also be used as an operations monitoring
technique. For the case where a removal efficiency is specified, measurements
are necessary before and after a control device. An analyzer is necessary
after control; inlet data may be obtained either by an analyzer or by
fuel monitoring. There may be some cases where an operating parameter
could be used as an indicator of operations. At some of the industrial
boiler facilities equipped with flue gas desulfurization systems tested
by EPA, the pH of the scrubbing liquid was a good qualitative indicator
of operation at design removal efficiencies. However, the usefulness of
monitoring this parameter could vary from system to system and the
correlation of pH to removal efficiency would be site specific.
The cost of an instrument system for monitoring SQ^ and a diluent
at a single location is estimated to range from $20,000 to $30,000.
Installation costs are estimated to be $10,000. Annual operating and
maintenance costs, at one-half hour per day at $30/hour are $5,500.
D-26
-------
This system would include an analog chart recorder. Systems for automatic
data handling are commercially available with costs ranging from $10,000
to $30,000. For multiple locations, the costs can be assumed additive;
however, many parts of the overall system could be shared in some designs,
resulting in reduced overall cost. Each system would require an initial
performance specification test, estimated at $10,000 per measurement
location.
Fuel analysis costs have been discussed in Section D.2.2.
D.3.3 Oxides of Nitrogen
The continuous monitoring of nitrogen oxides can be accomplished
using instrumental analyzers. Commercial systems that can meet the
requirements of Performance Specification 2, Appendix B 40 CFR 60 are
available. Instrumental measurements are usually the only way to obtain
monitoring information for NO since there is not a simple relationship
A
between emission rates and operating parameters (e.g., excess air or
combustion temperature).
Instrument systems for NO monitoring are similar to those required
A
for S02 monitoring, and the capital and operating costs are essentially
the same.
n-27
-------
APPENDIX E
EMERGING TECHNOLOGY MODEL BOILER IMPACT ANALYSIS
Chapters 6-8 presented a model boiler analysis of a variety of
emission control techniques applied to different sizes and types of
industrial boilers. This appendix is included as a supplement to these
chapters. It provides a separate model boiler impact analysis for
selected "emerging control technologies". The technologies selected for
evaluation are:
• Selective Catalytic Reduction (SCR)
• Low-Btu Gasification (LBG)
• Coal/Limestone Pellets (CLP)
• Fluidized Bed Combustion (FBC)
These technologies, while generally not applied to commercial scale
industrial boilers, offer potential for significant near-term penetration
into the industrial boiler market. Chapter 4 provides process descriptions
and a discussion of the status of development of each of these technologies
Several Individual Technology Assessment Reports (ITAR's) have been
prepared and form the basis for the majority of the data presented in
123
this Appendix. ' ' Since the emerging technologies are still, by
definition, under development, the data is inherently less accurate than
that presented in Chapters 6-8. For this reason, comparisons between
Chapters 6-8 and this appendix should be made with caution.
Except for LBG, application of each emerging technology results in
the reduction of either S09, PM, or NO (LBG reduces all three major
L- X
emission species relative to conventional combustion of coal). Except
as noted, the impacts presented in this appendix are associated with the
emerging technology only and do not include impacts associated with the
use of other control techniques used to control other emission species.
The organization of this appendix is analagous to the organization
of Chapters 6-8. Section E.I defines the model boilers in terms of
E-l
-------
boiler specifications, control device specifications, and achievable
emission levels. Section E.2 presents a brief analysis of the environ-
mental and energy impacts. Finally, Section E.3 reviews the costs
associated with the emerging technologies.
E.I EMERGING TECHNOLOGY MODEL BOILERS
Table E-l presents the five emerging technology model boilers
examined in this appendix. Both uncontrolled and controlled emissions
are indicated. As noted in Table E-l, the LBG, CLP, and FBC technologies
use control methods involving the boiler and/or fuel preparation
system rather than a flue gas treatment device. In these cases, an
uncontrolled high sulfur coal-fired spreader stoker is assumed represen-
tative of uncontrolled emissions.
Two oil-fired units are included to assess use of selective catalytic
reduction (SCR) NO controls. The parallel flow system is applied to a
/\
residual oil-fired unit where particulate matter might plug a fixed bed
system. The distillate oil-fired unit emits very little particulate
matter and is thus suitable for the fixed bed system. The remaining
three model boilers input coal as the raw fuel. In low-Btu gasification
(LBG) the coal is gasified at the boiler site prior to combustion in a
gas-fired boiler, resulting in reductions in all three major emission
species. The coal/limestone pellet (CLP) S02 control technique involves
firing a pelletized coal and limestone mixture in a conventional spreader
stoker. Fluidized bed combustion (FBC) also uses limestone as an S0?
sorbent. However, the coal and limestone are introduced separately with
firing occurring in a bed fluidized by forced air.
Table E-2 presents the model boiler and control device specifications
used in this analysis. As noted, the SCR systems are applied to boilers
identical to the standard oil-fired boilers defined in Chapter 6. The
LBG technology uses a modified natural gas-fired boiler to fire the low-
Btu gas produced in the gasifier. The modifications are relatively
minor, but include a derating of the boiler due to the lower flame
intensities associated with combustion of low-Btu gas. The CLP technology
E-2
-------
TABLE E-l. EMERGING TECHNOLOGY MODEL BOILERS
I
GO
Emission Levels
Model*
Boiler
RES-150-SCR/PF
DIS-150-SCR/FB
HSC-150-LBG
HSC-150-CLP
HSC-150-FBC
Boiler
Capacity
c
MW (10°Btu/hr)
44 (150)
44 (150)
44 (I50)d
44 (150)
44 (150)
Emission(s)
Controlled
NOX
NOX
NO
SO,
PM^
so2
so*
ng/J
k
Uncontrolled
171 (0.400)
103 (0.240)
273 (0.630)
2450 (5.70)
2500 (5.82)
2450 (5.70)
2450 (5.70)
(lb/106Btu)
Controlled
17.1 (0.040)
10.3 (0.024)
86.0 (0.200)
150 (0.500)
13.0 (0.030)
1104 (2.56)
245 (0.570)
Emission
Reduction
(percent)
90.0
90.0
68.3
91.2
99.5
55.0
90.0
RES = residual oil-fired; DIS = distillate oil-fired; LBG = low-Btu gas-fired; HSC = high sulfur coal fired;
SCR/PF = selective catalytic reduction, parallel flow; SCR/FB = selective catalytic reduction, fixed bed;
CLP = coal-limestone pellets; FBC = fluidized bed combustion.
For oil-fired boilers, uncontrolled emissions are actual emissions prior to SCR control. For other boilers, a spreader
stoker is assumed representative of uncontrolled emissions.
CFBC boilers typically achieve a slight (less than 20%) NO reduction compared to a conventional spreader stoker, however,
available data is inconclusive (see Chapter 4).
Heat input to low-Btu gas-fired boiler (not heat input to gasifier).
-------
TABLE E-2. SPECIFICATIONS FOR EMERGING TECHNOLOGY CONTROL TECHNIQUES
Selective Catalytic Reduction/Parallel Flow (SCR/PF)
Reactor Configuration
Catalyst
Catalyst Shape
NH3:NO Ratio
Reactof Temp.
Gas Velocity
Bed Depth
Pressure Drop
Parallel Flow
VpOn or Fe-Cr on
alumina substrate
Honeycomb or parallel
plate
1:1 (molar)
350-400°C (688-788°F)
2-10 m/sec (6.6-33 ft/sec)
1-6 m (3.3-30 feet)
0.03-0.16 kPa (0.12-0.63
in H20)
Boiler Specifications as per Table 6-5 (RES-150)
Selective Catalytic Reduction/Fixed Bed (SCR/FB)
Reactor Configuration
Catalyst
Catalyst Shape
NH3:NO Ratio
Reactor Temp
Gas Velocity
Bed Depth
Pressure Drop
Fixed Packed Bed
VpOr or Fe-Cr on
afumina substrate
Pellets, 0.33 cm
(0.13 in) diameter
1:1 (molar)
350-400°C (688-788°F)
1-1.5 m/s (3.3-4.9 ft/sec)
0.2-0.6 m (0.66-2.0 ft)
0.040-0.080 kPa (0.16-0.32
in. H20)
Boiler Specifications as per Table 6-4 (DIS-150)
Low-Btu Gasification (LBG)
Gasifier Type
Acid Gas Removal
Coal Feed
System Components
Wellman-Galusha
Stretford
High Sulfur Coal
(see Table 6-8)
Coal preparation, gasifier,
quench towers, ESP, Stretford
HpS removal unit, Claus sulfur
recovery unit
E-4
-------
TABLE E-2. (CONTINUED)
Low-Btu Gasification (LEG) (continued)
Gas Composition N9 - 46%
CO - 26%
H« - 13%
C09 - 3%
CH, - 2.6%
H?S - 0.7% (before Stretford)
Gas Heating Value 5.62 MJ/nT (151 Btu/ftJ)
Capacity Factor 0.6
Boiler is similar to NG-150 presented in Table 6-3
with modifications to burn low-Btu gas.
Coal-Limestone Pellets (CLP)
Boiler Type Spreader Stoker,-
Thermal Input 44 MW (150 x 10DBtu/hr)
Boiler Efficiency 81% (estimated)
Fuel Coal/Limestone Pellets
Coal Type High Sulfur Coal
(see Table 6-8)
Sorbent Type Limestone (CaCO?)
Ca:S Ratio 3.5:1 (molar)
Capacity Factor 0.6
Fluidized Bed Combustion (FBC)
Boiler Type Atmospheric FBC with once-through
sorbent processing
Thermal Input 44 MW (150 x 10bBtu/hr)
Boiler Efficiency 82.8%
Bed Temperature 843°C (1550°F)
Capacity Factor 0.6
Fuel High Sulfur Coal
(see Table 6-8)
Sorbent Limestone (CaCO^ with average
particle size of 0.5 mm)
Ca:S Ratio 3.3:1 (molar)
Capacity Factor 0.6
E-5
-------
uses a modified spreader stoker. Very little data is presently available
to assess the full extent of the modifications necessary to adapt a
spreader stoker to CLP firing. Some derating of the unit is anticipated
as well as modifications to the fuel feed and bottom ash removal mechanisms.
The FBC technology involves a radically different boiler design compared
to conventional boilers.
A uniform 44 MW (150 x 106Btu/hr) capacity is specified for all the
emerging technology model boilers. Use of this uniform capacity allows
direct comparisons of costs and impacts between technologies. However,
this is not meant to imply that these technologies are suitable to this
size of industrial boiler only. Chapter 4 and the ITAR's review the
applicability of emerging technologies to other sizes of boilers.
E.2 ENVIRONMENTAL AND ENERGY IMPACTS OF EMERGING TECHNOLOGIES
This section presents a brief review of the air, liquid waste,
solid waste, and energy impacts associated with the emerging technologies
defined in Section E.I. As mentioned earlier, this information is, in
part, based on preliminary studies of undeveloped technologies. Impacts
are likely to change somewhat as the technologies mature.
E.2.1 Air Impacts
The annual air pollution impacts for each model boiler are presented
in Table E-3. Annual emissions are reported for both uncontrolled and
controlled boilers designed to meet emission limits detailed in Table
E.I. Annual emissions are reported in Mg/yr (tons/yr) for the controlled
and uncontrolled cases. The percent reduction values shown represent
the reduction achieved over a conventional uncontrolled boiler. For the
oil-fired boilers, the uncontrolled case is simply an oil-fired boiler
without SCR control. For the boiler systems which use coal, the uncon-
rolled case is a conventional high sulfur coal-fired spreader stoker
without emission controls.
E.2.2 Liquid Waste Impacts
There are no liquid streams associated with the SCR systems examined;
however, there is one potential source of water pollution. In some
E-6
-------
TABLE E-3. EMERGING TECHNOLOGY MODEL BOILER ANNUAL EMISSIONS
m
i
Model9
Boiler
RES-150-SCR/PF
DIS-150-SCR/FB
HSC-150-LBG
HSC-150-CLP
HSC-150-FBC
Emission(s)
Controlled
NOX
NOX
NOY
SO,
m*
so2
so2
Annual Emissions
Mg/yr (tons/yr)
Uncontrolled
131 (145)
78.7(86.7}
225 (248)
2040 (2247)
2083 (2294)
2040 (2247)
2040 (2247)
Controlled
13.1 (14.5)
7.87 (8.67)
71.6 (78.8\d
179 (197)°.
10.7 (11.8)a
916 (1009)
204 (225)
Emission
Reduction
(percent)
90.0
90.0
68.3
91.2
99.5
55.0
90.0
Model boilers and abbreviations defined in Table E-l.
For oil-fired boilers, uncontrolled emissions are actual emissions prior to SCR control. For other
boilers, a spreader stoker is assumed representative of uncontrolled emissions.
CFBC boilers typically achieve a slight (less than 20%) NO reduction compared to a conventional
spreader stoker. However, available data is inconclusive (see Chapter 4).
The controlled emissions shown are those resulting from combustion of low-Btu gas. The gasification
process emits small amounts of NO , SO^, and PM. In addition, other emission species (organics, CO,
NH~, HCN, H0S, and COS) are also emitted in small amounts.
-------
Japanese installations, NH4HS04 deposits (see Chapter 4) are removed
from the air preheater by water washing. The blowdown from this operation
will contain both ammonium and sulfate ions which, if not treated,
present a water pollution source. Since the amount of NH.HSO, and water
are not known, it is not possible to estimate the concentration or flow
of this potential source.
There are no waste water streams directly associated with the FBC
or CLP model boilers. Disposal of the solid waste from these boilers is
expected to occur by landfill ing. A secondary water pollution impact
may exist at sites where rainfall runoff causes percolation and leaching
of materials from the spent and unspent sorbent.
In a coal gasification facility, the specific sources which generate
wastewaters will determine the type of contaminants that are present in
those streams. Potential water effluents from.a Wellman-Galusha low-Btu
gasification facility include:
• coal storage runoff,
• ash sluicing water,
• process condensate, and
• stretford process blowdown.
The coal storage runoff stream principally contains dissolved
metals and inorganics that have been leached from coal in uncovered
storage piles or bins. The quantity and composition of this stream are
c
highly dependent on the site of the gasification facility.
Ash sluice water is used to aid the removal of ash from the gasifier.
This stream principally contains ash, dissolved metals, and inorganics
that have been leached from the ash, but also contains some organic
compounds. The composition of the ash sluice water depends, of course,
on the characteristics of the gasifier ash. The only data presently
available on ash sluice water composition are for gasifying anthracite
coal. Those data indicate few compounds are present in hazardous concen-
trations. Generalizing these results to other coal types is not warranted.
E-8
-------
In cooling the raw low-Btu gas to the operating temperature and
pressures of the sulfur removal processes (44°C or 137°F for Stretford
processes and essentially atmospheric pressure), water is condensed and
subsequently removed from the gas quenching and cooling system. This
condensate contains many of the constituents of the low-Btu gas, including
nitrogen species (such as NH. and CN~), particulates (which are relatively
rich in trace elements), organics (including phenols, thiols, and
polynuclear aromatic hydrocarbons), and dissolved gases. Numerical
values for the effluent generated by the process condensate stream are
reported in the synthetic fuels ITAR for various control levels. For
the LBG model boiler in this report, the value is 1217 Mg/yr (1340
tons/yr). This value represents the quantity of condensate sent to an
on-site evaporator. Residual wastes after evaporation may be as little
as 5 percent of the value reported above.
The principal pollutants found in the Stretford blowdown are thiosul-
fate and thiocyanate. Specific standards for the discharge of these
pollutants do not exist. The effluent generated by the blowdown stream
o
is estimated to be 500 Mg/yr (551 ton/yr).
E.2.3 Solid Waste Impacts
Solid waste impacts for all emerging technology model boilers are
summarized in Table E-4. All values were taken directly from the ITAR's
with the exception of the coal/limestone pellet (CLP) technology. Solid
waste impacts for CLP were determined partially on the basis of documenta-
tion supplied from the fluidized bed combustion (FBC) ITAR.11 The
assumptions used are presented at the end of this subsection where CLP
solid waste is discussed.
The only solid waste associated with the SCR systems is the spent
catalyst. The life of SCR catalysts has been estimated to be from 1-2
12
years. However, no commercial SCR units have operated long enough to
require catalyst replacement, therefore, estimates of solid waste genera-
tion are not reported. In addition, the catalysts used are expensive,
making regeneration an attractive alternative to conventional disposal
techniques. Regeneration would minimize the solid waste impacts of SCR.
E-9
-------
TABLE E-4. EMERGING TECHNOLOGY MODEL BOILER
ANNUAL SOLID WASTE PRODUCTION
9,10
I
o
Model9
Boiler
RES-150-SCR/PF
DIS-150-SCR/FB
HSC-150-LBG
HSC-150-CLP
HSC-150-FBC
Emission(s)
Controlled
NOX
NOX
NOX,S02,PM
so2
so2
Source of
Solid Waste
SCR reactor
SCR reactor
Gasifier
Cyclone
Acid gas removal
Boiler and
final PM
control
Boiler and
final PM
control
Type of
Solid Waste
Spent catalyst •
Spent catalyst
Bottom ash
Dust
Sulfur cake
Bottom ash and
fly ash
Bottom ash and
fly ash
Annual Solid
Waste Production
Mg/yr (tons/yr)
5441
305
2746
13104
13221
b
b
(5992)
(336)
(3024)
(14431)
(14538)
Model boilers and abbreviations defined in Table E-l.
'insufficient data to estimate catalyst replacement rates.
•»
'Assuming some type of high efficiency final PM control device (uncontrolled PM emissions are unlikely
to be acceptable in most instances).
-------
Solid wastes generated by the LBG system include gasifier ash,
cyclone dust, and sulfur cake. Solid waste production is considerably
higher for the gasification and purification system than for an uncontrolled
coal-fired boiler. The quantity of gasifier ash produced can be as much
as 700 percent greater than the bottom ash from a coal-fired boiler.
This is because of the higher coal throughput required for gasification
to overcome the coal loss associated with the LBG process, and because
some of the coal ash evolves as fly ash during combustion while most of
13
it appears as gasifier ash in gasification. Cyclone dust and sulfur
cake are additional solid waste products from the gasification system
not produced from uncontrolled coal-fired boilers.
The gasifier ash and sulfur cake (and possibly the cyclone dust)
can be disposed of by landfill, with steps taken to prevent surface and
ground water contamination from water runoff and leachate. Sulfur
produced by the Stretford process is a wet cake containing about 50
percent water and 4 percent total dissolved solids. This cake contains
chemicals from the Stretford solution that may be Teachable from the
sulfur cake. The concentration of these chemicals in the cake depends
on the degree and effectiveness of cake washing. This sulfur cake could
be autoclaved and further purified to produce pure molten sulfur suitable
for sale, but the small quantities produced in the systems considered in
this report would probably make this purification economically unattractive.
The cyclone dust consists mostly of carbon which can be incinerated
rather than being landfilled. In fact, under current regulations,
landfill of the dust may not be allowed if it classified as a hazardous
"ignitable" waste.15
The major adverse environmental impact of fluidized-bed combustion
is expected to be the solid waste which is produces. Solid residue from
the fluidized-bed process consists of a mixture of spent bed material
(largely calcined and sulfated sorbent), bottom ash and fly ash collected
in the particulate matter control devices. The amount of solid waste
produced is a function of the fuel and sorbent characteristics. The
E-ll
-------
solid waste loading reported in Table E-4 constitutes the total waste
produced by the system; about 85 to 95 percent of the waste will be
withdrawn as spent bed material, assuming that the material collected in
the primary cyclone is recycled to the bed. The remaining 5 to 15
percent elutriates from the bed, passes through the primary cyclone, and
is collected by a final particulate control device. Solid waste generated
by the FBC system with a fabric filter is 300 percent higher than that
from a coal-fired spreader stoker using a fabric filter for fly ash
collection.
Total solid waste production for CLP firing was calculated based on
a pellet Ca:S molar ratio of 3.5:1. In addition, it was assumed that
the limestone used was 90 percent CaCO^ and 10 percent inert material
17
and that 95 percent of the CaC03 is calcined in the bed.
E.2.4 Energy Impact
Table E-5 provides data on energy usage for the emerging technology
model boilers examined. Energy required to operate the emerging technolo-
gies may be in one of several forms. For SCR systems, electricity is
used to drive fan motors and to pump ammonia for injection systems. For
gasification systems, additional coal input is required to overcome
substantial conversion losses in the gasification process. In addition,
electricity is required for fans and pumps in the gasifier and emission
control system. Steam is needed in the gasifier itself; this steam
could be supplied from the gas-fired boiler which the gasifier feeds.
For FBC boilers, the overall boiler efficiency is slightly higher than
for conventional stoker boilers; thus, the coal feed for a given steam
output is actually reduced. Electricity is required, however, to supply
air for bed fluidization and to handle increased solids input and outputs
from the boiler. The use of CLP incurs a slight energy penalty due to
reduced boiler efficiency. At present, data is insufficient to estimate
the magnitude of this penalty.
The gasification of coal to produce a low-Btu gas incurs a significant
energy penalty. For the Wellman-Galusha/Stretford system used in the
E-12
-------
TABLE E-5. EMERGING TECHNOLOGY MODEL BOILER ENERGY USE18'19'20
m
i
CO
Energy Use
Model Emission(s)
Boiler Controlled
RES-150-SCR/PF N0¥
A
DIS-150-SCR/FB NOV
A
HSC-150-LBG NOX,S02,PM
HSC-150-CLP S02
HSC-150-FBCC'd S02
Type
Electricity
Steam
Total
Electricity
Steam
Total
Coal Feed
Electricity
Steam
Total
Amount
MW (106Btu/hr)
0.134
0.034
0.168
0.121
0.0706
0.192
18.3
2.5
0.15
20.9
(0.458)
(0.115)
(0.573)
(0.414)
(0.241)
(0.655)
(62.5)
(8.4)
(0.5)
(71.4)
Percent of
Boiler Input
0.31
0.08
0.38
0.28
0.16
0.44
41.6
5.6
0.3
47.5
Insufficient Data
Coal Feed
Electricity
Total
-0.96
0.47
-0.49
(-3.28)
(1.60)
(-1.68)
-2.2
1.1
-1.1
Model boilers and abbreviations defined in Table E-l.
Negative numbers indicate net decrease in energy use.
°For FBC control technique, energy use shown is net increase or decrease compared to conventional
spreader stoker.
Energy use of final PM control device not included.
-------
model boiler analysis, an energy penalty of approximately 48 percent is
incurred to gasify high sulfur coal. The major contributor to the
energy consumed by the low-Btu gasification system is the gasification
inefficiency. This includes both conversion losses and the energy
content of the by-product tars and oils. Use of the by-products' energy
would lower the energy penalties presented by about 20 percentage points.
E.3 COSTS OF EMERGING TECHNOLOGY CONTROL TECHNIQUES
This section presents an analysis of the costs associated with
using emerging technology .emission control techniques. This cost analysis
is intended to provide a comparative analysis to allow the general
assessment of the costs of using the emerging technologies. Since
emerging technologies are, by definition, still under development, these
costs should be considered as approximate and are likely to change
considerably as the technologies mature.
For the most part, the costs presented are developed from costs
presented in the Individual Technology Assessment Reports (ITAR's). For
coal/limestone pellets, no such report is available. In this case,
costs were developed by integrating data from the coal/limestone pellet
22
supplier with the engineering data from Chapter 4.
Both capital and annualized cost impacts are presented for each
emerging technology (in June 1978 dollars). These costs are developed
for both boiler and emission control(s) systems. The cost bases (i.e.
fuel costs, labor rates, interest rate, etc.) are essentially unchanged
from those used to cost the model boilers in Chapter 8.
E.3.1 Analysis of Capital Cost Impacts
Table E-6 presents the capital costs for the five emerging technology
model boilers. Of immediate note is the disparity between capital costs
of oil- and coal-fired boilers. In general, oil-fired units cost have
significantly lower capital costs.
The capital costs of the residual oil- and distillate oil-fired
emerging technology model boilers are virtually equivalent. The higher
costs of the parallel flow SCR system compared to the fixed bed system
E-14
-------
TABLE E-6. CAPITAL COSTS OF EMERGING TECHNOLOGY
MODEL BOILERS ($1978)22
rn
i
_j
tn
Model3
Boiler
RES-150-SCR/PF
DIS-150-SCR/FB
HSC-150-LBG
HSC-150-CLP
HSC-150-FBC
Emission(s)
Controlled
NOX
NOX
NOX
so;
PM^
S02
S0x
Emission
Reduction(s)
(percent)
90.0
90.0
68.3
91.2
99.5
55.0
90.0
Capital Costs ($1000)
Boiler
Cost
2735
2927
1860d
8971
9921
Control
Cost
502
311
10911s
w/boiler
w/boiler
Total
Cost
3244
3238
12771
8971
9921
Model boilers and abbreviations defined in Table E-l.
For oil-fired boilers (RES-150, DIS-150) the reductions listed are actual reductions achieved by the
SCR control device. Other model boilers use control techniques which are inherent in the boiler or
the fuel preparation prior to the boiler. For these cases, emission reductions are relative to an
uncontrolled spreader stoker firing high sulfur coal.
«
FBC boilers typically achieve a slight (less than 20%) NO reduction compared to an uncontrolled
spreader stoker, however, available data is inconclusive fsee Chapter 4).
Low-Btu gas-fired boiler.
eGasifier and emission controls required for qasifier.
-------
are offset by the higher boiler capital cost for the uncontrolled distil-
late-fired unit compared to the residual-fired unit (primarily due to
higher working capital costs for distillate fuel). The most capital
intensive emerging technology is LBG. For the coal-fired boilers, the
total capital cost of the boiler and gasifier system is considerably
more expensive than all other control technologies examined. Most of
the gasifier cost (85 percent) is associated with the extensive air and
water pollution controls on the gasifier itself.
E.3.2 Analysis of Annualized Cost Impacts
Table E-7 presents the annualized costs for the five emerging
technology model boilers. Figure E-l illustrates the "normalized" total
annualized costs of boilers and controls. The normalized cost is calcu-
lated by dividing the annualized cost by the total annual heat input to
the boiler. Any comparisons between these costs should keep in mind the
different emissions species under control and the relative levels. LBG,
for example, is the most expensive technique examined. However, it is
the only technology examined which achieves comparatively large decreases
in all three major emission species.
For annualized as well as capital cost, the LBG model boiler is the
most expensive model boiler examined. In fact, the normalized annual
cost of the LBG model boiler exceeds the costs of all coal-fired model
boilers examined in Chapter 8.
The FBC and CLP technology costs are roughly equivalent. The CLP
technology has a small three percent cost advantage. However, it should
be noted that the CLP technology is considerably less advanced than the
FBC technology. Further experience with CLP-firing may indicate lower
achievable S02 removal and/or higher pelletizing costs.
E-16
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TABLE E-7. ANNUALIZED COSTS OF EMERGING TECHNOLOGY MODEL BOILERS ($1978)
22
Annuali zed Cost ($1000/yr)
Model9
Boiler
RES-150-SCR/PF
DIS-150-SCR/FB
HSC-150-LBG
HSC-150-CLP
HSC-150-FBC
Emission(s)
Controlled
N0x
N0x
NO
so;
PM^
so2
so2
Emission
Reduction(s)
(percent)
90.0
90.0
68.3
91.2
99.5
55.0
90. Oc
Boiler
Cost
4368
5260
6598d
4436
4592
Control
Cost
226
208
5718e
w/boiler
w/boiler
Total
Cost
4626
5468
6598
4436
4592
Normalized
Total
Cost
6.41
7.57
8.36
5.63
5.82
Model boilers and abbreviations defined in Table E-l.
For oil-fired boilers (RES-150, DIS-150) the reductions listed are actual reductions achieved by the
SCR control device. Other model boilers use control techniques which are inherent in the boiler or
the fuel preparation prior to the boiler. For these cases, emission reductions are relative to an
uncontrolled spreader stoker firing high sulfur coal.
CFBC boilers typically effect a slight (less than 20%) NO reduction compared to an uncontrolled
spreader stoker, however, available data is inconclusive (see Chapter 4).
Includes cost of gasification.
eCost of gasification process and emission controls.
Total annualized cost divided by annual heat input ($/10 Btu).
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8
o •—»
o +->
Z5
•— Q.
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E.4 REFERENCES
1. Jones, G.D. and K.L. Johnson. (Radian Corporation). Technology
Assessment Report for Industrial Boiler Application: NO Flue Gas
Treatment. (Prepared for U.S. Environmental Protection Agency.)
Research Triangle Park, North Carolina. Publication No. EPA-600/7-
79-178g. December 1979.
2. Thomas, W.C. (Radian Corporation). Technology Assessment Report
for Industrial Boiler Applications: Synthetic Fuels. (Prepared
for U.S. Environmental Protection Agency.) Research Triangle Park,
North Carolina. Publication No. EPA-600/7-79-178d. November 1979.
3. Young, C.W., et al. (GCA Corporation). Technology Assessment
Report for Industrial Boiler Applications: Fluidized-Bed Combustion.
(Prepared for U.S. Environmental Protection Agency). Research
Triangle Park, North Carolina. Publication No. EPA-600/7-79-178e.
November 1979.
4. Reference 2, p. 6-8.
5. Reference 2, pp. 6-14, 6-15.
6. Reference 2, p. 6-15.
7. Reference 2, p. 6-9.
8. Reference 2, p. 6-9.
9. Reference 2, p. 6-20.
10. Reference 3, p. 364.
11. Reference 3, pp. 360-366.
12. Reference 1, p. 6-24.
13. Reference 2, pp. 6-19, 6-21.
14. Reference 2, p. 6-22.
15. Reference 2, p. 6-23.
16. Reference 3, p. 361.
17. Piccot, S.P. "Solid Waste and Fuel Feed Calculations for Coal/Limestone
Pellet Technology Model Boiler". Memo to Industrial Boiler File.
Radian Corporation.
18. Reference 1, pp. 5-17, 5-18.
E-19
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E.4 References (continued)
19. Reference 2, p. 5-7.
20. Reference 3, p. 317.
21. Reference 2, p. 5-9.
22. Jennings, M.S. "Cost Calculations for Emerging Technology Model
Boilers". Memo to Industrial Boiler File. Radian Corporation.
Durham, N.C. May 1981.
E-20
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