Southern Research Institute/US EPA
April 2008
EPA Contract No. EP-C-04-056
Work Assignment No. 2-8-101
April 2008
Environmental and Sustainable Technology
Evaluation - Biomass Co-firing in Industrial
Boilers - University of Iowa
Prepared by:
Southern Research Institute
Under Subcontract to ERG
U.S. Environmental Protection Agency
Office of Research and Development - Environmental Technology
Verification Program
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Southern Research Institute/US EPA
April 2008
EPA REVIEW NOTICE
This report has been peer and administratively reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Mention of trade names or commercial products does not constitute endorsement or
recommendation for use.
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Southern Research Institute/US EPA
April 2008
THE ENVIRONMENTAL TECHNOLOGY VERIFICATION PROGRAM
Environmental and Sustainable Technology Evaluation (ESTE)
&EPA
U.S. Environmental Protection Agency SOUTHERN RESEARCH
INSTITUTE
ESTE Joint Verification Statement
TECHNOLOGY TYPE: Biomass Co-firing
APPLICATION: Industrial Boilers
TECHNOLOGY NAME: Renewafuels Palletized Wood Fuel
COMPANY: Renewafuels, LLC
ADDRESS' 13420 Courthouse Boulevard
Rosemount, MN 55068
The U.S. Environmental Protection Agency (EPA) has created the Environmental Technology
Verification (ETV) program to facilitate the deployment of innovative or improved environmental
technologies through performance verification and dissemination of information. The goal of the ETV
program is to further environmental protection by accelerating the acceptance and use of improved and
cost-effective technologies. ETV seeks to achieve this goal by providing high-quality, peer-reviewed data
on technology performance to those involved in the purchase, design, distribution, financing, permitting,
and use of environmental technologies. This verification was conducted under the Environmental and
Sustainable Technology Evaluation (ESTE) program, a component of ETV that was designed to address
agency priorities for technology verification.
The goal of the ESTE program is to further environmental protection by substantially accelerating the
acceptance and use of improved and innovative environmental technologies. The ESTE program was
developed in response to the belief that there are many viable environmental technologies that are not
being used for the lack of credible third-party performance data. With performance data developed under
this program, technology buyers, financiers, and permitters in the United States and abroad will be better
equipped to make informed decisions regarding environmental technology purchase and use.
This ESTE project involved evaluation of co-firing common woody biomass in industrial, commercial or
institutional coal-fired boilers. For this project ERG was the responsible contractor and Southern
Research Institute (Southern) performed the work under subcontract. Client offices within the EPA, those
with an explicit interest in this project and its results, include: Office of Air and Radiation (OAR),
Combined Heat and Power (CHP) Partnership, Office of Air Quality Planning and Standards (OAQPS),
Combustion Group, Office of Solid Waste (OSW), Municipal and Industrial Solid Waste Division, and
ORD's Sustainable Technology Division. Letters of support have been received from the U.S.
Department of Agriculture Forest Service and the Council of Industrial Boiler Owners.
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TECHNOLOGY DESCRIPTION
Wood Pellets from a Renewafuel, LLC facility in Michigan were used for this verification. The pellets
were a pressed oak product which is made from the waste of trailer bed manufacturing. No glue or
adhesives were used in the manufacture of the pellets. Proximate analyses of the pelletized wood used for
this testing is as follows:
Component % by Weight
Moisture 6.6
Ash 0.43
Volatile matter 75.5
Fixed carbon 17.3
The average heating value was 7,688 British thermal units per pound (Btu/lb).
Testing was conducted at the University of Iowa (UI) Main Power Plant's Boiler 10. The UI Main Power
Plant is a combined heat and power (CHP) facility which serves the main campus and the UI hospitals
and clinics. The plant continuously supplies steam service and cogenerated electric power. There are
four operational boilers at the facility, one stoker unit (Boiler 10), one circulating fluidized bed boiler
(Boiler 11), and two gas package boilers (Boilers 7 and 8). Boiler 10 was used during this co-firing
demonstration. Boiler 10 is a Riley Stoker Corporation unit rated at 170,000 Ib/h steam (206 MMBtu/h
heat input) at 750 degrees Fahrenheit (°F) and 600 pounds per square inch, gauge (psig). This unit
normally operates in pressure control (swing) mode on a multi-boiler header at a typical operating range
of 120,000 to 140,000 Ib/h steam. The unit can be base loaded up to its rated capacity or swing down to a
minimum load of 90,0001b/h. The facility includes a mechanical dust collector and electrostatic
precipitator (ESP) to control paniculate emissions. Bottom ash and fly ash generated by Boilers 10 and
11 are collected, blended, and shipped to a nearby limestone quarry where it is mixed with water,
solidified, and used to build roads or fill.
Forty-four tons (T) of Renewafuel's wood based pellets were delivered to the River Trading site and
mixed with stoker coal using a front end loader. The weight of the total mixture was 294 T, for a pellet
fraction by weight of approximately 15 %.
VERIFICATION DESCRIPTION
This project was designed to evaluate changes in boiler performance due to co-firing woody biomass with
coal. Boiler operational performance with regard to efficiency, emissions, and fly ash characteristics
were evaluated while combusting 100 percent coal and then reevaluated while co-firing biomass with
coal. The verification also addressed sustainability issues associated with biomass co-firing at this site.
The testing was limited to two operating points on Boiler 10:
• firing coal only at a typical nominal load
• firing a coahbiomass "co-firing" mixture of approximately 85:15 percent by weight
at the same operating load
Under each condition, testing was conducted in triplicate with each test run approximately three hours in
duration. In addition to the emissions evaluation, this verification addressed changes in fly ash
composition. Fly ash can serve as a portland cement production component, structural fill, road materials,
soil stabilization, and other beneficial uses. An important property that limits the use of fly ash is carbon
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content. Presence of metals in the ash, particularly mercury (Hg), can also limit fly ash use, such as in
cement manufacturing. Biomass co-firing could impact fly ash composition and properties, so this
verification included evaluation of changes in fly ash carbon burnout (loss on ignition), minerals, and
metals content.
During testing, the verification parameters listed below were evaluated. This list was developed based on
project objectives cited by the client organizations and input from the Biomass Co-firing Stakeholder
Group (BCSG).
Verification Parameters:
• Changes in emissions due to biomass co-firing including:
- Nitrogen oxides (NOX)
- Sulfur dioxide (SO2)
- Carbon monoxide (CO)
- Carbon dioxide (CO2)
- Total particulates (TPM) (including condensable particulates)
- Primary metals: arsenic (As), selenium (Se), zinc (Zn), and Hg
- Secondary metals: barium (Ba), beryllium (Be), cadmium (Cd), chromium (Cr), copper (Cu),
manganese (Mn), nickel (Ni), and silver (Ag)
- Hydrogen chloride (HC1) and hydrogen fluoride (HF)
• Boiler efficiency
• Changes in fly ash characteristics including:
- Carbon, hydrogen, and nitrogen (CHN), and SiO2, A12O3, and Fe2O3 content
- Primary metals: As, Se, Zn, and Hg
- Secondary metals: Ba, Be, Cd, Cr, Cu, Mn, Ni, and Ag
- fly ash fusion temperature
- Resource Conservation Recovery Act (RCRA) metals and Toxic Characteristic Leaching
Procedure (TCLP).
• Sustainability indicators including CO2 emissions associated with sourcing and transportation of
biomass and ash disposal under baseline (no biomass co-firing) and test case (with biomass co-
firing) conditions.
Rationale for the experimental design, determination of verification parameters, detailed testing
procedures, test log forms, and QA/QC procedures can be found in Test and Quality Assurance Plan titled
Test and Quality Assurance Plan - Environmental and Sustainable Technology Evaluation Biomass Co-
firing in Industrial Boilers.
Quality Assurance (QA) oversight of the verification testing was provided following specifications in the
ETV Quality Management Plan (QMP). Southern's QA Manager conducted an audit of data quality on a
representative portion of the data generated during this verification and a review of this report. Data
review and validation was conducted at three levels including the field team leader (for data generated by
subcontractors), the project manager, and the QA manager. Through these activities, the QA manager has
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concluded that the data meet the data quality objectives that are specified in the Test and Quality
Assurance Plan.
VERIFICATION OF PERFORMANCE
Boiler Efficiency
For the efficiency testing, mass feed of blended coal and wood was increased to attempt to repeat heat
input as closely as possible to the baseline coal only tests.
Table S-1. Boiler Efficiency
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Baseline Average
Cofire Average
Absolute Difference
% Difference
Fuel
100% Coal
Blended Fuel
(85.1 coal:
14.9 wood)
Statistically Significant Change?
Heat Input
(MMBtu/hr)
264.6
264.2
264.8
267.6
275.7
271.9
272.5
265.3
273.4
8.1
3.0%
na
Heat Output
(MMBtu/hr)
224.4
223.9
223.7
228.8
229.7
230.0
230.3
225.2
230.0
4.8
2.1%
na
Efficiency
(%)
84.8
84.8
84.5
85.5
83.3
84.6
84.5
84.9 ±0.4
84.1 +0.7
-0.7
-0.9%
No
The average efficiencies during baseline (coal only) and co-firing tests were 84.9 ± 0.4 and 84.1 ± 0.7
percent respectively. This change is not statistically significant, so it is concluded that co-firing biomass
at the 15 percent blending rate did not impact boiler efficiency performance.
Emissions Performance
Table S-2. Gaseous Pollutant Emissions (Ib/MMBtu)
Test ID
Fuel
SO,
CO,
NOX
CO
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
% Difference
Statistically Signific
100% Coal
Blended Fuel
(85.1 coal:
14.9 wood)
ant Change?
2.49
2.28
2.48
2.63
2.12
2.11
2.26
2.47 ±0.14
2.16 ±0.08
-12.4%
Yes
207
206
206
202
207
207
207
205 ±2
207 ±0.3
0.82%
No
0.473
0.442
0.438
0.486
0.487
0.525
0.506
0.460 ±0.02
0.506 ±0.018
10.2%
Yes
0.081
0.083
0.085
0.102
0.089
0.081
0.081
0.088 ±0.010
0.083 ±0.05
-5.02%
No
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SO2 emissions were about 13 percent lower while combusting the blended fuel, which correlates well
with the approximately 15 percent biomass to coal ratio. The reduction in SO2 indicates that co-firing
woody biomass may be a viable option for reducing SO2 emissions without adding emission control
technologies. NOX emissions had a statistically significant increase when co-firing. Increases are
presumably due to the higher temperatures within the boiler that were experienced while firing the dryer,
lighter blended fuel. Changes in CO and CO2 emissions were not statistically significant.
Table S-3. Paniculate Emissions (Ib/MMBtu)
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
Absolute Difference
% Difference
Fuel
1 00 % Coal
Blended Fuel
(85.1 coal: 14.9
wood)
Statistically Significant Change?
Total Particulate
0.090
0.039
0.054
Filterable PM
0.038
0.023
0.031
Condensable
PM
0.051
0.016
0.022
Not Tested
0.046
0.044
0.041
0.061 ±0.03
0.044 ±0.003
-1.71E-02
-28.1%
No
0.026
0.023
0.023
0.031 ±0.008
0.024 ±0.001 8
-7.03E-03
-22.8%
No
0.021
0.020
0.018
0.030 ±0.02
0.020 ±0.001 2
-1.01E-02
-33.9%
No
Although not statistically significant, particulate emission fractions were generally lower while co-firing
the blended fuel. This is likely caused by the lower ash content of the blended fuels. It could also be the
result of better combustion or better ESP performance due to changes in firebox temperatures or flyash
characteristics.
Metals emissions were relatively low during all test periods. The only statistically significant change in
metals emissions was a decrease in selenium. Emissions of HC1 and HE were considerably lower during
co-firing decreasing by approximately 9 and 29 percent, respectively.
Fly Ash Characteristics
Changes in ash characteristics were generally small, which is favorable for most operating systems (ash
handling systems would not be expected to be impacted by co-firing at this rate). Carbon content and ash
loss on ignition were both reduced significantly during biomass co-firing, although neither ash met the
Class F requirements for use in concrete. Quantitative flyash results are voluminous and not presented
here, but can be viewed in the main body of the report in Tables 3-7 through 3-9.
Biomass co-firing during this verification did not impact the quality of the ash with regard to fly ash
TCLP metals (40 CFR 261.24) and Class F Requirements (C 618-05). Metals content of the ash was well
below the TCLP criteria during all test periods and changes were not significant. The ash generated
during co-firing did have a significantly higher SO3 content, but was still well below the Class F
requirement.
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Sustainability Issues
• The wood pellets used for testing at the University of Iowa were produced from waste wood
waste at a rate of 4.5 tons per hour. The equipment used to produce the pellets is rated at 250
horsepower and was operated at 80 percent of capacity. Based on electrical consumption of
0.746 kWh/hp multiplied by 200 hp, the energy use per hour to produce the pellets was 149.14
kWh or 33.14 kWh/ton. Based on an Energy Information Administration emission factor for
Michigan (location of the production facility) of 1.58 Ibs CO2/kWh, CO2 emissions per ton of
pellets produced is 52.36 Ibs.
• Wood-based pellets were transported from Battle Creek Michigan to Muscatine, Iowa (where the
University of Iowa's coal supplier is located). 43 tons of wood-based pellets were shipped with
two trucks using 350 Cummins motors. The trucks averaged 6.5 miles per gallon. The distance
from Battle Creek to Muscatine is 345 miles. Therefore:
345 miles * 2 trucks = 690 miles, divided by 6.5 mpg = 106.15 gallons, divided by 43
tons fuel = 2.47 gallons/ton.
Renewafuel has a 28-acre site for possible future operations in Anamosa, Iowa. The distance
from Anamosa to Muscatine is 65 miles. Here, Renewafuel can load as much as 25 tons of fuel
per truck. Assuming use of the same truck with 6.5 miles per gallon the fuel used per ton of fuel
transported from Anamosa to Muscatine, fuel usage from Anamosa is then:
65 miles, divided by 6.5 mpg = 10 gallons, divided by 25 tons per truck = 0.4 gallons/ton
• Based on an Energy Information Administration emission factor of 19.564 Ibs CO2/gallon, CO2
emissions per ton of pellets transported to the facility are:
48.3 Ibs/ton for Battle Creek (2.47 gal fuel /ton pellets * 19.564 Ibs CO2/gal).
7.82 Ibs/ton for Anamosa (0.4 gal/ton * 19.564 Ibs CO2/gal).
• Based on data generated during this testing, the CO2 emission rates while firing straight coal and
blended fuel (at a blending rate of approximately 15 percent wood by mass) were 205 and 207
Ib/MMBtu, respectively. However, combustion of Renewafuel wood pellets, which are
comprised of biogenic carbon—meaning it is part of the natural carbon balance and will not add
to atmospheric concentrations of CO2—emits no creditable CO2 emissions under international
greenhouse gas accounting methods developed by the IPCC and adopted by the CFPA [6]. The
slight increase in CO2 emissions is likely also impacted by the increased mass fuel feed rates
during co-firing. By analyzing the heat content of the coal and the wood, the total boiler heat
input for the test periods, and boiler efficiency, it was determined that approximately 10 percent
of the heat generated during co-firing test periods is attributable to the Renewafuel pellets fuel. It
is therefore estimated that the CO2 emissions offset during this testing is approximately 10
percent, or 20.7 Ib/MMBtu at this co-firing blend.
• UI Boiler 10 typically operates in the 160 to 190 MMBtu/hr heat generating rate. Assuming an
availability and utilization rate of 80 percent for Boiler 10, this would equate to estimated annual
CO2 emission reductions of approximately 11,000 to 13,000 tons per year. CO2 offsets from use
of wood pellets could be even greater had the analysis included emissions associated with coal
mining and transportation.
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• Regarding use and or disposal of fly ash, biomass co-firing did not impact either sustainability
issue since the quality of the ash with regard to fly ash TCLP metals and Class F Requirements
was unchanged.
Details on the verification test design, measurement test procedures, and Quality Assurance/Quality Control
(QA/QC) procedures can be found in the Test Plan titled Test and Quality Assurance Plan - Environmental
and Sustainable Technology Evaluation Biomass Co-firing in Industrial Boilers. (Southern 2006). Detailed
results of the verification are presented in the Final Report titled Environmental and Sustainable Technology
Evaluation Biomass Co-firing in Industrial Boilers - University of Iowa (Southern 2007). Both can be
downloaded from the Southern's web-site (www.sri-rtp.com) or the ETV Program web-site
(ww w. epa. eov/etv).
Signed by: Sally Gutierrez - April 28, 2008 TimHansen-April 3, 2008
Sally Gutierrez Tim Hansen
Director Program Director
National Risk Management Research Laboratory Southern Research Institute
Office of Research and Development
Notice: This verification was based on an evaluation of technology performance under specific, predetermined
criteria and the appropriate quality assurance procedures. The EPA and Southern Research Institute make no
expressed or implied warranties as to the performance of the technology and do not certify that a technology will
always operate at the levels verified. The end user is solely responsible for complying with any and all applicable
Federal, State, and Local requirements. Mention of commercial product names does not imply endorsement or
recommendation.
EPA REVIEW NOTICE
This report has been peer and administratively reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Mention of trade names or commercial products does not constitute endorsement or
recommendation for use.
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EPA Contract No. EP-C-04-056
Work Assignment No. 2-8-101
April 2008
Environmental and Sustainable Technology Evaluation
Biomass Co-firing in Industrial Boilers
University of Iowa Unit 10
Prepared by:
Southern Research Institute
3000 Aerial Center Parkway, Ste. 160
Morrisville, NC 27560 USA
Telephone: 919/806-3456
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TABLE OF CONTENTS
Page
APPENDICES ii
LIST OF FIGURES iii
LIST OF TABLES iii
ACRONYMS AND ABBREVIATIONS iv
DISTRIBUTION LIST v
ACKNOWLEDGMENTS vi
1.0 INTRODUCTION 1-1
1.1 BACKGROUND 1-1
2.0 VERIFICATION APPROACH 2-1
2.1 HOST FACILITY AND TEST BOILER 2-2
2.2 FIELD TESTING 2-4
2.2.1 Field Testing Matrix 2-5
2.3 BOILER PERFORMANCE TEST PROCEDURES 2-5
2.3.1 Boiler Efficiency 2-5
2.3.1.1 Fuel Sampling and Analyses 2-6
2.3.2 Boiler Emissions 2-7
2.3.3 Fly ash Characteristics 2-8
2.4 SUSTAINABILITY INDICATORS AND ISSUES 2-8
3.0 RESULTS 3-1
3.1 BOILER EFFICIENCY 3-1
3.2 BOILER EMISSIONS 3-2
3.3 FLYASH CHARACTERISTICS 3-5
3.4 SUSTAINABILITY ISSUES 3-8
3.4.1 GHG Emission Offsets 3-8
4.0 DATA QUALITY ASSESSMENT 4-1
4.1 DATA QUALITY OBJECTIVES 4-1
4.1.1 Emissions Testing QA/QC Checks 4-1
4.1.2 Fly ash and Fuel Analyses QA/QC Checks 4-2
4.1.3 Boiler Efficiency QA/QC Checks 4-3
5.0 REFERENCES 5-1
APPENDICES
Page
Appendix A Emissions Data A-l
Appendix B Fuels and Ash Analyses B-l
Appendix C Boiler Efficiency Calculations C-l
Appendix D ESP Operational Data D-l
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LIST OF FIGURES
Figure 2-1. The University of Iowa Main Power Plant 2-2
Figure 2-2. Test Port Locations for Boiler 10 2-3
Figure 2-3. Renewafuel Pelletized Wood 2-4
LIST OF TABLES
Table 2-1. UI-10CEMS 2-3
Table 2-2. University of Iowa Boiler 10 Test Periods 2-5
Table 2-3. Summary of Boiler Efficiency Parameters 2-6
Table 2-4. Summary of Fuel Analyses 2-6
Table 2-5. Summary of Emission Test Methods and Analytical Equipment 2-7
Table 2-6. Summary of Fly ash Analyses 2-8
Table 3-1 Fuel Characteristics (As received) 3-1
Table 3-2. Boiler Efficiency 3-2
Table 3-3. Gaseous Pollutant Emissions (Ib/MMBtu) 3-2
Table 3-4. Particulate Emissions (Ib/MMBtu) 3-3
Table 3-5. Primary Metals Emissions (Ib/MMBtu) 3-4
Table 3-6. Acid Gas (Ib/MMBtu) 3-4
Table 3-7. Ash Characteristics 3-6
Table 3-8. Ash TCLP Metals (mg/1) 3-7
Table 3-9. Fly Ash Class F Requirements (C 618-05) 3-8
Table 4-1. Summary of Emission Testing Calibrations and QA/QC Checks 4-2
Table 4-2. Boiler Efficiency QA/QC Checks 4-3
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Acronyms and Abbreviations
Ag silver
As arsenic
Ba barium
Be beryllium
BCSG Biomass Co-firing Stakeholder
Group
Btu British thermal unit
Btu/h British thermal unit per hour
Cd cadmium
CEMS continuous emissions
monitoring system
CHN carbon, hydrogen, and nitrogen
CHP combined heat and power
CO carbon monoxide
CO2 carbon dioxide
Cr chromium
Cu copper
DQO data quality objective
EPA-ORD Environmental Protection
Agency
Office of Research and
Development
ESP electrostatic precipitator
ESTE Environmental and Sustainable
Technology Evaluation
ETV Environmental Technology
Verification
gr/dscf grains per dry standard cubic
foot
HC1 hydrogen chloride
HE hydrogen fluoride
Hg mercury
ICI industrial-commercial-
institutional
kW kilowatt
Ib/h pounds per hour
Ib/lb-mol pounds per pound-mole
MMBtu/h million British thermal units per
hour
Mn manganese
MQO measurement quality objective
MW megawatt
Ni nickel
NOX nitrogen oxides
O2 oxygen
QA / QC quality assurance / quality
control
OAQPS Office of Air Quality Planning
and Standards
OAR Office of Air and Radiation
OSW Office of Solid Waste
ppmvd parts per million by volume, dry
psig pounds per square inch, gauge
Se selenium
SO2 sulfur dioxide
T tons (English)
TCLP Toxic Characteristic Leaching
Procedure
TPM total paniculate matter
TQAP test and quality assurance plan
UI University of Iowa
Zn zinc
°F degrees Fahrenheit
IV
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DISTRIBUTION LIST
U.S. EPA - Office of Research and Development
Teresa Harten
David Kirchgessner
Donna Perla
Robert Wright
U.S. EPA - Office of Air Quality Planning and Standards
Robert Wayland
James Eddinger
U.S. EPA - Office of Solid Waste
Alex Livnat
U.S. EPA - Combined Heat and Power Partnership
Kim Grossman
Southern Research Institute
Tim Hansen
William Chatterton
Eric Ringler
University of Iowa
Ferman Milster
Ben Fish
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ACKNOWLEDGMENTS
Southern Research Institute wishes to thank the ETV-ESTE program management, especially Theresa
Harten, David Kirchgessner, and Robert Wright for supporting this verification and reviewing and
providing input on the testing strategy and this Verification Report. Thanks are also extended to the
University of Iowa for hosting the test, and their interests in sustainable fuels. Special thanks go to
Associate Director - Utilities and Energy Management Ferman Milster, and Plant Engineer Ben Fish.
Their input supporting the verification and assistance with coordinating field activities was invaluable to
the project's success. Finally, thanks are extended to James Mennell of Renewafuel, LLC for providing
the biomass based fuel in support of this evaluation.
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1.0 INTRODUCTION
1.1 BACKGROUND
The U.S. Environmental Protection Agency's Office of Research and Development (EPA-ORD) operates
the Environmental and Sustainable Technology Evaluation (ESTE) program to facilitate the deployment
of innovative technologies through performance verification and information dissemination. In part, the
ESTE program is intended to increase the relevance of Environmental Technology Verification (ETV)
Program projects to the U.S. EPA program and regional offices.
The goal of the ESTE program is to further environmental protection by substantially accelerating the
acceptance and use of improved and innovative environmental technologies. The ESTE program was
developed in response to the belief that there are many viable environmental technologies that are not
being used for the lack of credible third-party performance data. With performance data developed under
this program, technology buyers, financiers, and permitters in the United States and abroad will be better
equipped to make informed decisions regarding environmental technology purchase and use.
The ESTE program involves a three step process. The first step is a technology category selection
process conducted by ORD. The second step involves selection of the project team and gathering of
project collaborators and stakeholders. Collaborators can include technology developers, vendors,
owners, and users. They support the project through funding, cost sharing, and technical support.
Stakeholders can include representatives of regulatory agencies, trade organizations relevant to the
technology, and other associated technical experts. The project team relies on stakeholder input to
improve the relevance, defensibility, and usefulness of project outcomes. Both collaborators and
stakeholders are critical to development of the project test and quality assurance plan (TQAP), the end
result of step two. Step three includes the execution of the verification and quality assurance and review
process for the final reports.
This ESTE project involved evaluation of co-firing common woody biomass in industrial, commercial or
institutional coal-fired boilers. For this project ERG was the responsible contractor and Southern
Research Institute (Southern) performed the work under subcontract. Client offices within the EPA, those
with an explicit interest in this project and its results, include: Office of Air and Radiation (OAR),
Combined Heat and Power (CHP) Partnership, Office of Air Quality Planning and Standards (OAQPS),
Combustion Group, Office of Solid Waste (OSW), Municipal and Industrial Solid Waste Division, and
ORD's Sustainable Technology Division. Letters of support have been received from the U.S.
Department of Agriculture Forest Service and the Council of Industrial Boiler Owners.
With increasing concern about global warming and fossil fuel energy supplies, there continues to be an
increasing interest in biomass as a renewable and sustainable energy source. Many studies and research
projects regarding the efficacy and environmental impacts of biomass co-firing have been conducted on
large utility boilers, but less data is available regarding biomass co-firing in industrial size boilers. As
such, OAQPS has emphasized an interest in biomass co-firing in industrial-commercial-institutional (ICI)
boilers in the 100 to 1000 million British thermal units per hour (MMBtu/h) range. The reason for this
emphasis is to provide support for development of a new area-source "Maximum Achievable Control
Technology" standard.
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The focus for this project was to evaluate performance and emission reductions for ICI boilers as a result
of biomass co-firing. The primary objectives of this project were to:
• Evaluate changes in boiler emissions due to biomass co-firing
• Evaluate boiler efficiency with biomass co-firing
• Examine any impact on the value and suitability of fly ash for beneficial uses (carbon and metals
content)
• Evaluate sustainability indicators including emissions from sourcing and transportation of
biomass and disposal of fly ash
This document is one of two Technology Evaluation Reports for this ESTE project. This report presents
results of the testing conducted on Unit 10 at the University of Iowa's Power Plant in Iowa City. This
report includes the following components:
• Brief description of the verification approach and parameters (§2.0)
• Description of the test location (§ 2.1)
• Brief description of sampling and analytical procedures (§ 2.2)
• Test results (§ 3.0)
• Data quality (§ 4.0)
This report has been reviewed by representatives of ORD, OAQPS, OSW, the EPA QA team, and the
project stakeholders and collaborators. It documents test operations and verification results. It is
available in electronic format from Internet sites maintained by Southern Research Institute (Southern)
(www.sri-rtp.com) and ETV program (www.epa.eov/etv).
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2.0 VERIFICATION APPROACH
This project was designed to evaluate changes in boiler performance due to co-firing woody biomass with
coal. Boiler operational performance with regard to efficiency, emissions, and fly ash characteristics
were evaluated while combusting 100 percent coal and then reevaluated while co-firing biomass with
coal. The verification also addressed sustainability issues associated with biomass co-firing at this site.
The testing was limited to two operating points on Boiler 10 at U of I:
• firing coal only at a typical nominal load
• firing a coal:biomass "co-firing" mixture of approximately 85:15 percent by weight
at the same operating load
In addition to the emissions evaluation, this verification addressed changes in fly ash composition. Fly
ash can serve as a portland cement production component, structural fill, road materials, soil stabilization,
and other beneficial uses. An important property that limits the use of fly ash is carbon content. Presence
of metals in the ash, particularly mercury (Hg), can also limit fly ash use, such as in cement
manufacturing. Biomass co-firing could impact fly ash composition and properties, so this verification
included evaluation of changes in fly ash carbon burnout (loss on ignition), minerals, and metals content.
During testing, the verification parameters listed below were evaluated. This list was developed based on
project objectives cited by the client organizations and input from the Biomass Co-firing Stakeholder
Group (BCSG).
Verification Parameters:
• Changes in emissions due to biomass co-firing including:
- Nitrogen oxides (NOX)
- Sulfur dioxide (SO2)
- Carbon monoxide (CO)
- Carbon dioxide (CO2)
- Total particulates (TPM) (including condensable particulates)
- Primary metals: arsenic (As), selenium (Se), zinc (Zn), and Hg
- Secondary metals: barium (Ba), beryllium (Be), cadmium (Cd), chromium (Cr), copper (Cu),
manganese (Mn), nickel (Ni), and silver (Ag)
- Hydrogen chloride (HC1) and hydrogen fluoride (HF)
• Boiler efficiency
• Changes in fly ash characteristics including:
- Carbon, hydrogen, and nitrogen (CHN), and SiO2, A12O3, and Fe2O3 content
- Primary metals: As, Se, Zn, and Hg
- Secondary metals: Ba, Be, Cd, Cr, Cu, Mn, Ni, and Ag
- fly ash fusion temperature
- Resource Conservation Recovery Act (RCRA) metals and Toxic Characteristic Leaching
Procedure (TCLP).
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• Sustainability indicators including CO2 emissions associated with sourcing and transportation of
biomass and ash disposal under baseline (no biomass co-firing) and test case (with biomass co-
firing) conditions.
2.1 HOST FACILITY AND TEST BOILER
Testing was conducted on two industrial boilers that are capable of co-firing woody biomass using two
different biomass types and blends. The two units that hosted tests were Minnesota Power's Rapids
Energy Center Boiler 5 (MP-5) and the University of Iowa (UI) Main Power Plant's Boiler 10. Results of
the Rapids Energy Center testing are published under separate cover and can be found at www.sri-
rtp.com.
The UI Main Power Plant is a combined heat and power (CHP) facility which serves the main campus
and the UI hospitals and clinics. The plant continuously supplies steam service and cogenerated electric
power. There are four operational boilers at the facility, one stoker unit (Boiler 10), one circulating
fluidized bed boiler (Boiler 11), and two gas package boilers (Boilers 7 and 8). Three controlled
extraction turbine generators with 24.7 megawatt (MW) capacity cogenerate about 30 percent of the
university and hospital facilities total electric needs.
Figure 2-1. The University of Iowa Main Power Plant
Boiler 10 is a Riley Stoker Corporation unit rated at 170,000 Ib/h steam (206 MMBtu/h heat input) at 750
degrees Fahrenheit (°F) and 600 pounds per square inch, gauge (psig). This unit normally operates in
pressure control (swing) mode on a multi-boiler header at a typical operating range of 120,000 to 140,000
Ib/h steam. The unit can be base loaded up to its rated capacity or swing down to a minimum load of
90,0001b/h.
This boiler is currently fired with Appalachian coal mined in West Virginia and Pennsylvania and barged
to Muscatine, Iowa for distribution. However, UI has been successful in converting the fluidized bed
boiler (Boiler 11) at the facility to a co-firing unit using an oat hull product generated at a nearby food
processing plant. In keeping with the economic and environmental benefits realized through this effort,
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UI is interested in introducing biomass co-firing on Boiler 10. A pelletized wood product manufactured
from woody biomass by Renewafuels, LLC in Minnesota has been identified as a suitable co-firing fuel
for Boiler 10.
Emissions testing for this program was conducted in the ductwork of the selected boiler upstream of the
stack. The testing location and ports are shown in Figure 2-2.
Figure 2-2. Test Port Locations for Boiler 10
The facility includes a mechanical dust collector and electrostatic precipitator (ESP) to control paniculate
emissions. Bottom ash and fly ash generated by Boilers 10 and 11 are collected, blended, and shipped to
a nearby limestone quarry where it is mixed with water, solidified, and used to build roads or fill.
Boiler 10 is equipped with a continuous emissions monitoring system (CEMS) that monitors flue gas SO2
and 62 concentrations. Table 2-1 summarizes the Boiler 10 CEMS specifications.
Table 2-1. UI-10 CEMS
Parameter
S02
02
Instrument Make/Model
TML 50-H
TML41-HO2
Instrument Range
0- 1000ppm
0-25 %
Reporting Units
Ib/MMBtu
%
The facility has a fully equipped control room that continuously monitors boiler operations. The system's
distributed control system includes a PI Historian software package that allows the facility to customize
data acquisition, storage, and reporting activities. Operational parameters that were recorded during this
test program include the following:
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Heat input, Btu/h
Steam flow, Ib/h
Steam pressures, psig, and temperatures, °F
Air flows, Ib/h, and temperatures, °F
Power output, MW
SC>2 emissions, pounds per million Btu (Ib/MMBtu)
ESP variables (volts, amperes, number of fields on l
on line), recorded manually
These data were recorded using the PI Historian during each test period. One minute readings were
recorded during each test period using an assigned start and end tag, and then averaged over the test
period to document boiler operations during the testing, co-firing rates, and boiler efficiency. Key
parameters such as heat input and steam flow are summarized in the results section of this report. ESP
operational data are summarized in Appendix D.
2.2 FIELD TESTING
Wood pellets from a Renewafuel, LLC facility in Michigan were shipped to the River Trading Co. coal
yard in Muscatine, IA (the facility's coal supplier). The pellets were a pressed oak product which is made
from the waste of trailer bed manufacturing. No glue or adhesives were used in the manufacture of the
pellets. A sample of pellets is shown in Figure 2-3.
Figure 2-3. Renewafuel Pelletized Wood
Proximate analyses of the pelletized wood used for this testing is as follows:
Component % by Weight
Moisture 6.6
Ash 0.43
Volatile matter 75.5
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Fixed carbon
17.3
The average heating value was 7,688 British thermal units per pound (Btu/lb).
Forty-four tons (T) of Renewafuel's wood based pellets were delivered to the River Trading site and
mixed with stoker coal using a front end loader. The weight of the total mixture was 294 T, for a pellet
fraction by weight of approximately 15 %. Table 3-1 summarizes the composition of the sites coal supply
and the blended fuel. The fuel mix was delivered by truck and stored in Silo #3 at the facility. Over the
next two days the mixed fuel was transferred by operations staff to the south bunker.
2.2.1 Field Testing Matrix
A set of three replicate tests were conducted while firing coal only on March 13, 2007. The following
day, a second set of three tests were conducted while co-firing biomass and coal. Duration of each test
run was approximately 180 minutes. Other than changes in fuel composition, all other boiler operations
were replicated as closely as possible during test sets. Test and sampling procedures were also consistent
between sets of tests. A fourth run on straight coal was conducted on March 15 to repeat the metals
testing conducted during Baseline test 3 on the 13th because broken glassware had invalidated that test
run. Table 2-2 summarizes the test matrix.
Table 2-2. University of Iowa Boiler 10 Test Periods
Date
3-13-07
3-14-07
3-15-07
Time
08:20-11:14
12:12-14:55
15:30- 18:00
08:15-11:00
11:50-14:25
15:10-17:35
07:50- 10:10
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline 4
Fuel
1 00 % coal
Blended fuel
(85.1coal:14.9
wood)
1 00% coal
Steam Flow (Klb/h)
159.9
159.9
159.7
163.0
163.2
163.5
162.8
All testing was conducted during stable boiler operations (defined as boiler steam flows varying by less
than 5 percent over a 5 minute period). Southern representatives coordinated testing activities with boiler
operators to ensure that all testing was conducted at the desired boiler operating set points and the boiler
operational data needed to calculate efficiency was properly logged and stored. Southern also supervised
all emissions testing activities.
2.3 BOILER PERFORMANCE TEST PROCEDURES
Conventional field testing protocols and reference methods were used to determine boiler efficiency,
emissions, and fly ash properties. A brief description of the methods and procedures is provided here.
Details regarding the protocols and methods proposed are provided in the document titled: Test and
Quality Assurance Plan - Environmental and Sustainable Technology Evaluation - Biomass Co-firing in
Industrial Boilers [1].
2.3.1 Boiler Efficiency
Boiler efficiency was determined following the Bru method in the B&W Steam manual [2]. The
efficiency determinations were also used to estimate boiler heat input during each test period. The facility
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logs all of the data required for determination of boiler efficiency on a regular basis. Certain parameters
such as ambient conditions and flue gas temperatures were independently measured by Southern. Table
2-3 summarizes the boiler operational parameters logged during testing and the source and logging
frequency for each.
Table 2-3. Summary of Boiler Efficiency Parameters
Operational Parameter
Intake air temperature, °F
Flue gas temperature at air heater inlet, °F
Fuel temperature, °F
Moisture in air, Ib/lb dry air
Fuel consumption, Ib/h
Combustion air temperature, °F
Steam flow, MMBtu/h or Ib/h
Steam pressure, psig
Steam temperature, °F
Supply water pressure, psig
Supply water temperature, °F
Power generation, kW
Fuel ultimate analyses, both wood and coal
Fuel heating value, Btu/lb
Unburned carbon loss, %
Source of Data
Southern measurements
Southern measurements
Facility PI Historian Control
System
Analytical laboratory
Logging Frequency
Five minute intervals
Twice per test run
One minute averages
One composite coal,
mixed fuel, and fly ash
sample per test (3 total for
each condition)
2.3.1.1 Fuel Sampling and Analyses
Fuel samples were collected during each test run for ultimate and heating value analysis. A composite of
grab samples of coal and biomass were prepared during co-firing test runs and submitted to Wyoming
Analytical Laboratories, Inc. in Laramie, Wyoming for the analyses shown in Table 2-4.
Table 2-4. Summary of Fuel Analyses
Parameter
Ultimate analysis
Gross calorific value
Method
ASTM D3176
ASTM D5865 (coal) ASTM
E71 1-87 (biomass)
Grab samples of each fuel (straight coal and blended fuel) were collected from the solid fuel conveyer
immediately above the stoker feed hopper. The grabs contained approximately one Ib of fuel and were
collected at 30 minute intervals during each test run and combined in a large pail. One mixed composite
sample of approximately one Ib of each fuel was generated for each test run, sealed and submitted for
analysis. Collected composite samples were labeled, packed and shipped to Wyoming Analytical along
with completed chain-of-custody documentation for off-site analysis. Because the blended fuel is
delivered premixed, pelletized wood fuel samples were collected at the fuel blending facility (coal yard)
and sealed in plastic zip lock bags. These samples were submitted to the field team leader for subsequent
analysis. The ultimate analysis reported the following fuel constituents as percent by weight:
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• carbon
• water
• sulfur
• nitrogen
• hydrogen
• oxygen
• ash
The efficiency analysis requires the unburned carbon loss value, or carbon content of fly ash. Fly ash
samples were also collected during each test run and submitted for analysis. Prior to each test run,
precipitator ash hoppers were cleared of residual ash. Grab samples of ash were then collected from a
hopper at 30 minute intervals during each test run and combined in a gallon size metal ash sampling can.
Collected ash samples were then sealed in plastic bags, labeled, packed and shipped to Wyoming
Analytical along with completed chain-of-custody documentation for off-site analysis. Results of these
analyses were used to complete the combustion gas calculations in the Bru method.
2.3.2 Boiler Emissions
Measurements required for emissions tests include:
• fuel heat input, Btu/h (via boiler efficiency, Section 2.3.1)
• gaseous pollutant concentrations, parts per million by volume, dry (ppmvd)
• TPM and condensible paniculate concentrations, grains per dry standard cubic foot
(gr/dscf)
• CO2 concentrations, percent
• flue gas molecular weight, pounds per pound-mole (Ib/lb-mol)
• flue gas moisture concentration, percent
• flue gas flow rate, dry standard cubic feet per hour
The average emission rates for each pollutant are also reported in units of pounds per hour (Ib/h), and
pounds per million Btu (Ib/MMBtu).
All testing was conducted by GE Energy following EPA Reference or Conditional Methods for emissions
testing [3]. Table 2-5 summarizes the reference methods used and the fundamental analytical principle
for each method.
Table 2-5. Summary of Emission Test Methods and Analytical Equipment
Parameter or
Measurement
CO2
TPM
Condensable PM
Metals
HCI, HF
Moisture
Flue gas flow rate
U.S. EPA
Reference
Method
3A
5
CTM040/202
29
26
4
2
Principle of Detection
Non-dispersive infra-red
Gravimetric
Gravimetric
Inductively coupled plasma / cold vapor atomic
absorption spectroscopy
Ion chromatography
Gravimetric
Pilot traverse
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2.3.3 Fly ash Characteristics
Fly ash samples were collected during the efficiency and emissions testing periods to evaluate the impact
of biomass co-firing on ash composition. Fly ash samples were collected from the electrostatic
precipitator (ESP) collection hoppers during each test run. Hoppers were cleaned out between runs.
Collected samples were submitted to Wyoming Analytical along with completed chain-of-custody
documentation for determination of the parameters listed below. The laboratory also conducted tests to
evaluate ash fusion temperature. Results are compared to the Class F (bituminous and anthracite) or
Class C (lignite and sub bituminous) fly ash specifications. Table 2-6 summarizes the analytical methods
that were used.
Table 2-6. Summary of Fly ash Analyses
Parameter
CHN
Minerals
RCRA metals
Metals TCLP
Fly ash fusion temperature
Method
ASTM D5373
ASTM D4326-04
SW-846 3052/60 10
SW-846 1311/6010
ASTM D1857
2.4 SUSTAINABILITY INDICATORS AND ISSUES
Sustainability is an important consideration regarding use of woody biomass as a renewable fuel source.
This project evaluated certain sustainability issues for the two sites selected for field testing. The
following sustainability related issues were examined:
Estimated daily and annual woody biomass consumption at the nominal co-firing rate
Biomass delivery requirements (distance and mode)
Coal delivery requirements (distance and mode)
Fly ash composition, use, and waste disposal including delivery distance and mode.
Biomass Consumption, Type, and Source
The projected daily and annual biomass consumption rate is useful in determining whether the supply of
biomass is sustainable. Biomass consumption rates measured during the testing conducted at each site
were used as the basis to estimate daily and annual biomass consumption. The source, type, and
compositional analyses of the biomass was documented during testing.
Associated Biomass COy Emissions
By evaluating the average biomass consumption rate during the testing, upstream CO2 emissions
associated with the biomass supply were estimated. The distance between the biomass source and the
boiler tested along with CO2 emission factors for the modes of transportation used to deliver the biomass
were used to complete this analysis. Emission factors were determined based on EPA's AP 42 Emission
Factors Database [4].
Solid Waste Issues (Ash utilization)
Results of the baseline coal fly ash analyses and the co-fired fuel fly ash analyses were compared to
determine if co-firing biomass has a measurable impact on the carbon content of the ash with respect to
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ASTM standards for cement admixtures. In addition, results of the RCRA metals analyses for the
baseline and co-fire ash were compared to evaluate impact on metals content. The metals TCLP
analytical results were used to examine if co-firing impacts fly ash characteristics with respect to the
TCLP standards cited in 40 CFR 261.24 [5].
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3.0 RESULTS
Results of the testing are summarized in the following sections. Where results are used to evaluate
whether biomass co-firing resulted in significant changes in boiler performance, a statistical t-test was
applied with a 90 percent confidence interval. Field and analytical data generated during the verification
are presented in Appendices A through C. In general, the facility was able to process and utilize the
blended fuel with minimal problems. No physical changes to fuel handling or boiler equipment were
necessary to accommodate use of the pelletized biomass fuel. The mix was very dry due to concerns
associated with mixing the wood pellets with water, but the crew on shift kept the mix flowing to the
boiler and a successful three test runs were completed.
An additional coal only test run was performed as a precaution because a portion of the metals sampling
train was spilled during recovery of run 2. Once all runs were completed, test personnel confirmed that
all needed data and samples had been collected.
As part of the data analysis, results were analyzed to evaluate changes in boiler performance and fly ash
characteristics between the two sets of tests. Standard deviations of the replicate measurements
conducted under each fueling condition and a statistical analysis (t-test) with a 90 percent confidence
interval were used to verify the statistical significance of any observed changes in emissions or efficiency.
3.1 BOILER EFFICIENCY
Table 3-1 summarizes the major fuel characteristics for both coal and blended fuel. Detailed fuel
analyses, including results on a dry basis, are presented in Appendix B.
Table 3-1 Fuel Characteristics (As received)
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Baseline
Averages
Cofire
Averages
% Difference
Fuel
100% Coal
Blended
Fuel (85.1
coal: 14.9
wood)
Moisture
(%)
13.8
13.9
14.4
13.8
13.6
13.1
13.2
13.9
13.3
-4.6%
Carbon
(%)
63.8
63.7
61.8
62.3
59.8
60.3
59.2
62.8
59.8
-4.7%
Nitrogen
(%)
1.45
1.31
1.20
1.24
1.23
1.29
1.11
1.29
1.21
-6.1%
Sulfur (%)
1.48
1.50
1.05
1.48
1.40
1.37
1.38
1.40
1.38
-1.0
Ash (%)
7.0
6.7
6.4
7.3
6.6
6.3
6.1
6.9
6.4
-8.1%
Heating
Value
(Btu/lb)
1 1 ,242
1 1 ,287
10,935
11,153
10,615
10,757
10,555
11,154
10,642
-4.6%
The moisture, carbon content, and heating value of the blended fuel was consistently about 5 percent
lower than those of the baseline coal. The blended fuel also had about 8 percent less ash content.
Repeatability of the blended fuel results indicate that the fuel was evenly blended.
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Efficiency data showed no significant change when burning the coal/wood pellet mix despite the fact that
higher superheater and stack outlet temperatures were evident during the test. Combustion appeared to
occur higher up the boiler than on coal, this was observed by the camera inside the boiler. Table 3-2
summarizes boiler efficiency during the test periods
Table 3-2. Boiler Efficiency
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Baseline Average
Cofire Average
Absolute Difference
% Difference
Fuel
100% Coal
Blended Fuel
(85.1 coal:
14.9 wood)
Statistically Significant Change?
Heat Input
(MMBtu/hr)
264.6
264.2
264.8
267.6
275.7
271.9
272.5
265.3
273.4
8.1
3.0%
na
Heat Output
(MMBtu/hr)
224.4
223.9
223.7
228.8
229.7
230.0
230.3
225.2
230.0
4.8
2.1%
na
Efficiency
(%)
84.8
84.8
84.5
85.5
83.3
84.6
84.5
84.9 ±0.4
84.1 +0.7
-0.7
-0.9%
No
The average efficiencies during baseline (coal only) and co-firing tests were 84.9 ± 0.4 and 84.1 ± 0.7
percent respectively. This change is not statistically significant, so it is concluded that co-firing biomass
at the 15 percent blending rate did not impact boiler efficiency performance.
3.2 BOILER EMISSIONS
Table 3-3 and Figure 3-1 summarizes emission rates for the gaseous pollutants evaluated. SO2 emissions
were about 13 percent lower while combusting the blended fuel, which correlates well with the
approximately 15 percent biomass to coal ratio. The reduction in SO2 emissions is statistically
significant, and indicates that co-firing woody biomass may be a viable option for reducing SO2 emissions
without adding emission control technologies.
Table 3-3. Gaseous Pollutant Emissions (Ib/MMBtu)
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
% Difference
Statistically Signific
Fuel
100% Coal
Blended Fuel
(85.1 coal:
14.9 wood)
ant Change?
SO2
2.49
2.28
2.48
2.63
2.12
2.11
2.26
2.47 ±0.14
2.16 ±0.08
-12.4%
Yes
CO2
207
206
206
202
207
207
207
205 ±2
207 ±0.3
0.82%
No
NOX
0.473
0.442
0.438
0.486
0.487
0.525
0.506
0.460 ±0.02
0.506 ±0.018
10.2%
Yes
CO
0.081
0.083
0.085
0.102
0.089
0.081
0.081
0.088 ±0.010
0.083 ±0.05
-5.02%
No
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NOX emissions had a statistically significant increase when co-firing. Increases are presumably due to the
higher temperatures within the boiler that were experienced while firing the dryer, lighter blended fuel.
Also, boiler operators did not make significant changes to boiler operations to reduce flue gas
temperatures or NOX emissions. It's worth noting that in similar testing conducted at another facility, a
much higher blend of wood was co-fired with the coal and the biomass had much higher moisture content
(46 percent). In that case NOX emissions were significantly reduced, indicating that if the Renewafuel
pellets had a higher moisture content (i.e., had sat in a fuel yard for a time), NOX emissions may have
been reduced.
Changes in CO and CO2 emissions were not statistically significant. Regarding CO2 emissions, it should
be noted that combustion of wood-based fuel, which is comprised of biogenic carbon emits no creditable
CO2 emissions under international greenhouse gas accounting methods developed by the
Intergovernmental Panel of Climate Change (IPCC) and adopted by the International Council of Forest
and Paper Associations (ICFPA). Therefore, the facility realizes a significant annual reduction in CO2
emissions when co-firing wood (see Section 3.4.1)
Table 3-4 and Figure 3-2 summarizes results of filterable, condensable, and total particulate emissions.
Table 3-4. Particulate Emissions (Ib/MMBtu)
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
Absolute Difference
% Difference
Fuel
100% Coal
Blended Fuel
(85.1 coal: 14.9
wood)
Statistically Significant Change?
Total
Particulate
0.090
0.039
0.054
Filterable PM
0.038
0.023
0.031
Condensable
PM
0.051
0.016
0.022
Not Tested
0.046
0.044
0.041
0.061 ±0.03
0.044 ±0.003
-1.71E-02
-28.1%
No
0.026
0.023
0.023
0.031 ±0.008
0.024 ±0.0018
-7.03E-03
-22.8%
No
0.021
0.020
0.018
0.030 ±0.02
0.020 ±0.0012
-1.01E-02
-33.9%
No
Although not statistically significant, particulate emission fractions were generally lower while co-firing
the blended fuel. This is likely caused by the lower ash content of the blended fuels. It could also be the
result of better combustion or better ESP performance due to changes in firebox temperatures or flyash
characteristics. More testing and analysis will be needed to fully understand the impact of co-firing this
biomass on particulate emissions. ESP operational data presented in Appendix D indicate that conditions
were consistent between the two sets of runs with regard to ESP fields in operation and voltages.
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Table 3-5. Primary Metals Emissions (Ib/MMBtu)
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
Absolute Difference
% Difference
Fuel
100% Coal
Blended Fuel
(85.1 coal: 14.9
wood)
Statistically Significant Change?
Arsenic, As
7.75E-06
1.39E-05
1.84E-05
8.83E-06
9.66E-06
7.10E-06
6.84E-06
1.22E-05±
4.9E-06
7.87E-06 ±
1.6E-06
-4.35E-06
-35.6%
No
Mercury, Hg
4.71E-06
4.48E-06
4.49E-06
1.15E-07
4.21 E-06
3.76E-06
3.87E-06
3.45E-06 ±
2.2E-06
3.957E-06 ±
2.4E-07
4.98E-07
14.4%
No
Selenium, Se
6.02E-05
6.43E-05
7.40E-05
6.05E-05
5.04E-05
4.28E-05
3.69E-05
6.48E-05 ±
6.4E-06
4.34E-05 ±
6.8E-06
-2.14E-05
-33.0%
Yes
Zinc, Zn
2.52E-05
2.17E-05
2.55E-05
1.81E-05
2.44E-05
1.50E-05
1.55E-05
2.26E-05 ±
3.5E-06
1.83E-05
±5.3E-06
-4.33E-06
-19.1%
No
Metals emissions (primary metals summarized in Table 3-5) were relatively low during all test periods.
Changes in metals emissions on a percentage basis were large and variable from across the elements
analyzed, including the list of eight secondary metals. Absolute differences are shown in the table to
demonstrate how low metals emissions were, causing the large changes on a percent difference basis.
The only statistically significant change in metals emissions was for Se.
Acid gas emissions are summarized below. Emissions of HC1 and HF were considerably lower during
co-firing due to the reduced level of chlorine in the fuel. The HF reduction is statistically significant
using the t-test while the HC1 reduction is not.
Table 3-6. Acid Gases (Ib/MMBtu)
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
Absolute Difference
% Difference
Fuel
100% Coal
Blended Fuel
(85.1 coal: 14.9
wood)
Statistically Significant Change?
Hydrofluoric Acid, HF
5.00E-03
5.30E-03
6.10E-03
5.30E-03
4.50E-03
5.10E-03
5.47E-03± 0.0019
4.97E-03 ± 0.004
-5.00E-04
-9.15%
Yes
Hydrochloric Acid, HCI
3.94E-02
4.30E-02
4.00E-02
3.46E-02
2.79E-02
2.95E-02
4.08E-02 ± 0.0006
3.07E-02 ± 0.0004
-1.01E-02
-28.8%
No
3-4
-------
Southern Research Institute/US EPA
April 2008
In summary, emissions of SO2, Se, and HF were all reduced at a level with statistical significance as a
result of co-firing the wood based pellets with coal in this boiler, all without significant impacts on boiler
operations or efficiency. The co-firing also resulted in a statistically significant increase in NOX
emissions.
3.3 FLYASH CHARACTERISTICS
Results of the flyash analyses are summarized in Tables 3-7 through 3-9. Changes in ash characteristics
were generally small, which is favorable for most operating systems (ash handling systems would not be
expected to be impacted by co-firing at this rate). Carbon content and ash loss on ignition were both
reduced significantly during biomass co-firing, although neither ash met the Class F requirements for use
in concrete.
Biomass co-firing during this verification did not impact the quality of the ash with regard to fly ash
TCLP metals (40 CFR 261.24) and Class F Requirements (C 618-05), as shown in Tables 3-8 and 3-9.
Metals content of the ash was well below the TCLP criteria during all test periods and changes were not
significant. The ash generated during co-firing did have a significantly higher SO3 content, but was still
well below the Class F requirement.
3-5
-------
Southern Research Institute/US EPA
April 2008
Table 3-7. Ash Characteristics
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
% Difference
Fuel
100%
Coal
Blended
Fuel (85.1
coal: 14.9
wood)
Statistically Significant Change?
Carbon, wt
%
17.9
17.2
18.4
16.5
16.5
16.6
15.7
17.5 ±0.8
16.3 ±0.5
-6.9%
Yes
Silicon
Dioxide, %
as SiO2
39.1
39.0
38.7
38.0
38.3
37.6
38.0
38.7 ±0.5
37.9 ±0.3
-2.0%
Yes
Aluminum
Oxide, % as
AI2O3
18.8
18.4
18.3
17.7
18.0
17.6
17.7
18. 3 ±0.5
17.8 ±0.2
-3.0%
No
Iron
Oxide, %
as Fe2O3
14.1
14.9
15.1
15.0
15.0
14.7
15.2
14.8 ±0.5
15.0 ±0.3
1 .5%
No
Loss on
Ignition
19.2
18.6
19.1
18.5
18.3
18.4
17.4
18.9 ±0.3
18.0 ±0.5
-4.6%
Yes
Ash Fusion Temp., °F
Reducing
Atmosphere:
Initial
Deformation
1,849
1,900
1,877
1,915
1,860
1,870
2,095
1 ,885 ± 29
1,942 ±130
3.0%
No
Oxidizing
Atmosphere:
Initial
Deformation
2,005
2,051
2,060
2,039
2,075
2,009
2,007
2, 038 ±24
2,030 ±39
-0.40%
No
3-6
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Southern Research Institute/US EPA
April 2008
Table 3-8. Ash TCLP Metals (mg/l)
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
Fuel
100%
Coal
Blended
Fuel (85.1
coal: 14.9
wood)
Limit/ 40 CFR 261. 24
Silver
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
<0.001
< 0.001
5.0
Arsenic
0.35
0.25
0.11
0.16
0.29
0.11
0.096
0.22
0.17
5.0
Barium
0.51
0.47
0.43
0.64
0.64
0.18
0.18
0.51
0.33
100.0
Cadmium
0.075
0.086
0.088
0.11
0.110
0.10
0.10
0.09
0.10
1.0
Chromium
0.18
0.18
0.16
0.13
0.19
0.32
0.31
0.16
0.27
5.0
Mercury
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
0.2
Lead
0.80
0.76
0.80
0.60
1.00
0.86
0.66
0.74
0.84
5.0
Selenium
0.033
0.028
0.026
0.021
0.032
0.075
0.067
0.027
0.058
1.0
3-7
-------
Southern Research Institute/US EPA
April 2008
Table 3-9. Fly Ash Class F Requirements (C 618-05)
Test ID
Baseline 1
Baseline 2
Baseline 3
Baseline 4
Cofire 1
Cofire 2
Cofire 3
Class F
Requirements
Baseline Averages
Cofire Averages
Fuel
100%
Coal
Blended
Fuel (85.1
coal: 14.9
wood)
Silicon Dioxide
(SiO2) +
Aluminum Oxide
(AI2O3) + Iron
Oxide (Fe2O3),
(%)
72.0
72.3
72.0
70.8
71.3
69.9
70.9
70.0 (min %)
71.8
70.7
Sulfur
Trioxide
(S03), (%)
0.43
0.46
0.37
0.99
0.75
1.14
1.15
5.0 (max %)
0.56
1.01
Loss on
ignition, (%)
19.23
18.64
19.11
18.53
18.28
18.36
17.37
6.0 (max %)
18.9
18.0
3.4 SUSTAINABILITY ISSUES
Table 3-1 summarized the composition of the site's coal supply and the blended fuel. Regarding use and
or disposal of fly ash, biomass co-firing did not impact either sustainability issue since the quality of the
ash with regard to fly ash TCLP metals and Class F Requirements was unchanged. The following is a
brief GHG sustainability analysis for use of the pelletized fuel at this site.
3.4.1 GHG Emission Offsets
Energy Used to Produce Wood-Based Pelletized Fuel
The wood pellets used for testing at the University of Iowa were produced from waste wood waste at a
rate of 4.5 tons per hour. The equipment used to produce the pellets is rated at 250 horsepower and was
operated at 80 percent of capacity. Based on electrical consumption of 0.746 kWh/hp multiplied by 200
hp, the energy use per hour to produce the pellets was 149.14 kWh or 33.14 kWh/ton (149.14 divided by
4.5).
CO? Emissions from Energy Used to Produce Wood-Based Pelletized Fuel
Based on an Energy Information Administration emission factor for Michigan (location of the production
facility) of 1.58 Ibs CO2/kWh, CO2 emissions per ton of pellets produced is 52.36 Ibs (1.58 * 33.14).
Transportation Fuel Use
-------
Southern Research Institute/US EPA
April 2008
From Battle Creek, MI:
Wood-based pellets were transported from Battle Creek Michigan to Muscatine, Iowa (where the
University of Iowa's coal supplier is located). 43 tons of wood-based pellets were shipped with two
trucks using 350 Cummins motors. The trucks averaged 6.5 miles per gallon. The distance from Battle
Creek to Muscatine is 345 miles. Therefore:
• 345 miles * 2 trucks = 690 miles, divided by 6.5 mpg = 106.15 gallons, divided by 43 tons fuel =
2.47 gallons/ton.
From Anamosa, IA
Renewafuel has a 28-acre site for possible future operations in Anamosa, Iowa. The distance from
Anamosa to Muscatine is 65 miles. Further, Renewafuel can load as much as 25 tons of fuel per truck.
Assuming use of the same truck with 6.5 miles per gallon the fuel used per ton of fuel transported from
Anamosa to Muscatine, fuel usage from Anamosa is:
• 65 miles, divided by 6.5 mpg = 10 gallons, divided by 25 tons per truck = 0.4 gallons/ton
CO? Emissions From Transportation Fuel Use
Based on an Energy Information Administration emission factor of 19.564 Ibs CO2/gallon, CO2 emissions
per ton of pellets transported to the facility are:
• 48.3 Ibs/ton for Battle Creek (2.47 gal fuel /ton pellets * 19.564 Ibs CO2/gal).
• 7.82 Ibs/ton for Anamosa (0.4 gal/ton * 19.564 Ibs CO2/gal).
CO? Emissions from Combustion of Bituminous Coal Compared to Wood Pellets
Based on data generated during this testing, the CO2 emission rates while firing straight coal and blended
fuel (at a blending rate of approximately 15 percent wood by mass) were 205 and 207 Ib/MMBtu,
respectively. However, combustion of Renewafuel wood pellets, which are comprised of biogenic
carbon—meaning it is part of the natural carbon balance and will not add to atmospheric concentrations
of CO2—emits no creditable CO2 emissions under international greenhouse gas accounting methods
developed by the IPCC and adopted by the CFPA [6]. By analyzing the heat content of the coal and the
wood, the total boiler heat input for the test periods, and boiler efficiency, it was determined that
approximately 10 percent of the heat generated during co-firing test periods is attributable to the
Renewafuel pellets fuel. The following equation was used:
Heath = Fuel, * 0.149 * (LHVt/1000000)
Where: Heatb = average heat input attributable to wood pellets (27.7 MMBru/hr)
Fuelt = average fuel feed rate (24,200 Ib/hr), from plant records
0.149 = coal: biomass ratio, determined at coal yard
LHVb = heat content of wood pellets (7,688 Btu/lb), from fuel sample analyses
1,000,000 = Etu/MMEtu
It is therefore estimated that the CO2 emissions offset during this testing is approximately 10 percent, or
20.7 Ib/MMBtu at this co-firing blend.
3-9
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Southern Research Institute/US EPA
April 2008
UI Boiler 10 typically operates in the 160 to 190 MMBtu/hr heat generating rate. Assuming an
availability and utilization rate of 80 percent for Boiler 10, this would equate to estimated annual CO2
emission reductions of approximately 11,000 to 13,000 tons per year. CO2 offsets from use of wood
pellets could be even greater had the analysis included emissions associated with coal mining and
transportation.
The following equation was used:
C02offset.anmal = C02offset * Genmte * Av * 8,765 * (1/2,000)
Where: CO2offset.anmal = annual CO2 offset (13,648 ton/yr)
CO2offset = CO2 emissions offset (20.7 Ib/MMBtu)
Genrate = average boiler generating rate (190 MMBtu/hr)
Av = Assumed availability for boiler 10 (80 percent)
8,765 = hours per year
2,000 = Ibs per ton
3-10
-------
Southern Research Institute/US EPA
April 2008
4.0 DATA QUALITY ASSESSMENT
4.1 DATA QUALITY OBJECTIVES
Under the ETV-ESTE program, Southern specifies data quality objectives (DQOs) for each primary
verification parameter before testing commences as a statement of data quality. The DQOs for this
verification were developed based on input from EPA's ETV QA reviewers, and input from the BCSG.
Test results which meet the DQOs provide an acceptable level of data quality for technology users and
decision makers.
The DQOs for this verification are qualitative in that the verification produced emissions performance
data that satisfy the QC requirements contained in the EPA Reference Methods specified for each
pollutant, and the fuel and fly ash analyses meet the quality assurance / quality control (QA/QC)
requirements contained in the ASTM Methods being used.
This verification did not include a stated DQO for boiler efficiency determinations because measurement
accuracy validation for certain boiler parameters was not possible. Section 4.1.3 provides further
discussion.
4.1.1 Emissions Testing QA/QC Checks
Each of the EPA Reference Methods used here for emissions testing contains rigorous and detailed
calibrations, performance criteria, and other types of QA/QC checks. For instrumental methods using gas
analyzers, these performance criteria include analyzer span, calibration error, sampling system bias, zero
drift, response time, interference response, and calibration drift requirements. Methods 5, 29, CTM040,
and 202 for determination of particulates and metals also include detailed performance requirements and
QA/QC checks. Details regarding each of these checks can be found in the methods and are not repeated
here. However, results of certain key QA/QC checks for each method are reported as documentation that
the methods were properly executed. Key emissions testing QA/QC checks are summarized in Table 4-1.
Where facility CEMS were used, up to date relative accuracy test audit (RATA) certifications and
quarterly cylinder gas audits (CGAs) have been procured, reviewed, and filed at Southern to document
system accuracy.
The emissions testing completeness goal for this verification was to obtain valid data for 90 percent of the
test periods on each boiler tested. This goal was achieved as all data was validated for the test periods
except for the third baseline test run. Test personnel conducted a fourth test run in response.
4-1
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Southern Research Institute/US EPA
April 2008
Table 4-1. Summary of Emission Testing Calibrations and QA/QC Checks
Parameter
NOX,
CO,
C02,
O2
SO2
NOX
TPM,
Metals
Metals
HC1,
HF
Calibration/QC Check
Analyzer calibration
error test
System bias checks
System calibration drift
test
Relative accuracy test
audit
NO2 converter
efficiency
Percent isokinetic rate
Analytical balance
calibration
Filter and reagent
blanks
Sampling system leak
test
Dry gas meter
calibration
Sampling nozzle
calibration
ICP/CVAAS
Sampling system leak
test
Dry gas meter
calibration
Ion chromatograph
When
Performed/Frequency
Daily before testing
Before each test run
After each test run
annually
Once before testing
begins
After each test run
Daily before analyses
Once during testing
after first test run
After each test
Once before and once
after testing
Once for each nozzle
before testing
Spike and recovery of
prepared QC standards
After each test
Once before and once
after testing
Analysis of prepared
QC standards
Allowable Result
+ 2 % of analyzer
span
+ 5 % of analyzer
span
+ 3 % of analyzer
span
+ 20 percent of
reference method
98 % minimum
90- 110% for
TPM and metals
+ 0.0002 g
< 10 % of
paniculate catch
for first test run
<0.02 cfm
+ 5%
+ 0.01 in.
+ 25% of expected
value
<0.02 cfm
+ 5 %
+ 10% of expected
value
Actual Result
All calibrations, system
bias checks, and drift
tests were within the
allowable criteria.
Relative accuracy was
5.2 percent (February
2007)
NOX converter efficiency
was over 99%.
All criteria were met for
the TPM and metals
measurement and
analytical systems.
All matrix spike and
recovery results were
within 90 to 1 10 percent
of the standards,
including an independent
Hg audit sample
All criteria were met for
the acid gases
measurement and
analytical systems.
4.1.2 Fly ash and Fuel Analyses QA/QC Checks
The laboratory selected for analysis of collected fuel and fly ash samples (Wyoming Analytical
Laboratory Services, Inc.) operates under an internal quality assurance protocol, a copy of which is
maintained at Southern. Each of the analytical procedures used here include detailed procedures for
instrument calibration and sample handling. They also include QA/QC checks in the form of analytical
repeatability requirements or matrix spike analyses. All of the QA/QC checks specified in the methods
were met during these analyses.
4-2
-------
Southern Research Institute/US EPA
April 2008
4.1.3 Boiler Efficiency QA/QC Checks
Table 4-2 summarizes the contributing measurements for boiler efficiency determination, measurement
quality objectives (MQOs) for each, and the primary method of evaluating the MQOs. Factory
calibrations, sensor function checks, and reasonableness checks in the field were used to assess
achievement of the MQOs where possible. Some of the MQOs were either not met or impossible to
verify, so the overall uncertainty of the boiler efficiency determinations is unclear. In anticipation of this,
the test plan did not specify a DQO for boiler efficiency.
Table 4-2. Boiler Efficiency QA/QC Checks
Measurement /
Instrument
Fuel temperature, °F
Flue gas temperature at
air heater inlet, °F
Air temperature, °F
Moisture in air, Ib/lb
dry air
Combustion air
temperature, °F
Steam flow, MMBtu/h
orlb/h
Steam pressure, psig
Steam temperature, °F
Supply water pressure,
psig
Supply water
temperature, °F
Fuel feed rate, Ib/h
Fuel ultimate analyses,
both wood and coal
Fuel heating value,
Btu/lb
QA/QC Check
NIST-traceable
calibration
NIST-traceable
calibration
NIST-traceable
calibration
Cross check with NIST-
traceable standard
Orifice calibration
Cross check with NIST-
traceable standard
Cross check with boiler
efficiency calculations
ASTM D1945 duplicate
sample analysis and
repeatability
ASTM D1945 duplicate
sample analysis and
repeatability
When Performed
Upon purchase and
every 2 years
Annually
Upon installation
Annually
Annually
2 samples
MQO
+ 6°F
+ 1°F
+ 3.5 %
+ 6°F
+ 5 % reading
+ 5 psig
+ 6°F
+ 5 psig
+ 2 % of reference
standard
+ 5 % reading
Within D 1945
repeatability limits
for each fuel
component
Within D 1945
repeatability limits
for each fuel
component
Results achieved
Fuel temp + 1°F
Flue gas temp + 5°F
+ 1°F
+ 3.0 %
Within 5°F
Calibration not
available
+ 6 psig
+ 10°F
Calibrations not
available
Average + 11%, but
not used for
determining
efficiency
Method
repeatability criteria
were met
4-3
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Southern Research Institute/US EPA
April 2008
5.0 REFERENCES
[1] Southern Research Institute, Test and Quality Assurance Plan - Environmental and Sustainable
Technology Evaluation - Biomass Co-firing in Industrial Boilers, www.sri-rtp.com, Southern
Research Institute, Research Triangle Park, NC. October 2006.
[2] Babcock & Wilcox, Steam -Its Generation and Use - 40th Edition, The Babcock & Wilcox
Company, Barberton, Ohio, 1992.
[3] Code of Federal Regulations (Title 40 Part 60, Appendix A) Test Methods (Various),
http://www.gpoaccess.gov/cfr/index.html, U.S. Environmental Protection Agency, Washington,
DC, 2005.
[4] U.S. EPA, AP-42, Compilation of Air Pollutant Emission Factors,
http://www. epa. gov/oms/ap42. htm, U.S. Environmental Protection Agency Office of
Transportation and Air Quality, Washington D.C., 2005.
[5] Code of Federal Regulations (Title 40 Part 261.24) Identification and Listing of Hazardous Waste
- Toxicity Characteristic, http://www.access.gpo.gov/nara/cfr/waisidx 05/40cfr261 05.html,
U.S. Environmental Protection Agency, Washington, DC, 2005.
[6] The Climate Change Working Group of The International Council of Forest and Paper
Associations (ICFPA) Calculation Tools for Estimating Greenhouse Gas Emissions from Pulp
and Paper Mills, Version 1.1, National Council for Air and Stream Improvement, Inc. (NCASI),
Research Triangle Park, NC, July, 2005.
5-1
-------
Southern Research Institute/US EPA
April 2008
Appendix A
Unit 10 Emissions Data
A-l
-------
Southern Research Institute/US EPA
April 2008
GE
Company: University of knw
Plant
Unit 10
Test Run Number
Source Condition
Date
Start Time
Bad Time
Total Parrtcutate:
Ipaias/dsef
(Mir
lb/mmBlu(Fd**9746J
Filterable PM:
grains/dscf
Ib/hr
!MtinnBtu
-------
Southern Research Institute/US EPA
April 2008
GE
of
PowBf • Bolter 10 Outfit
Averajp
1 tiwough 4 • Cott Only
March 13 and 15, 2007
Parameter
A^@nic
Barium
BetyMuin
Cadmium
Clwomiym
Copper
iead
ManjaMss
Mercury
Nickel
Selenium
Siver
2nc
Concentration
(UnTdscfl
8.37E-10
2.82E-10
2.0SE-11
3.79E-11
1.20E-OS
2.SSE-10
3.61 E-W
1.10E-08
< 2.37E-10
1.87E-09
4.42E-09
4.EZE-11
1.SSE.«9
Emissions Rate
(Ibsflir}
2.77E-B3
9.35E-44
6.82E-O5
1256-94
4.07E413
J.67E-04
1.19E-03
3.76E43
< r.ME-04
8.40E-03
1.47E-02
1.40E-04
5.11E-03
grtijsef
S-B6E4W
1.97E-06
1.44E-07
2.656-0?
8.40E-08
181E-OS
2.53E-08
7.68E-08
< 1.68E-OS
1.31E-OS
110E-05
a,9Si-o?
1.08E-OS
ar/acf
3 426-06
1 156-08
83»E4»
1SJE-0?
4JSE-CW
1. 08E-06
1.47C-06
4.S4E-06
< 9.621-0?
7.7SE-06
1J1E-05
1736-07
6,31 £-06
litsMMBtu
(using
calculated fuel
factor)
1.226-06
4.146.06
S.016J37
8.9SE-07
I.78E-OS
3.81 E-06
$.20E-06
1.63E-OS
< 3.45E-06
2.rai-w
6.41E-OS
8.19E-07
2.266-05
ugWm*
13.418
4.518
0.329
0.807
19.213
4 1S2
S.?87
17.58$
< 3.7f8
29.B89
70.854
0.876
2476S
Test Support Data
Volumetric Ftowmlg (acfm)
.„.„_ ,.„. , , ,, .,........._.,..„_„.
..,„„ , .,._,„__„„„..,.,„„_„„
„„,„,.., .,_..,.,. ..„ , ,.._,_...
.„,._„,._._ „„„„„,.,.,„„„,„
94641
,,„.,..,.
..,„.,,.„ 7.0
... ».,. 12.3
.„_..„
A-3
-------
Southern Research Institute/US EPA
April 2008
GE
University of Iowa
Plant
10
Goal Only
13,2007
Pit*
1
2
3
•'. - '., -Tiffi? :-• -ii
08:57-09:57
12:50-13:50
15:30-16:30
Average
I-^'CC I;
£&
-------
Southern Research Institute/US EPA
April 2008
GE
of
Power
13 and 1i» 2007
:Rlftvf
1
2
3
4
5-:y: ^rtnr^ii;::
08:25-11:11
12:11-14:52
15:30-18:00
Average
07:50-10:10
'°;;° ; .•:;•!.''! :> ' .
"triir: •
:i™ *fsefm::;j:-;;
80,484
52,428
51,832
51,581
57,861
, .
"' : "' !:>••
Q»..',',
^sltaiyrK::
7.0
6.9
6.8
6.9
7.3
. :-. ;:., ••! •.. ...• "
::: ^-iCSb :' •'
h'-miijsr&s
12.4
12.4
12.5
12.4
12.0
Sippmyd
270.S
254.3
253.8
259.5
276.4
^jteU
0.473
0.442
0.438
0.451
0.486
""•iiii^ff
97.83
95.51
94.24
95.86
114.57
.--.----.-:._-:;
Run^
1
2
3
4
;;:..-':^_i.'1filttt0;^:::i:i;!:|
08:25-11:11
12:11-14:52
15:30-18:00
Average
07:50-10:10
-;:£^5:::^wwa|;;vp;- .;.
76.2
78.S
81.0
78.6
95.3
: .. '•'• .:-;-\JpOM/ :;;.•• ^;::'
:^:;:-:f;j|(jsi!ipBlu;:; ;;•;-;:§;;
0.081
0.083
0.085
0.083
0.102
.• • •'•• • '"-.'. T||:" • ;, .:;:' :,'••„'
: r- :\ ;:-'~:rs -:::»*••,:• «;s-"::':;:~ :r- •::;•:::
:s;--5-;:73?;sB»rtir£;;i; :;; ;:=s;;;
16.78
17.93
18.30
17.67
24.03
13 Fyel =
15 Fuel =
The tor 1 3 the
for run 4 the
A-5
-------
Southern Research Institute/US EPA
April 2008
GE
PARTICULATE TEST RESULTS SUMMARY
Company:
Phut:
University of
10 Duct
Test Ran i%mlxr
Souims Condition
Date
Start Time
End Time
Total Parttaiiite
gfains'dscf
Jb/hf
ih/mmBtu(Fd-"9648)
FUterabte PM:
graims/dscf
IMw
Ib/mmBtu (Fd - 9648)
Ccmdeasible PM (Method 202):
_grains/(Jscf
Ibftr
Ib/mmBtu (Fd = 9648)
Stack Parameters:
pas Volumetric Flow Rate, acfin
Gas Volumetric Flow Rite, dscfin
Average Gas Temperature, "f
Average Gas Velocity, fl/scc
Flue Gas Moisture, percent by volume
Average Flue Pressure, in. Hg
Barometric Pressure, in. Hg
Average %CO2 by votane, drv basis
Average %02 by volume, dry
Dry Molecular Wi, of Gas, tMh-niole
Gas Sample Volume, dscf
isokinctic Variance
i
75% Coal/ 25%
Wood
3/14/2007
8:20
11:00
0.0221
10.554
0,0464
0,0123
5,891
0.0259
0.0097
4.662
0.0205
95,51?
55,795
351.1
52.804
7,8
29.13
29.20
12.3
7.2
30.256
104.464
103.9
2
75% Coal/ 25%
Wiwd
3/14/2007
11:50
14:23
0.0211
9.665
0.0435
0.0112
5.143
0.0231
0.0099
4.521
0.0203
9 2,26 1
53,385
352.8
51.004
»,5
29.13
29.20
12.6
6.9
30.292
101.033
185.1
3
75% Coal/ 25%
Wood
3/14/2007
15:10
17:35
0.0200
9.380
0.0411
0.01 10
5.170
0.022<»
0.0090
4.210
0.0184
94,020
54,851
351.8
51.976
7.9
29.13
29.20
12.6
6.9
30.292
95.281
96.4
Average
0.0210
9.866
0.0436
0.0115
5.402
0.0239
0.0095
4.465
0.0198
93.933
54,67?
351,9
51.928
8.1
12J
7.0
A-6
-------
Southern Research Institute/US EPA
April 2008
GE
Untvwslty of
Main - 10 Duet
1 3 -
14,
Parameter
Arsenic
Barium
IterxHium
Cadmium
CfwemSufn
Copper
Lead
Manganese
Mercury
Nickel
Selenium
SBw
.Bne
Cancenwatisji
ifctfdseU
5.42E-10
1.S7E-W
2J7E-11
3.18E-I1
7.47E-09
3.28E-10
1. TOE- 10
1.1SE-W
2.72E-10
3-95E-09
2.»iE-fl9
4-S4E-11
1.J5E-09
Emissions Rate
(Ifcsfla)
1.S7E-03
8.4SE-04
7.4SE-OS
1.09E-04
2.63E-4J2
1.15E-03
S.87E.04
3.92E-03
S.37&04
1.39E-02
1.03E-02
1.50E-04
4.70E-03
flrfdSCl
3.79E-06
131E-06
1.82E-07
2.21 E-B7
5.23E-05
2.29C-06
1.1SE-06
TJ86.C8
1 8064)6
2-77E-OS
2-09E43S
3.04E-0?
9.44E4»
arf»ef
2^1E-08
7.62E-07
e.ssEvoa
1.2SE-07
3.05E-05
1.34E-OS
6.90E-07
4,S»E-08
1 1IE-06
1.81E-OS
1.22E-05
__JJ7EJ2_,
5.49E-06
llnMMBtu
-------
Southern Research Institute/US EPA
April 2008
GE
University of Iowa
Bolter 1i Outlet Duct
TS%Coal«§%W«Ml
14,
;SHS>
1
2
3
'!:.•• ;: Timer . ••;
08:20-09:20
11:50-12:60
15:10-16:10
Average
::: iidbf""
i*^
12.3
12.8
12.6
12.5
....-££;;-,
%.*y.'
7.2
6.9
69
7.0
'"": ffpfcbih
cfscfm
55,795
53,385
54,851
54,677
:^::^:^::^~::\:-:^:^MMs: hi ^LM:ll- - '^.
—JBISJihLi
24.848
20.451
21.655
22.318
--;-lbsife:y:
7.878
6.204
6.749
6.944
:
0.035
0.028
0.030
0.031
:^i^|?.v:
MIN;^
1
2
3
A
ilE'iTftiie" .'-^
08:20-0i^0
11:50-12:50
15:10-16:10
verage
- ~.T. rivs^"trr,3ihjjk«|iB.r;;;:r™^:::: '!;:".
, , i:-=:-r.::;r..T-|J|IIIl-..-::r.:;:;:::.-!j:.
6.944
6.005
6.855
6.601
. :.'".::'! liirJH" - " - • - - '- •- .
; ..Jfi^'Mhr"" !.-'<:
1,208
0.999
1.172
1127
!:•'•'' . •'•• ^.- /.'.'' V2f::-^ •i::"VR:'i
;i ' ;'"life/WMity"r. T.
0.005
0.005
0.005
0.005
Fuel factor = dsc&MMBtu
-------
Southern Research Institute/US EPA
April 2008
GE
of
Power Plant
Bolter 1§ Outlet Duct
7S%
14,
:RuW#
• ;• ..
1
2
3
-.• : ;• . :..
" .:\s =i;3%ne:£:ffi":K
08:20-11:00
11:50-14:23
15:10-17:35
Average
•'''••••'•fjmir ''•"'.
.::•:•: dSeflti:^.
55,795
53,385
54,851
54,677
' '"-;& ' '<
^ikSjdsiy-:.,:-'
7.2
6.8
6.9
7,0
' ' CG2 '
•V&idiyfJ-l
12.3
12.6
12.6
12.5
IHilSMttltei
277.4
305.5
2i4.4
292.4
^:;wo,^:L:.^i::i:
lis/Mliiii|^;lfis/fif r-
0.487 j 110.88
j 116.84
0.506 | 115.69
0.506 | 114.47
!iif^.::4"- "r--: .;i:4^.-.::::'::::--
jRyn J i - — ; ;IHb;7' : " ;; -
1 | 08:20-11:00
2 ! 11:50-14:23
3 | 15:10-17:35
Average
''-'y^ll:yM^*J<:
' ". :^:;:'-bffilii' -.'• -- /!.
- . - "',-;••; *T"^-!;- ~;r;' • • . . - .;:•
83.0
77,1
77.1
79.1
. .'..: ';:ijfe6.;;;l:.:,.:::L:
;:'; JBspl!iffi'''ir:-v
0.089
0.081
0.081
0.084
^Msfff^Wv
7;:7;;i;:ibsflw •.;;;;;:;••
20.19
17.95
18.43
18.86
Fuel = mm
A-9
-------
Southern Research Institute/US EPA
April 2008
Appendix B
Fuel and Ash Analyses
Fuel samples labeled as 3-13-07 represent baseline results, and fuel samples labeled 3-
14-07 represent co-fired fuel results. Ash samples labeled as Runs 1 through 3 represent
samples collected while firing straight coal, and samples labeled as Runs 4 though 7
represent samples while co-firing.
B-l
-------
Southern Research Institute/US EPA
April 2008
Kelley to insert pdf files in final report
B-2
-------
Southern Research Institute/US EPA
April 2008
Appendix C
Boiler Efficiency Determinations
c-i
-------
Southern Research Institute/US EPA
April 2008
University of Iowa Testing: Day 1, Coal only,
Run#1 03/13/2007
Combustion Calculations - Btu Method
INPUT CONDITIONS - BY TEST OR SPECIFICATION
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Excess air: at burner /leaving boiler/econ, % by weight
Entering air temperature, F
Reference temperature, F
Fuel temperature, F
Air temperature leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in air, Ib/lb dry air
Additional moisture, lb/100 Ib fuel
Residue leaving boiler/economizer, % Total
Output, 1,000,000 Btu/h (MMBtu/h)
Additional theoretical air, lb/10,000 Btu Table 14, Item [2
CO2 from sorbent, lb/10,000 Btu Table 14, Item [19]
H2O from sorbent, lb/10,000 Btu Table 14, Item [20]
Spent sorbent, lb/10,000 Btu Table 14, Item [24]
38.5
58.34
80
70.6
246.87
371.51
0.0078
0
85
224.40
0
0
0
0
COMBUSTION GAS CALCULATIONS, Quantity/10,000 Btu Fuel Input
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Theoretical air (corrected), lb/10,000 Btu
Residue from fuel, lb/10,000 Btu
Total residue, lb/10,000 Btu
20]- 21]x1151 /
FUEL - Subb luminous Coal, Iowa
15 1 Ultimate Analysis
Constituent % by weight
A C 63.77
B S 1.48
C H2 4.37
D H2O 13.76
E N2 1.45
F O2 8.16
G Ash 7.01
H Total 100.00
16 1 Theo Air, lb/100 Ib fuel
K1 | 15]xK1
11.51 734.0
4.32 6.4
34.29 149.8
-4.32 -35.3
Air 855.0
17| H2O,lb/100lbfuel
K2
8.94
1.00
H2O
18 Higher heating value (HHV), Btu/lb fue
19 Unburned carbon loss, % fuel input
20 Theoretical air, lb/10,000 Btu [16H]x 100/ [18]
21 Unburned carbon, % of fuel [19]x[18]/ 14,500
15]xK2
39.07
13.76
52.83
11,242
0.28
7.605
0.22
18 +[11]
([15G + [21]) X 100/[18]
[23] + 14]
Excess air, % by weight
Dry air, lb/10,000 Btu
H2O from air, lb/10,000 Btu
Additional moisture, lb/10,000 Btu
H2O from fuel, lb/10,000 Btu
Wet gas from fuel, lb/10,000 Btu
CO2 from sorbent, lb/10,000 Btu
H2O from sorbent, lb/10,000 Btu
Total wet gas, lb/10,000 Btu
Water in wet gas, lb/10,000 Btu
Dry gas, lb/10,000 Btu
H2O in gas, % in weight
Residue, % by weight (zero if < 0.15 lbm/10KB)
A | At Burners B| Infiltration
38.5 0.0
(1 + [25] / 1 00 X [22]
[26] X [7]
8 X 100/ [18
[17H]x 100/[18]
(100- 15G]-[21])x100/ 18]
[12]
[13]
Summation [26] through [32]
Summation [27] + [28] + [29] + [32]
33] -[34]
100x[34]/[33]
[9] X 24] / 33
EFFICIENCY CALCULATIONS, % Input from Fuel
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
C | Leaving Furnace
38.5
10.504
0.082 0.082
0.000 0.000
0.470
0.825
0.000
0.000 0.000
11.411
0.552 0.552
10.860
4.84
0.48
7.583
0.064
0.064
D | Leaving Blr/Econ
38.5
0.082
0.000
0.470
0.000
0.552
10.504
0.082
0.000
0.825
0.000
0.000
11.411
0.552
10.860
4.84
0.48
Losses
Dry Gas, %
Water from Enthalpy of steam at 1 psi, T = [6]
fuel, as fired Enthalpy of water at T = [3]
%
Moisture in air, %
Unburned carbon, %
Radiation and convection, %
Other, % (include manufacturers margin if applicable)
Sorbent net losses, % if sorbent is used
Summation of losses, %
Credits
Heat in dry air, %
Heat in moisture in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024[35D]x([6]
H1 =(3.958E-5xT
H2 = [3] -32
[29] X ([39] - [40]) /
0.0045x[27D x([6
[3])
+ 0.4329)xT+ 1062.2
00
]- 3])
[19] or [21] X 14,500 / [18]
ABMA curve, Chapter 23
From Chapter 1 0, T
able 14, Item [41
Summation [38] through [46]
0.0024x[26D]x([2]-[3])
0.0045x[27D]x([2]-[3])
(HatT[4]-HatT[3])x100/ 18]
Summation [48] through [51]
1 00 - [47] - [52]
KEY PERFORMANCE PARAMETERS
54
55
56
57
58
59
60
61
Input from fuel, 1,000,000 Btu/h
Fuel rate, 1 000 Ib/h
Wet gas weight, 1000 Ib/h
Air to burners (wet), lb/10,000 Btu
Air to burners (wet), 1 000 Ib/h
Heat available, 1,000,000 Btu/h
Ha (Btu/lb) 41.37
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100x 10]/[53
1000x[54]/[18]
[54] X [33] / 1 0
(1+[7])x(1+[25A]/100)x[22]
54 x[57]/10
54 x{([18 - 10.30 x[17H])/ 18] -0.005
X ([44] + [45]) + Ha at T[5] X [57] / 10,000}
1 000 X [59] / [56]
From Chapter 10, Fig.3 at H = [60], % H2O = [36]
1228.5
48.0
based on output of plant Btu/h
0.01 H@80~1.0
7.60
5.55
0.11
0.28
0.70
1.50
0.00
15.73
-0.55
-0.01
0.01
0.00
-0.55
84.81
Leaving Furnace
301.9
10.586
280.1
260.5
862.6
3020.0
Leaving Blr/Econ
264.6
23.5
301.9
C-2
-------
Southern Research Institute/US EPA
April 2008
University of Iowa Testing: Day 1, Coal only, Run #2 03/13/2007
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Combustion Calculations - Btu Method
NPUT CONDITIONS - BY TEST OR SPECIFICATION FUEL - Subb luminous Coal, Iowa
Excess air:
Entering air
Reference t
it burner/leaving boiler/econ, % by weight
emperature, F
smperature, F
Fuel temperature, F
Air temperature leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in
iir, Ib/lb dry air
Additional moisture, lb/1 00 Ib fuel
Residue leaving boiler/economizer, % Total
Output, 1 ,000,000 Btu/h (MMBtu/h)
Additional th
eoretical air, lb/1 0,000 Btu Table 1 4, Item [2
CO2 from sorbent, lb/1 0,000 Btu Table 1 4, Item [1 9]
H2O from sorbent, lb/1 0,000 Btu Table 1 4, Item [20]
Spent sorbent, lb/10,000 Btu Table 14, Item [24]
38.6
69.83
80 A
71 B
249.29 C
372.92 D
0.0077 E
0 F
85 G
223.90 H
0 18
0 19
0 20
0 21
COMBUSTION GAS CALCULATIONS, Quantity/10,000 Btu Fuel Input
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Theoretical air (corrected), lb/10,000 Btu
Residue from fuel, lb/10,000 Btu
Total residue, lb/1 0,000 Btu
[20]-[21 X1151 / 18] +
([15G] + [21])X100/[18]
[23] + [14]
A
Excess air, % by weight
Dry air, lb/1 0,000 Btu
H2O from air, lb/1 0,000 Btu
Additional moisture, lb/10,000 Btu
H2O from fuel, lb/1 0,000 Btu
Wet gas from fuel, lb/1 0,000 Btu
CO2 from sorbent, lb/1 0,000 Btu
H2O from sorbent, lb/1 0,000 Btu
Total wet gas, lb/1 0,000 Btu
Water in wet gas, lb/1 0,000 Btu
Dry gas, lb/10,000 Btu
H2O in gas,
Residue, %
% in weight
by weight (zero if < 0.1 5 lbm/1 0KB)
1 + [25] / 1 00) X [22]
[26] X [7]
[8] X 1 00 / [1 8]
17H]X100/[18]
1 5 | Ultimate Analysis
Constituent % by weight
C 63.73
S 1.50
H2 4.19
H2O 13.87
N2 1 .31
O2 8.71
Ash 6.69
Total 1 00.00
16 | Theo Air, lb/1 00 Ib fuel
K1 | [15]xK1
11.51 733.5
4.32 6.5
34.29 143.7
-4.32 -37.6
Air 846.1
17 | H2O, lb/1 00 Ib fuel
K2
8.94
1.00
H2O
Higher heating value (HHV), Btu/lb fuel
Unburned carbon loss, % fuel input
Theoretical air, lb/1 0,000 Btu [1 6H] x 1 00 / [1 8]
Unburned carbon, % of fuel [1 9] x [1 8] / 1 4,500
[1 5] X K2
37.46
13.87
51.33
1 1 ,287
0.27
7.496
0.21
11]
At Burners B| Infiltration
38.6 0.0
100- 15G]-[21])X100/ 18]
[12]
13]
Summation [26] through [32]
Summation [27] + [28] + [29] + [32]
[33] -[34]
1 00 X [34] / [33]
[91x1241/133]
C | Leaving Furnace
38.6
10.359
0.080 0.080
0.000 0.000
0.455
0.825
0.000
0.000 0.000
1 1 .263
0.535 0.535
10.729
4.75
0.46
7.474
0.061
0.061
D | Leaving Blr/Econ
38.6
0.080
0.000
0.455
0.000
0.535
10.359
0.080
0.000
0.825
0.000
0.000
1 1 .263
0.535
10.729
4.75
0.46
EFFICIENCY CALCULATIONS, % Input from Fuel
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
Losses
Dry Gas, %
Water from
fuel, as fired
%
Enthalpy of steam at 1 psi, T = [6]
Enthalpy of water at T = [3]
Moisture in air, %
Unburned carbon, %
Radiation and convection, %
Other, % (include manufacturers margin if applicable)
Sorbent net losses, % if sorbent is used
Summation of losses, %
Credits
Heat in dry air, %
Heat in mois ure in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024x[35d]x([6]-[3])
H1 = (3.958E-5 X T + 0.4329) X T + 1 062.2
H2 = [3] -32
[29]x([39 -[40])/100
0.0045x[27D]x([6]-[3]'
19] or[21]x14, 500/[18
ABMA curve, Chapter 23
From Chapter 1 0, Table 1 4, Item [41
Summation [38] through [46]
0.0024x[26D]x([2]-[3]'
0.0045x[27D]x([2]-[3])
(H at T[4] - H at T[3]) x 1 00 / [1 8]
Summation [48] through [51
1 00 - [47] - [52]
KEY PERFORMANCE PARAMETERS
54
55
56
57
58
59
60
61
Input from uel, 1 ,000,000 Btu/h
Fuel rate, 1 000 Ib/h
Wet gas we
ght, 1000 Ib/h
Air to burners (wet), lb/1 0,000 Btu
Air to burners (wet), 1 000 Ib/h
Heat available, 1 ,000,000 Btu/h
Ha (Btu/lb) | 41 .97
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100x[10]/[53]
1 000 X [54] / [1 8]
[54] X [33] / 1 0
1 +[7]) x (1 + [25A] / 1 00
54 X [57] / 1 0
XJ22J
54 X {([1 8] - 1 0.30 X [1 7H]) / [1 8] - 0.005
x ([44] + [45]) + Ha at T[5
1 000 X [59] / [56]
From Chapter 10, Fig. 3 a
X [57]/1 0,000)
H = [60], % H2O = [36]
1229.1
48.0
based on output of plant Btu/h
0.01 H@80~1.0
7.54
5.37
0.11
0.27
0.70
1.50
0.00
15.49
-0.25
0.00
0.01
0.00
-0.25
84.76
Leaving Furnace
297.5
10.439
275.7
260.5
875.4
3055.0
Leaving Blr/Econ
264.2
23.4
297.5
C-3
-------
Southern Research Institute/US EPA
April 2008
University of Iowa Testing: Day 1, Coal only, Run #3 03/13/2007
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Combustion Calculations - Btu Method
INPUT CONDITIONS - BY TEST OR SPECIFICATION
Excess air: at burner/leaving boiler/econ, % by weight
Entering air temperature, F
Reference temperature, F
Fuel temperature, F
Air temperature leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in air, Ib/lb dry air
Additional moisture, lb/100 Ibfuel
Residue leaving boiler/economizer, % Total
Output, 1,000,000 Btu/h (MMBtu/h)
Additional theoretical air, lb/10,000 Btu Table 14, Item [2
CO2 from sorbent, lb/10,000 Btu Table 14, Item [19]
H2Ofrom sorbent, lb/10,000 Btu Table 14, Item [20]
Spent sorbent, lb/10,000 Btu Table 14, Item [24]
37.9
74.35
80
74.8
249.86
372.753
0.0082
0
85
223.71
0 1
0 1
0 2
0 2
COMBUSTION GAS CALCULATIONS, Quantity/10,000 Btu Fuel Input
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Theoretical air (corrected), lb/10,000 Btu
Residue from fuel, lb/10,000 Btu
Total residue, lb/10,000 Btu
FUEL - Subbituminous Coal, Iowa
15| Ultimate Analysis
Constituent % by weight
\ C 61.82
3 S 1.05
D H2 4.20
D H2O 14.39
E N2 1 .20
= O2 10.95
3 Ash 6.39
-H Total 100.00
16| Theo Air, lb/1 00 Ibfuel
K1 | 15]xK1
11.51 711.5
4.32 4.5
34.29 144.0
-4.32 -47.3
Air 812.8
17| H2O, lb/100 Ibfuel
K2
8.94
1.00
H2O
8 Higher heating value (HHV), Btu/lb fuel
9 Unburned carbon loss, % fuel input
0 Theoretical air, lb/10,000 Btu [16H]x 100 /[18]
1 Unburned carbon, % of fuel 19]x 1 8] / 14, 500
[15]xK2
37.55
14.39
51.94
10,935
0.30
7.433
0.22
[20] - [21]x 1151 / [18] +[11]
([15G] +[21]) X 100/ [18]
[23]+ 14]
Excess air, % by weight
Dry air, lb/10,000 Btu
H2O from air, lb/10,000 Btu
Additional moisture, lb/10,000 Btu
H2O from fuel, lb/10,000 Btu
Wet gas from fuel, lb/10,000 Btu
CO2 from sorbent, lb/10,000 Btu
H2Ofrom sorbent, lb/10,000 Btu
Total wet gas, lb/1 0,000 Btu
Water in wet gas, lb/1 0,000 Btu
Dry gas, lb/1 0,000 Btu
H2O in gas, % in weight
Residue, % by weight (zero if < 0.15 lbm/1 0KB)
(1 + 25] / 100) X 22
[26] X [7]
[8]x 100/[18]
[17H]X100/[18]
100- 15G]-[21])X
[12]
^| At Burners B| Infiltration
37.9 0.0
100/[18]
[13]
Summation [26] through [32]
Summation [27] + [28] + [29] + [32]
[33]- 34
100x[34]/[33]
9]x 24] / 33]
C | Leaving Furnace
37.9
10.218
0.084 0.084
0.000 0.000
0.475
0.854
0.000
0.000 0.000
11.155
0.559 0.559
10.597
5.01
0.46
7.409
0.060
0.060
D | Leaving Blr/Econ
37.9
0.084
0.000
0.475
0.000
0.559
10.218
0.084
0.000
0.854
0.000
0.000
11.155
0.559
10.597
5.01
0.46
EFFICIENCY CALCULATIONS, % Input from Fuel
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
Losses
Dry Gas, %
Water from Enthalpy of steam at 1 psi, T = [6]
fuel, as fired Enthalpy of water at T = [3]
%
Moisture in air, %
Unburned carbon, %
Radiation and convection, %
Other, % (include manufacturers margin if applicable)
Sorbent net losses, % if sorbent is used
Summation of losses, %
Credits
Heat in dry air, %
Heat in moisture in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024x[35d]x([6]
H1 =(3.958E-5xT-i
H2 = [3] -32
3])
0.4329) XT + 1062.2
[29] X ([39]- [40]) / 100
0.0045x[27D]x([6]
- 3])
19]or[21]x14,500/[18]
ABMA curve, Chapter 23
From Chapter 10, Table 14, Item [41]
Summation [38] through [46]
0.0024 X[26D]X ([2]
0.0045 X[27D]X ([2]
-[3])
-[3])
(HatT[4]- HatT[3])x 100 / [18]
Summation [48] through [51
100 -[4 7] -[52]
KEY PERFORMANCE PARAMETERS
54
55
56
57
58
59
60
61
Input from fuel, 1,000,000 Btu/h
Fuel rate, 1000lb/h
Wetgasweght, 1000lb/h
Air to burners (wet), lb/1 0,000 Btu
Air to burners (wet), 1000 Ib/h
Heat available, 1,000,000 Btu/h
Ha (Btu/lb) 42.11
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100 X [10] / [53]
1000 X [54 /[18]
[54] X 33] / 1 0
1 +[7])x(1 +[25A]/100)X[22]
[54] X [57]/10
[54]x{([18]- 10.30X
17H])/ [18] -0.005
X ([44] + [45]) + Ha at T[5] X [57] / 10,000}
1000x[59]/[56]
From Chapter 10, Fig.3 at H = [60], % H2O = [36]
1229.1
48.0
based on output of plant Btu/h
0.01 H@80~1.0
7.45
5.61
0.11
0.30
0.70
1.50
0.00
15.66
-0.14
0.00
0.01
0.00
-0.13
84.47
Leaving Furnace
295.4
10.301
272.8
260.5
881.6
3063.0
Leaving Blr/Econ
264.8
24.2
295.4
C-4
-------
Southern Research Institute/US EPA
April 2008
University of Iowa Testing: Day 3, Coal only, Run #7 03/15/2007
Combustion Calculations - Btu Method
INPUT CONDITIONS - BY TEST OR SPECIFICATION
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Excess air: at burner/leaving boiler/econ, % by weight
Entering air temperature, F
Reference temperature, F
Fuel temperature, F
Air temperature leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in air, Ib/lb dry air
Additional moisture, lb/1 00 Ibfuel
Residue leaving boiler/economizer, % Total
Output, 1,000,000 Btu/h (MMBtu/h)
Additional theoretical air, lb/10,000 Btu Table 14, Item [2
CO2 from sorbent, lb/10,000 Btu Table 14, Item [19]
H2O from sorbent, lb/10,000 Btu Table 14, Item [20]
Spent sorbent, lb/10,000 Btu Table 14, Item [24]
41.1
42.09
80
69
233.95
372.14
0.0033
0
85
228.83
0
0
0
0
COMBUSTION GAS CALCULATIONS, Quantity/10,000 Btu Fuel Input
22
23
24
25
26
27
28
29
30
31
32
33
34
35
3b
37
Theoretical air (corrected), lb/10,000 Btu
Residue from fuel, lb/10,000 Btu
Total residue, lb/10,000 Btu
FUEL - Subbituminous Coal, Iowa
15 1 Ultimate Analysis
Constituent % by weight
A C 62.27
B S 1.48
C H2 4.14
D H2O 13.84
E N2 1.24
F O2 9.76
G Ash 7.27
H Total 100.00
16| Theo Air, lb/1 00 Ibfuel
K1 | [15]xK1
11.51 I 716.7
4.32 6.4
34.29 142.0
-4.32 -42.2
Air 822.9
17 1 H2O, lb/1 00 Ibfuel
K2
8.94
1.00
H2O
18 Higher heating value (H HV), Btu/lb fue
19 Unburned carbon loss, % fuel input
20 Theoretical air, lb/1 0,000 Btu [16H]x 100 /[18]
21 Unburned carbon, % of fuel [19] x [18] / 14,500
[15]xK2
37.01
13.84
50.85
11,153
0.27
7.378
0.20
[20]-[21]x1151/[18]+ 11
([15G] + [21])x100/[18]
[23] + [14]
Excess air, % by weight
Dry air, lb/10,000 Btu
H2O from air, lb/1 0,000 Btu
Additional moisture, lb/10,000 Btu
H2O from fuel, lb/10,000 Btu
Wet gas from fuel, lb/10,000 Btu
CO2 from sorbent, lb/1 0,000 Btu
H2O from sorbent, lb/1 0,000 Btu
Total wet gas, lb/10,000 Btu
Water in wet gas, lb/10,000 Btu
Dry gas, lb/10,000 Btu
H2O in gas, % in weight
Residue, % by weight (zero if < 0.15 lbm/10KB)
A At Burners B| Infiltration
41.1 0.0
(1 + 25] / 100_xJ22]
[26] x [7]
[8] x 100/[18
[17H]x100/[18]
(100 -[15G]- 21
[12]
)x 00/[18]
[13]
Summation 26 t
Summation 27 4
[33J-34]
100x 34] / 33]
[9]x[24]/[33
EFFICIENCY CALCULATIONS, % Input from Fuel
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
Trough 32
28 + 29 + [32]
C | Leaving Furnace
41.1
10.383
0.034 0.034
0.000 0.000
0.456
0.830
0.000
0.000 0.000
1 1 .247
0.490 0.490
10.757
4.36
0.51
D | Leaving
7.357
0.067
0.067
3lr/Econ
41.1
0.034
0.000
0.456
0.000
0.490
10.383
0.034
0.000
0.830
0.000
0.000
1 1 .247
0.490
10.757
4.36
0.51
Losses
Dry Gas, %
Water from Enthalpy of steam at 1 psi, T = [6]
fuel, as fired Enthalpy of water at T = [3]
%
Moisture in air, %
Unburned carbon, %
Radiation and convection, %
Other, % (include manufacturers margin if applicable)
Sorbent net losses, % if sorbent is used
Summation of losses, %
Credits
Heat in dry air, %
Heat in moisture in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024 [35D]x([E
H1 =(3.958E-5x
H2 = [3] -32
[29] x ([39] - [40])
0.0045x[27D x
]-[3])
T + 0.4329) xT+ 1062.2
/100
[6]- 3])
[19]or[21]x 14,500 / [18]
ABMA curve, Chapter 23
From Chapter 10
Table 14, Item [41]
Summation [38] through [46]
0.0024x[26D]x([2]-[3])
0.0045x[27D]x([2]-[3])
(H at T[4] - H at T[3]) x 100 / [18]
Summation [48 t
100 -[4 7] -[52
KEY PERFORMANCE PARAMETERS
54
55
56
57
58
59
60
61
Input from fuel, 1,000,000 Btu/h
Fuel rate, 1000lb/h
Wet gas weight, 1000lb/h
Air to burners (wet), lb/1 0,000 Btu
Air to burners (wet), 1000 Ib/h
Heat available, 1,000,000 Btu/h
Ha (Btu/lb) 38.21
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100 x 10]/[53]
1000x[54]/ 18]
[54] x [33]/10
Trough [51]
(1 +[7])x(1 +[25A]/100)x[22]
[54] x [57]/10
[54]x{([18]- 10.30X 17H])/[18]-0.005
X ([44] + [45]) + Ha at T[5] x [57] / 10,000}
1000x[59]/[56]
From Chapter 10
Fig. 3 at H = [60], % H2O = [36]
1228.8
48.0
based on output of plant Btu/h
0.01 H@80~1.0
7.54
5.38
0.05
0.27
0.70
1.50
0.00
15.44
-0.94
-0.01
0.01
0.00
-0.94
85.51
Leaving Furnace
301.0
10.417
278.8
262.8
873.0
2925.0
Leaving Blr/Econ
267.6
24.0
301.0
C-5
-------
Southern Research Institute/US EPA
April 2008
University of Iowa Testing: Day 2, Biomass and Coal Mix, Run #4 03/14/2007
Combustion Calculations - Btu Method
INPUT CONDITIONS - BY TEST OR SPECIFICATION FUEL - Biomass, Iowa
1
2
3
4
b
6
7
8
9
10
11
12
13
14
Excess air: at burner/leaving boiler/econ, % by weight
Entering air temperature, F
Reference temperature, F
Fuel temperature, F
Air temperature leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in air, Ib/lb dry air
Additional moisture, lb/100 Ib fuel
Residue leaving boiler/economizer, % Total
Output, 1 ,000,000 Btu/h
Additional theoretical air, lb/10,000 Btu Table 14, Item 21]
CO2 from sorbent, lb/10,000 Btu Table 14, Item [19]
H2O from sorbent, lb/10,000 Btu Table 14, Item [20]
Spent sorbent, lb/10,000 Btu Table 14, Item [24]
41.7 1b| Ultimate Analysis
53.71 Constituent % by weight
80 A C b9.83
70.667 B S 1.40
242.99 C H2 4.b4
37b.4b D H2O 13.59
0.00b6 E N2 1.23
0 F O2 12.77
8b G Ash 6.64
229.68 H Total 100.00
16| Theo Air, lb/100 Ib fuel
K1 | [1b]xK1
11.51 688.6
4.32 6.0
34.29 155.7
-4.32 -55.2
Air 79b.2
17 | H20, lb/100 Ib fuel
K2
8.94
1.00
H2O
0 18 Higher heating value (HHV), Btu/lb fue
0 1 9 Unburned carbon loss, % fuel input
0 20 Theoretical air, lb/10,000 Btu [16H]x 100/[18]
0 21 Unburned carbon, % of fuel [19] x [18] / 14,500
[1b]xK2
40.b9
13.59
54.18
10,61b
0.28
7.491
0.20
COMBUSTION GAS CALCULATIONS, Quantity/10,000 Btu Fuel Input
22
23
24
2b
26
27
28
29
30
31
32
33
34
3b
36
37
Theoretical air (corrected), lb/10,000 Btu
Residue from fuel, lb/10,000 Btu
Total residu
Excess air,
3, lb/10,000 Btu
[20]- 21]x 1151 /[18 +[11]
([1bG] + [21])x 100/[18]
[23] + [14]
A | At Burners B| Infiltration
/.by weight 41.7 0.0
Dry air, lb/10,000 Btu
H2O from air, lb/10,000 Btu
Additional moisture, lb/10,000 Btu
H2O from fu
el, lb/10,000 Btu
Wet gas from fuel, lb/10,000 Btu
CO2 from sorbent, lb/10,000 Btu
H2O from sorbent, lb/10,000 Btu
Total wet gas, lb/10,000 Btu
Water in wet gas, lb/10,000 Btu
Dry gas, lb/10,000 Btu
H2O in gas,
Residue, %
% in weight
by weight (zero if < 0. 1 b lbm/1 0KB)
(1 +[2b]/100)x[22]
[26] x [7]
[8]x100/ 18]
[17H]x 100/[18]
(100- 15G] - [21]) x 100/[18]
[12]
[13]
Summation 26] through [32]
Summation [27] + [28] + [29] + [32]
[33] - [34]
100x[34]/[33]
[9]x 24]/[33]
C | Leaving Furnace
41.7
10.b84
0.0b9 0.0b9
0.000 0.000
0.510
0.878
0.000
0.000 0.000
11.521
O.b70 O.b70
10.951
4.94
0.48
7.469
0.064
0.064
D | Leaving Blr/Econ
41.7
0.0b9
0.000
0.510
0.000
O.b70
10.b84
0.0b9
0.000
0.878
0.000
0.000
11.521
O.b70
10.951
4.94
0.48
EFFICIENCY CALCULATIONS, % Input from Fuel
38
39
40
41
42
43
44
4b
46
47
48
49
bO
51
b2
b3
Losses
Dry Gas, %
Water from
fuel, as fired
Enthalpy of steam at 1 psi, T = [6]
Enthalpy of water at T = [3]
Moisture in air, %
Unburned carbon, %
Radiation and convection, %
Other, % (include manufacturers margin if applicable)
Sorbent net
osses, % if sorbent is used
Summation of losses, %
Credits
Heat in dry air, %
Heat in moisture in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024 x [3bd] x ([6] - [3])
H1 = (3.9b8E-b x T + 0.4329) x T + 1062.2
H2 = [3]-32
[29] x ([39]- [40]) / 100
0.004b x [27D] x ([6] - [3])
[19] or 21 x 14,500 / [18
ABMA curve, Chapter 23
From Chapter 10, Table 14, Item [41]
Summation 38] through [46]
0.0024 x [26D] x ([2] - [3])
0.004bx 27D]x (2-3])
(H at T[4] - H at T 3]) x 100 / [18]
Summation [48] through [51]
100-[47]-[b2
KEY PERFORMANCE PARAMETERS
b4
bb
b6
b/
b8
b9
60
61
Input from fuel, 1,000,000 Btu/h
Fuel rate, 1000lb/h
Wet gas weight, 1000lb/h
Air to burners (wet), lb/10,000 Btu
Air to burners (wet), 1000 Ib/h
Heat available, 1,000,000 Btu/h
Ha (Btu/lb)
40.42
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100x[10]/[b3]
1000x[b4]/[18]
[54] x [33]/10
(1 +[7])x(1 + 2bA]/100)x[22]
[b4]x[b7]/10
[54] x {([18] - 0.30 x [17H]) / [18] - O.OOb
x ([44] + [45]) + Ha at T[b] x [57] / 10,000}
1000x[b9]/[b6
From Chapter 10, Fig. 3 at H = [60], % H2O = [36]
1230.3
48.0
based on output of plant Btu/h
0.01 H@80~1.0
7.77
6.03
0.08
0.28
1.70
1.50
0.00
17. 3b
-0.67
-0.01
0.01
0.00
-0.67
83.31
Leaving Furnace
317.6
10.644
293.4
268.6
84b.8
220b.O
Leaving Blr/Econ
27b.7
26.0
317.6
C-6
-------
Southern Research Institute/US EPA
April 2008
University of Iowa Testing: Day 2, Biomass and
Coal Mix, Run #5 03/14/2007
Combustion Calculations - Btu Method
INPUT CONDITIONS - BY TEST OR SPECIFICATION
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Excess air: at burner /leaving boiler/econ, % by weight
Entering air emperature, F
Reference temperature, F
Fuel temperature, F
Air tempera ure leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in air, Ib/lb dry air
Additional moisture, lb/1 00 Ib fuel
Residue leaving boiler/economizer, % Total
Output, 1,000,000 Btu/h
Additional theoretical air, lb/10,000 Btu Table 14, Item [21]
CO2 from sorbent, lb/10,000 Btu Table 14, Item [19]
H2O from sorbent, lb/10,000 Btu Table 14, Item [20]
Spent sorbent, lb/10,000 Btu Table 14, Item [24]
FUEL- Biomass, Iowa
39.2 15| Ultimate Analysis
61.82 Constituent % by weight
80 A C 60.32
71.25 B S 1.37
246.97 C H2 4.51
377.23 D H2O 13.12
0.0049 E N2 1.29
0 F O2 13.07
85 G Ash 6.32
230.03 H Total 100.00
16| Theo Air, lb/1 00 Ib fuel
K1 | 15]xK1
11.51 694.3
4.32 5.9
34.29 154.6
-4.32 -56.5
Air 798.4
17| H2O, lb/1 00 Ib fuel
K2
8.94
1.00
H2O
0 18 Higher heating value (HHV), Btu/lb fuel
0 19 Unburned carbon loss, % fuel input
0 20 Theoretical air, lb/1 0,000 Btu [16H]x 100 /[18]
COMBUSTION GAS CALCULATIONS, Quantity/10,000 Btu Fuel Input
22
23
24
Theoretical air (corrected), lb/10,000 Btu
Residue from fuel, lb/10,000 Btu
Total residue, lb/10,000 Btu
[20]-[21]x
0 21 Unburned carbon, % of fuel [19] x [18] / 14,500
[15]xK2
40.32
13.12
53.44
10,757
0.28
7.422
0.20
151 / 18]+ [11]
([15G] + [21])x100/[18]
[23UM41
25 Excess air, % by weight
26
27
28
29
30
31
32
Dry air, lb/1 0,000 Btu
H2Ofrom air, lb/10, 000 Btu
Additional moisture, lb/10,000 Btu
H2O from fuel, lb/10,000 Btu
Wet gas from fuel, lb/1 0,000 Btu
CO2 from sorbent, lb/10,000 Btu
H2O from sorbent, lb/10,000 Btu
33 Total wet gas, lb/10, 000 Btu
34 1 Water in wet gas, lb/1 0,000 Btu
35
37
Dry gas, lb/10, 000 Btu
H2O in gas, % in weight
Residue, % by weight (zero if < 0.15 lbm/10KB)
A | At Burners B| Infiltration
39.2 0.0
1 +[25]/100)x[22]
[26] x [7]
[8] x 100/[18]
[17H]x 100
100 -[15G
[12]
/[18]
- [21])x 100 /[18]
[13]
Summation
Summation
[33] - [34]
26 through 32
27 + [28] + 29 + [32
100x[34]/[33]
[9]x[24]/[33]
EFFICIENCY CALCULATIONS, % Input from Fuel
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
C | Leaving Furnace
39.2
10.304
0.050 0.050
0.000 0.000
0.497
0.869
0.000
0.000 0.000
11.224
0.547 0.547
10.677
4.88
0.46
D | Leaving
7.400
0.061
0.061
3lr/Econ
39.2
0.050
0.000
0.497
0.000
0.547
10.304
0.050
0.000
0.869
0.000
0.000
11.224
0.547
10.677
4.88
0.46
Losses
Dry Gas, %
Water from Enthalpy of steam at 1 psi, T = [6]
fuel, as fired Enthalpy of water at T = [3]
%
Moisture in air, %
Unburned carbon, %
Radiation and convection, %
Other, % (include manufacturers margin if applicable)
Sorbent net losses, % if sorbent is used
Summation of losses, %
Credits
Heat in dry air, %
Heat in moisture in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024X 35d]x([6 -[3])
H1 = (3. 958E-5XT + 0.4329) xT+ 1062.2
H2 = [3] -32
[29] x ([39]- [40]) / 100
0.0045x[27D]x([6]-[3])
19] or 21 x14,500/[18]
ABMA curve, Chapter 23
From Chapt
er 10, Table 14, Item [41]
Summation [38] through [46]
0.0024X 26D x(2 -[3])
0.0045X 27D x(2 -[3])
(HatT[4]-Ha T[3]) x 100 / [18]
Summation [48] through [51]
1 00 - [47] - [52]
KEY PERFORMANCE PARAMETERS
54
55
56
57
58
59
60
61
Input from uel, 1,000,000 Btu/h
Fuel rate, 1 000 Ib/h
Wet gas weight, 1 000 Ib/h
Air to burners (wet), lb/10,000 Btu
Air to burners (wet), 1000 Ib/h
Heat available, 1,000,000 Btu/h
Ha (Btu/lb) 41.40
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100x[10]/[53]
1000x[54]/[18]
[54] x 33]/10
(1 +[7 X (1
[54]x[57]/
[54]x{([18]
+ [25A]/ 00)x[22
0
10.30x[17H])/[18]-0.005
X ([44] + [45]) + Ha at T[5] x [57] / 10,000}
1000x[59]/[56]
From Chapter 10, Fig.3 at H = [60], % H2O = [36]
1231.1
48.0
based on output of plant Btu/h
0.01 H@80~1.0
7.62
5.88
0.07
0.28
0.50
1.50
0.00
15.84
-0.45
0.00
0.01
0.00
-0.44
84.61
Leaving Furnace
305.1
10.355
281.5
266.9
874.7
2260.0
Leaving Blr/Econ
271.9
25.3
305.1
C-7
-------
Southern Research Institute/US EPA
April 2008
University of Iowa Testing: Day 2, Biomass and Coal Mix, Run #6 03/14/2007
Combustion Calculations - Btu Method
INPUT CONDITIONS - BY TEST OR SPECIFICATION FUEL - Biomass, Iowa
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Excess air: at burner /leaving boiler/econ, % by weight
Entering air
Reference t
emperature, F
smperature, F
Fuel temperature, F
Air tempera ure leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in air, Ib/lb dry air
Additional moisture, lb/1 00 Ib fuel
Residue leaving boiler/economizer, % Total
Output, 1,000, 000 Btu/h
Additional theoretical air, lb/10,000 Btu Table 14, Item [21]
CO2 from sorbent, lb/10,000 Btu Table 14, Item [19]
H2O from sorbent, lb/10,000 Btu Table 14, Item [20]
Spent sorbent, lb/10,000 Btu Table 14, Item [24]
38.3 15| Ultimate Analysis
58.48 Constituent % by weight
80 A C 59.24
74.2 B S 1.38
244.72 C H2 4.49
376.55 D H2O 13.18
0.0041 E N2 1.11
0 F O2 14.46
85 G Ash 6.14
230.31 H Total 100.00
16| Theo Air, lb/1 00 Ib fuel
K1 | 15]xK1
11.51 681.9
4.32 6.0
34.29 154.0
-4.32 -62.5
Air 779.3
17| H2O, lb/1 00 Ib fuel
K2
8.94
1.00
H2O
0 18 Higher heating value (HHV), Btu/lb fuel
0 19 Unburned carbon loss, % fuel input
0 20 Theoretical air, lb/1 0,000 Btu [16H]x 100 /[18]
0 21 Unburned carbon, % of fuel [19] x [18] / 14,500
[15]xK2
40.14
13.18
53.32
1 0,555
0.27
7.383
0.19
COMBUSTION GAS CALCULATIONS, Quantity/10,000 Btu Fuel Input
22
23
24
Theoretical air (corrected), lb/10,000 Btu
Residue from fuel, lb/10,000 Btu
Total residue, lb/10,000 Btu
25 Excess air,
26
27
28
29
30
31
32
[20] - [21]x 1 151 / 18]+ [11]
([15G] + [21])x100/[18]
[23UM41
A | At Burners B| Infiltration
/0 by weight 38.3 0.0
Dry air, lb/1 0,000 Btu
H2Ofrom air, lb/10, 000 Btu
Additional moisture, lb/10,000 Btu
H2O from fu
el, lb/1 0,000 Btu
Wet gas from fuel, lb/1 0,000 Btu
CO2 from sorbent, lb/10,000 Btu
H2O from sorbent, lb/10,000 Btu
33 Total wet gas, lb/10, 000 Btu
34 1 Water in wet gas, lb/1 0,000 Btu
35
37
Dry gas, lb/10, 000 Btu
H2O in gas,
Residue, %
% in weight
by weight (zero if < 0.15 lbm/10KB)
(1+[25]/100)x[22]
[26] X [7]
[8]x100/ 18]
[17H]x100/[18]
(100-[15G]-[21])x100/[18]
[12]
[13]
Summation 26 through 32
Summation 27 + 28] + 29 + [32]
[33] -[34]
100x[34]/[33]
[9]x[24]/[33]
C | Leaving Furnace
38.3
10.184
0.042 0.042
0.000 0.000
0.505
0.887
0.000
0.000 0.000
11.113
0.547 0.547
10.566
4.92
0.46
D | Leaving
7.362
0.060
0.060
3lr/Econ
38.3
0.042
0.000
0.505
0.000
0.547
10.184
0.042
0.000
0.887
0.000
0.000
11.113
0.547
10.566
4.92
0.46
EFFICIENCY CALCULATIONS, % Input from Fuel
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
Losses
Dry Gas, %
Water from
fuel, as fired
Enthalpy of steam at 1 psi, T = [6]
Enthalpy of water at T = [3]
Moisture in air, %
Unburned carbon, %
Radiation and convection, %
Other, % (include manufacturers margin if applicable)
Sorbent net losses, % if sorbent is used
Summation of losses, %
Credits
Heat in dry
lir, %
Heat in moisture in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024 X 35d X ([6 - 3])
H1 =(3.958E-5xT + 0.4329)xT+ 1062.2
H2 = [3] -32
[29] X ([39]- [40]) / 100
0.0045 X [27D] X ([6] - [3])
[19 or 21]x 14,500 / [18
ABMA curve, Chapter 23
From Chapter 10, Table 14, Item [41]
Summation [38] through [46]
0.0024X 26D x([2 -[3])
0.0045 X 27D X ([2 - [3])
(HatT[4 -Ha T[3])x100/ 18]
Summation [48] through [51
1 00 - [47] - [52]
KEY PERFORMANCE PARAMETERS
54
55
56
57
58
59
60
61
Input from fuel, 1,000,000 Btu/h
Fuel rate, 1000lb/h
Wet gas weight, 1000lb/h
Air to burners (wet), lb/10,000 Btu
Air to burners (wet), 1 000 Ib/h
Heat available, 1 ,000,000 Btu/h
Ha (Btu/lb)
40.85
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100x[10]/[53]
1000x[54]/[18]
[54] X 33]/10
(1 +[7 x (1 + [25A] / 00) X [22
[54]x[57]/ 0
[54]x{([18]- 1 0.30 x[17H])/ [18] -0.005
X ([44] + [45]) + Ha at T[5] X [57] / 10,000}
1000x[59]/[56]
From Chapter 10, Fig.3 at H = [60], % H2O = [36]
1230.8
48.0
based on output of plant Btu/h
0.01 H@80~1.0
7.52
5.98
0.06
0.27
0.70
1.50
0.00
16.02
-0.53
0.00
0.01
0.00
-0.52
84.50
Leaving Furnace
302.9
10.226
278.7
266.8
880.7
2875.0
Leaving Blr/Econ
272.5
25.8
302.9
-------
Southern Research Institute/US EPA
April 2008
Appendix D
Electrostatic Precipitator Data
C-9
-------
Southern Research Institute/US EPA
April 2008
Summary of Electrostatic Precipitator Voltages
Run ID
1
2
3
4
5
6
7
Panel A
Primary
Voltage
295
301
299
294
283
278
290
Precipitator
Voltage
34
33
33
33
32
32
34
Panel B
Primary
Voltage
337
333
330
333
338
332
345
Precipitator
Voltage
36
36
36
34
36
36
36
Panel C
Primary
Voltage
333
330
330
329
326
328
330
Precipitator
Voltage
46
46
46
46
46
46
46
C-10
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