Southern Research Institute/I]SEP A
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 - Minnesota Power's Rapids Energy
Center
Prepared by:
Southern Research Institute
SOUTHERNRESEARCH Under Subcontract tO ERG
Affiliated wrtfi the
University of Alabama at Birmingham
For:
AEPA
U.S. Environmental Protection Agency
Office of Research and Development - Environmental Technology
Verification Program
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Southern Research Institute/I]SEP A
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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April 2008
THE ENVIRONMENTAL TECHNOLOGY VERIFICATION PROGRAM
Environmental and Sustainable Technology Evaluation (ESTE)
SERA
U.S. Environmental Protection Agency
SOUTHERN RESEARCH
INSTITUTE
ESTE Joint Verification Statement
TECHNOLOGY TYPE: Biomass Co-firing
APPLICATION: Industrial Boilers
TECHNOLOGY NAME: Wood Waste Co-firing With Coal
COMPANY: Minnesota Power, Rapids Energy Center
ADDRESS: Grand Rapids, Minnesota
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 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
Minnesota Power's Rapids Energy Center (REC) hosted this testing. REC provides power and heat for
the neighboring Blandin Paper Mill in Grand Rapids, Minnesota. The facility has two identical Foster
Wheeler Spreader Stoker Boilers installed in 1980 (Boilers 5 and 6). This verification was conducted on
Boiler 5. Each boiler has a steaming capacity of approximately 175,000 Ib/hour. The boilers can be fired
with western subbituminous coal supplied by Decker Coal Company, located in the northwest section of
the Powder River Basin, wood waste, railroad ties, on-site generated waste oils and solvents, and other
paper wastes. Paniculate emissions from each boiler are controlled by a Zurn multiclone dust collector
and cold side electrostatic precipitator (ESP).
Waste wood and bark from the neighboring Blandin Paper mill, as well as waste wood from other local
facilities, was co-fired with coal during this verification. The fuels (woody biomass and coal) are
conveyed to the boiler separately and mixed on the stoker. Proximate analyses of the woody biomass
used for this testing is as follows (wet weight basis):
Component % by Weight
Moisture 46.5
Ash 1.28
Fixed carbon 27.3
The average heating value of the woody biomass was 4,645 Btu/lb.
Under normal operations, each boiler generates approximately 175,000 Ib/h steam which is used to
power a 15 MW steam turbine and provide process steam to the Blandin mill. The boilers typically co-
fire woody waste, primarily bark, at a nominal coal:biomass fuel ratio of 15:85 percent. The woody
biomass waste is of sufficient supply nearly all year long with the exception of spring months. During
periods of reduced wood waste supply the facility increases the amount of coal used to fuel the boilers.
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 5:
firing coal only at a typical nominal load
firing a coal:biomass "co-firing" mixture of approximately 7:93 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
content. Presence of metals in the ash, particularly mercury (Hg), can also limit fly ash use, such as in
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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 a technical systems audit
and 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 concluded that the data meet the data quality objectives that are specified
in the Test and Quality Assurance Plan.
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VERIFICATION OF PERFORMANCE
Boiler Efficiency
Table S-1. Boiler Efficiency
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline Average
Cofire Average
Absolute Difference
% Difference
Fuel
1 00 % Coal
Blended Fuel (8
Coal; 92 Woody
biomass)
Statistically Significant Change?
Heat Input
(MMBtu/hr)
296.6
304.1
295.7
368.4
363.7
357.8
298.8
363.3
64.5
21.8%
na
Heat Output
(MMBtu/hr)
220.4
225.8
221.3
227.9
219.9
220.1
222.5
222.6
0.1
0.00%
na
Efficiency (%)
74.3
74.2
74.9
61.8
60.5
61.5
74.5 ±0.3
61. 3 ±0.7
-13.2
-17.7%
Yes
The average efficiencies during baseline (coal only) and co-firing tests were 74.5 ± 0.3 and 61.3 ± 0.7
percent respectively. This results in a statistically significant decrease of 17.7 percent efficiency when
firing the blended fuel. The mass of woody fuel needed to provide an equal amount of heat is much
greater. During baseline testing, an average 31,600 Ib/h coal was consumed. During co-firing, fuel feed
rates for coal and woody biomass averaged approximately 6,470 and 75,200 Ib/h, respectively.
Emissions Performance
Table S-2. Gaseous Pollutants (Ib/MMBtu)
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
% Difference
Fuel
1 00 % Coal
Blended
Fuel
Statistically Significant Change?
S02
0.489
0.485
0.448
0.0013
0.0014
0.0012
0.474 ±0.02
0.001 3 ±0.0001
-99.7%
Yes
C02
167
160
153
131
127
134
160 ±7
131 ±4
-18.3
Yes
NOX
0.533
0.540
0.509
0.188
0.193
0.201
0.527 ±0.01
0.1 94 ±0.007
-63.2%
Yes
CO
0.229
0.210
0.251
0.680
0.337
0.649
0.230 ±0.02
0.555 ±0.2
142%
Yes
As expected SO2 emissions were essentially eliminated using this high blend of woody biomass. NOX
emissions were also greatly reduced when co-firing (less fuel-bound nitrogen and lower thermal NOX
formation due to higher fuel moisture content, both shown in Table 3-1), and there was a statistically
significant change in CO2 emissions and a large increase in CO emissions. In similar testing at a different
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facility, wood pellets were co-fired with coal at a much lower rate (about 15 percent) and at a much lower
moisture content (about 7 percent). During that testing NOX emissions were slightly increased and CO
and CO2 emissions were not significantly impacted. The two tests serve as a useful comparison between
relatively dry and very moist woody fuels, and how this can impact emissions.
A large reduction in condensable particulates was evident while co-firing the woody fuel. Although there
was not a significant change in emissions of filterable particulates, the total particulate emission rate was
reduced by 81 percent due to the large decrease in condensable particulates.
Table S-3. Particulate Emissions (Ib/MMBtu)
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
Absolute Difference
% Difference
Fuel
1 00 % Coal
Blended Fuel
Statistically Significant Change?
Total Particulate
0.0295
0.0277
0.0379
0.0088
0.0029
0.0062
0.031 7 ±0.005
0.0060 ±0.003
-0.0257
-81.2%
Yes
Filterable PM
0.0044
0.0042
0.0049
0.0055
0.0031
0.0026
0.0045 ± 0.0004
0.0037 ±0.002
-0.0008
-17.1%
No
Condensable PM
0.0251
0.0236
0.0262
0.0050
0.0030
0.0021
0.0249 ±0.001 3
0.0034 ±0.001 5
-0.0216
-86.5%
Yes
Metals emissions were extremely low during all test periods. Changes in metals emissions on a
percentage basis were large and quite variable across the elements analyzed, including the list of eight
secondary metals. For the four primary metals shown, the reductions in mercury and selenium were
statistically significant.
Emissions of HC1 and HF were considerably lower during co-firing due the reduced levels of chlorine and
fluorine in the fuel, showing decreases of approximately 62 and 77 percent, respectively. The reductions
for both are statistically significant using the t-test.
Fly Ash Characteristics
Changes in ash characteristics were significant. Minerals content was much lower in the cofired fuel ash.
Loss on ignition was significantly higher, indicating that the woody biomass is more difficult to fully
combust. Changes in carbon content or fusion temperatures of the ash were not statistically significant.
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). Metals content was well below the TCLP requirements for all tests as
shown in Table 3-8. Ash results did not meet the Class F Requirements (C 618-05) for use in concrete
for either the baseline or co-fired fuels.
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Sustainability Issues
The REC receives woody biomass based fuel from the neighboring Blandin Mill and a wide
variety of commercial suppliers throughout the northern plains region. During the first 6 months
of 2007, the facility received a total of approximately 173,000 tons of woody biomass based fuel.
Of that, approximately 83,000 tons came from the Blandin Mill, and the remaining 90,000 tons
were purchased from commercial providers.
Fuel and emissions associated with transportation of woody biomass to the Blandin Mill are not
considered in this analysis since the woody biomass is transported to the facility whether used as
fuel or not. Collected data show that approximately 33,000 gallons of diesel fuel was used to
transport woody biomass based fuels from commercial suppliers to the REC (equating to an
estimated 0.37 gallons per ton of woody biomass delivered). Based on an Energy Information
Administration emission factor of 19.564 Ibs CO2/gallon, CO2 emissions per ton of woody
biomass based fuel transported to the facility are:
7.2 Ibs CO2 / ton woody biomass (0.37 gal fuel /ton pellets * 19.564 Ibs CO2/gal).
648 tons CO2 annually (7.2 Ib/ton * 180,000 tons woody biomass delivered annually).
Based on data generated during this testing, the CO2 emission rates while firing straight coal and
blended fuel (at a blending rate of approximately 92 percent woody biomass by mass) were 160
and 165 Ib/MMBtu, respectively. However, combustion of wood-based fuel, which is composed
of biogenic carbon, emits no appreciable CO2 emissions under international greenhouse gas
accounting methods developed by the IPCC and adopted by the ICFPA [6]. By analyzing the
heat content of the coal and the woody biomass, the total boiler heat input for the test periods, and
boiler efficiency, it was determined that approximately 90 percent of the heat generated during
co-firing test periods is attributable to the wood-based fuel. It is therefore estimated that the CO2
emissions offset during this testing is approximately 90 percent, or 148 Ib/MMBtu at this co-
firing blend. REC Boiler 5 typically operates around 220 MMBtu/hr heat generating rate.
Assuming an availability and utilization rate of 75 percent for Boiler 5 at this heat rate, this would
equate to estimated annual CO2 emission reductions of approximately 107,000 tons per year.
The mass of woody fuel needed to provide an equal amount of heat is much greater. During
baseline testing, an average 31,600 Ib/h coal was consumed. During co-firing, fuel feed rates for
coal and woody biomass averaged approximately 6,470 and 75,200 Ib/h, respectively.
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). Metals content was well below the TCLP requirements for
all tests. Ash results did not meet the Class F Requirements (C 618-05) for use in concrete for
either the baseline or co-fired fuels. As such, 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.
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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 - Minnesota Power's Rapids Energy Center (Southern
2007). Both can be downloaded from Southern's web-site (www.sri-rtp.com) or the ETV Program web-site
(ww w. epa. gov/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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April 2008
EPA Contract No. EP-C-04-056
Work Assignment No. 2-8-101
April 2008
Southern Research Institute
Environmental and Sustainable Technology Evaluation
Biomass Co-firing in Industrial Boilers
Minnesota Power's Rapids Energy Center
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
DISTRIBUTION LIST iv
ACRONYMS AND ABBREVIATIONS 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 METHODS AND 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
4.1.4 Technical Systems Audit 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 Wood Based Fuel Deliveries for Rapids Energy D-l
Appendix E Dust Collector and ESP Data E-l
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LIST OF FIGURES
Figure 2-1. Minnesota Power's Foster Wheeler Spreader Stokers 2-2
Figure 2-2. Emission Testing Ports for MP-5 2-3
Figure 2-3. Rapids Energy Woody biomass Feed 2-4
LIST OF TABLES
Table 2-1. MP-5 CEMS 2-3
Table 2-2. Rapids Energy Boiler 5 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 2-8
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 Pollutants (Ib/MMBtu) 3-3
Table 3-4. Paniculate Emissions (Ib/MMBtu) 3-3
Table 3-5. Primary Metals Emissions (Ib/MMBtu) 3-4
Table 3-6. Acid Gas Emissions (Ib/MMBtu) 3-4
Table 3-7. Ash Characteristics 3-6
Table 3-8. Ash TCLP Metals 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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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
Rapids Energy Center
Jim Uzelak
Doug Tolrud
IV
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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
REC Rapids Energy Center
Se selenium
SO2 sulfur dioxide
T tons (English)
TCLP Toxic Characteristic Leaching
Procedure.
TPM total particulate matter
TQAP test and quality assurance plan
Zn zinc
°F degrees Fahrenheit
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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
Rapids Energy Center for hosting the test, especially Compliance Superintendent Doug Tolrud, Plant
Engineer Jim Uzelak, Lead Station Operator Gordon Ranta, and Instrument and Lab Specialist Nick
Wooner. Their input supporting the verification and assistance with coordinating field activities was
invaluable to the project's success.
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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 and 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 5 at Minnesota Power's Rapids Energy Center (REC) in Grand
Rapids, Minnesota. 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 (www.sri-rtp.com) and ETV
program (www. epa. gov/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 Unit 5 at REC:
firing coal only at a typical nominal load
firing a coal:biomass "co-firing" mixture of approximately 8:92 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. The two
units that hosted tests were Minnesota Power's REC Boiler 5 (MP-5) and the University of Iowa Main
Power Plant's Boiler 10 (UI-10). Results of the UI-10 testing are published under separate cover and can
be found at www.sri-rtp.com.
Minnesota Power's REC provides power and heat for the neighboring Blandin Paper Mill in Grand
Rapids, Minnesota. The facility has two identical Foster Wheeler Spreader Stoker Boilers installed in
1980 (Boilers 5 and 6). This verification was conducted on Boiler 5. Each boiler has a steaming capacity
of approximately 175,000 Ib/hour. The boilers can be fired with western subbituminous coal supplied by
Decker Coal Company, located in the northwest section of the Powder River Basin, wood waste, railroad
ties, on-site generated waste oils and solvents, and other paper wastes. Paniculate emissions from each
boiler are controlled by a Zurn multiclone dust collector and cold side electrostatic precipitator (ESP).
Cleaned flue gas from each boiler exhausts to the atmosphere via a common stack which is 205 feet above
elevation and has an inner diameter of 9 feet. Figure 2-1 is a schematic of the boilers.
Figure 2-1. Minnesota Power's Foster Wheeler Spreader Stokers
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Since both boilers exhaust through a common stack, emission 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. Emission Testing Ports for MP-5
Under normal operations, each boiler generates approximately 175,000 Ib/h steam which is used to
power a 15 MW steam turbine and provide process steam to a nearby industrial facility. The boilers
typically co-fire woody waste, primarily bark, at a nominal coal:biomass fuel ratio of 15:85 percent. The
woody biomass waste is of sufficient supply nearly all year long with the exception of spring months.
During periods of reduced wood waste supply the facility increases the amount of coal used to fuel the
boilers. More details regarding the fuels used for this test is presented in Section 2.2.2.
Fly ash generated by this boiler is collected from the dust collector and precipitator and distributed to
farms for crop use as long as the fuel blend is less than 50 percent coal. In 2003, approximately 7,700
tons of ash was distributed to farms. When coal exceeds 50 percent, the ash is landfilled.
The systems data control system (DCS) includes a PI Historian software package that allows the facility
to customize data acquisition, storage, and reporting activities. Each boiler is also equipped with
continuous emission monitoring systems (CEMS) that record NOX, SO2, CO, and O2 concentrations and
emission rates. Table 2-1 summarizes the CEMS on each boiler.
Table 2-1. MP-5 CEMS
Parameter
NOX
SO2
CO
02
Instrument Make/Model
Teledyne Monitor Labs
(TML) 41-H-O2
TML 50-H
TML 30-M
TML 41-H-O2
Instrument Range
0 - 500 ppm
0 - 1000 ppm
0 - 5000 ppm
0 - 25 %
Reporting Units
Ib/MMBtu
Ib/MMBtu
Ib/MMBtu
%
The facility has a fully equipped control room that continuously monitors boiler operations. 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)
SO2 emissions (Ib/MMBtu)
ESP variables (volts, amperes, fields on line), recorded manually
Data recorded during each test period was averaged over the test period and reported 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. Dust collector and ESP operational data
are summarized in Appendix E.
2.2 FIELD TESTING
Waste wood and bark from the neighboring Blandin Paper mill, as well as waste wood from other local
facilities, was co-fired with coal during this verification. The fuels (woody biomass and coal) are
conveyed to the boiler separately and mixed on the stoker. Figure 2-3 shows the woody biomass
conveyer during verification testing.
Figure 2-3. Rapids Energy Woody biomass Feed
Proximate analyses of the woody biomass used for this testing is as follows (wet weight basis):
Component
Moisture
Ash
Fixed carbon
% by Weight
46.5
1.28
27.3
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The average heating value of the woody biomass was 4,645 Btu/lb. These values are the average of three
composite samples collected on the day of testing and may not reflect variability in the woody biomass
used at REC.
2.2.1 Field Testing Matrix
A set of three replicate tests were conducted while firing coal only on March 28, 2007. The following
day, a second set of three tests were conducted while firing primarily woody biomass co-fired with a
small amount of coal. Duration of each test run was approximately 120 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. Table 2-2 summarizes the test
matrix.
Table 2-2. Rapids Energy Boiler 5 Test Periods
Date
03-28-07
03-29-07
Time
0940-1215
1250-1520
1555- 1825
0815- 1050
1228- 1500
1520- 1750
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Fuel
1 00 % coal
Blended Fuel
(8 % Coal; 92
% woody
biomass)
Heat Input
(MMBtu/h)
296.6
304.1
295.7
293.5
285.2
285.6
Steam Flow
(Klb/h)
153.6
157.3
154.2
159.2
153.7
153.9
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 METHODS AND 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 Btu 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
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.
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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 woody
biomass 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)
Fuel feed rates were monitored during the verification testing to confirm fuel blending rates (fuel feed rate
is not required for the boiler efficiency calculations via the Btu method). Woody biomass feed rates to
the boiler are monitored by the site using a belt scale. Coal firing rates are determined by counting and
recording the number of hopper releases over a given period of time, and assigning an assumed mass of
coal per release. The coal feed rate data were later determined to be invalid. Therefore, fuel blending rate
was derived using the total calculated heat input, the measured woody biomass feed rate, and the
measured heating value of the woody biomass and the coal.
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 (coal and woody biomass separately) were collected from the fuel conveyers
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 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
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with completed chain-of-custody documentation for off-site analysis. These samples were submitted to
the field team leader for subsequent analysis. The ultimate analysis reported the following fuel
constituents as percent by weight (wet):
carbon sulfur hydrogen
water nitrogen 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 Btu method.
2.3.2 Boiler Emissions
Testing was conducted on each boiler to determine emissions of the following atmospheric pollutants:
nitrogen oxides (NOX) carbon monoxide (CO) secondary metals
sulfur dioxide (SO2) carbon dioxide (CO2) acid gases (HC1, HF)
particulate matter primary metals (As,
(filterable and Hg, Se, Zn)
condensable)
Emission rates for NOX, SO2, and CO were determined continuously using the facility's continuous
emissions monitoring system (CEMS). For all other parameters, a total of three replicate test runs were
conducted under both the baseline (coal only) and co-firing operating conditions. Each test run was
approximately 120 minutes in duration.
Measurements required for emissions tests include:
fuel heat input, Btu/h (via boiler efficiency, Section 2.3.1)
pollutant and O2 concentrations, parts per million (ppm), grains per dry standard
cubic foot (gr/dscf), or 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 (dscfh)
The average concentrations established as part of each test run are reported in units of ppmvd for NOX,
CO, SO2, HC1, and HF, and percent for CO2. Concentrations of total particulate matter are reported as
grains per dry standard cubic foot (gr/dscf). 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.
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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
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 from the 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, and air-
entraining agents index. 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
Air-entraining agents index
Fly ash fusion temperature
Method
ASTM D5373
ASTM D4326-04
SW-846 3052/60 10
SW-846 1311/6010
Foam Index Test
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 Rapids Energy facility. 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)
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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 for each site. The source, type,
and compositional analyses of the biomass was documented during testing.
Associated GHG 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 CC>2 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
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. Field and analytical data generated
during the verification are presented in Appendices A through D including detailed emissions testing data,
fuel and ash analyses, boiler efficiency calculations, and REC woody biomass delivery records. As
expected, the facility was able to operate under both conditions (coal only and co-firing) without
difficulties. Due to lack of demand from the host paper mill, all testing was conducted at approximately
88 percent of boiler capacity (approximately 155,000 Ib/h steam). Using the total calculated heat input,
the measured woody biomass feed rate, and the measured heating value of the woody biomass and the
coal, the fuel blending rate was determined to be an average of 8 percent coal and 92 percent woody
biomass during co-firing.
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
Cofire 1
Cofire 2
Cofire 3
Baseline
Averages
Cofire
Averages
% Difference
Fuel
100% Coal
Blended
Fuel (8
Coal; 92
woody
biomass)
Moisture
(%)
23.5
23.6
23.9
43.6
46.0
44.7
23.7
44.8
89.2%
Carbon
(%)
54.2
54.8
54.4
29.6
29.0
29.4
54.5
29.3
-46.2%
Nitrogen
(%)
0.93
1.12
0.54
0.30
0.42
0.44
0.86
0.39
-55.2%
Sulfur
(%)
0.33
0.33
0.33
0.04
0.05
0.04
0.33
0.04
-86.9%
Ash (%)
3.95
3.59
3.98
1.65
1.16
1.79
3.84
1.53
-60.1%
Heating
Value
(Btu/lb)
9,445
9,491
9,422
5,025
4,930
5,085
9,453
5,014
-47.0%
As expected, the moisture content of the blended fuel was much higher than the coal, and carbon, ash and
heating values were much lower.
The average efficiencies during baseline (coal only) and co-firing tests were 74.5 ± 0.3 and 61.3 ± 0.7
percent respectively. This results in a statistically significant decrease of 17.7 percent efficiency when
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firing the blended fuel. Combustion appeared to occur higher up the boiler with; 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
Cofire 1
Cofire 2
Cofire 3
Baseline Average
Cofire Average
Absolute Difference
% Difference
Fuel
100% Coal
Blended Fuel (8
Coal; 92 Woody
biomass)
Statistically Significant Change?
Heat Input
(MMBtu/hr)
296.6
304.1
295.7
368.4
363.7
357.8
298.8
363.3
64.5
21.8%
na
Heat Output
(MMBtu/hr)
220.4
225.8
221.3
227.9
219.9
220.1
222.5
222.6
0.1
0.00%
na
Efficiency (%)
74.3
74.2
74.9
61.8
60.5
61.5
74.5 ±0.3
61.3±0.7
-13.2
-17.7%
Yes
The mass of woody fuel needed to provide an equal amount of heat is much greater. During baseline
testing, an average 31,600 Ib/h coal was consumed. During co-firing, fuel feed rates for coal and woody
biomass averaged approximately 6,470 and 75,200 Ib/h, respectively.
3.2 BOILER EMISSIONS
Table 3-3 summarizes emission rates for the gaseous pollutants evaluated. As expected SO2 emissions
were essentially eliminated using this high blend of woody biomass. NOX emissions were also greatly
reduced when co-firing (less fuel-bound nitrogen and lower thermal NOx formation due to higher fuel
moisture content, both shown in Table 3-1), and there was a statistically significant change in CO2
emissions and a large increase in CO emissions. In similar testing at a different facility, wood pellets
were co-fired with coal at a much lower rate (about 15 percent) and at a much lower moisture content
(about 7 percent). During that testing NOX emissions were slightly increased and CO and CO2 emissions
were not significantly impacted. The two tests serve as a useful comparison between relatively dry and
very moist woody fuels, and how this can impact emissions.
Regarding CO2 emissions, it should be noted that combustion of wood-based fuel, which is composed of
biogenic carbon, emits no appreciable 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)
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Table 3-3. Gaseous Pollutants (Ib/MMBtu)
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
% Difference
Fuel
100% Coal
Blended
Fuel
Statistically Significant Change?
S02
0.489
0.485
0.448
0.0013
0.0014
0.0012
0.474 ±0.02
0.0013 ±
0.0001
-99.7%
Yes
C02
167
160
153
131
127
134
160 ±7
131 ±4
-18.3
Yes
NOX
0.533
0.540
0.509
0.188
0.193
0.201
0.527 ±
0.01
0.194 ±
0.007
-63.2%
Yes
CO
0.229
0.210
0.251
0.680
0.337
0.649
0.230 ±
0.02
0.555 ±
0.2
142%
Yes
Table 3-4 summarizes results of filterable, condensable, and total paniculate emissions.
Table 3-4. Particulate Emissions (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
Statistically Significant Change?
Total Particulate
0.0295
0.0277
0.0379
0.0088
0.0029
0.0062
0.0317 ±0.005
0.0060 ±0.003
-0.0257
-81.2%
Yes
Filterable PM
0.0044
0.0042
0.0049
0.0055
0.0031
0.0026
0.0045 ±0.0004
0.0037 ±0.002
-0.0008
-17.1%
No
Condensable PM
0.0251
0.0236
0.0262
0.0050
0.0030
0.0021
0.0249 ±0.001 3
0.0034 ±0.0015
-0.0216
-86.5%
Yes
A large reduction in condensable particulates was evident while co-firing the woody fuel. Although there
was not a significant change in emissions of filterable particulates, the total particulate emission rate was
reduced by 81 percent due to the large decrease in condensable particulates. Dust collector and ESP
operational data presented in Appendix E indicate that conditions were consistent between the two sets of
runs with regard to control device operations.
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Table 3-5. Primary Metals Emissions (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
Statistically Significant Change?
Arsenic
9.61 E-07
2.11E-06
8.12E-07
4.83E-07
4.67E-07
4.89E-07
1.29E-06±
7.71 E-07
4.80E-07±
8.42E-09
-8.15E-07
-62.9%
No
Mercury
2.44E-06
2.40E-06
2.07E-06
9.39E-07
7.84E-07
8.33E-07
2.30E-06 ±
2. 01 E-07
8.52E-07 ±
9.36E-08
-1.45E-06
-63.0%
Yes
Selenium
2.04E-06
2.13E-06
2.35E-06
6. 11 E-07
8.83E-07
9.05E-07
2.18E-06±
1.60E-07
8.00E-07 ±
2.10E-07
-1.38E-06
-63.2%
Yes
Zinc
2.56E-05
1.53E-05
1 .45E-05
1.91E-05
2.51 E-05
2.20E-05
1.84 E-05 ±
6.20E-06
2.21 E-05 ±
4.04E-06
3.64E-06
19.5%
No
Metals emissions (primary metals summarized in Table 3-5) were extremely low during all test periods.
Changes in metals emissions on a percentage basis were large and quite variable 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.
For the four primary metals shown, the reductions in mercury and selenium were statistically significant.
Acid gas emissions are summarized below. Emissions of HC1 and HF were considerably lower during
co-firing due the reduced level of chlorine in the fuel. The reductions for both are is statistically
significant using the t-test.
Table 3-6. Acid Gas Emissions (Ib/MMBtu)
Test ID
Baseline 1
Baseline 3
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
Absolute Difference
% Difference
Fuel
100% Coal
Blended Fuel
Statistically Significant Change?
Hydrochloric
Acid, HCI
4.83E-04
6.07E-04
5.45E-04
3.35E-04
1.45E-04
1.37E-04
5.45E-04 ±
6.21 E-05
2.06E-04 ±
1.12 E-04
-3.39E-04
-62.3%
Yes
Hydrofluoric
Acid, HF
2.18E-03
2.25E-03
2.07E-03
6.08E-04
3.74E-04
5.06E-04
2.17E-03±
9. 11 E-05
4.96E-04 ±
1.17E-04
-1.67E-03
-77.1%
Yes
3-4
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Southern Research Institute/I]SEP A
April 2008
3.3 FLYASH CHARACTERISTICS
Results of the flyash analyses are summarized in Tables 3-7 through 3-9. Changes in ash characteristics
were significant. Minerals content was much lower in the cofired fuel ash. Loss on ignition was
significantly higher, indicating that the woody biomass is more difficult to fully combust. Changes in
carbon content or fusion temperatures of the ash were not statistically significant.
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). Metals content was well below the TCLP requirements for all tests as
shown in Table 3-8. Ash results did not meet the Class F Requirements (C 618-05) for use in concrete
for either the baseline or co-fired fuels.
3-5
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Southern Research Institute/I]SEP A
April 2008
Table 3-7. Ash Characteristics
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
% Difference
Fuel
100%
Coal
Blended
Fuel
Statistically Significant Change?
Carbon, wt
%
7.11
8.34
9.00
8.49
10.3
9.57
8.15 ±0.9
9.47 ±0.9
14.9%
No
Silicon
Dioxide, %
as SiO2
14.2
12.9
13.8
7.83
6.21
6.13
13.6 ±0.7
6. 72 ±0.9
-67.9%
Yes
Aluminum
Oxide, % as
AI203
7.99
8.48
9.84
3.81
3.23
3.01
8.77 ±0.9
3.35 ±0.4
-89.4%
Yes
Iron
Oxide, %
as Fe2O3
2.40
2.48
2.76
1.38
1.30
1.25
2.55 ±
0.2
1.31 ±
0.07
-64.1%
Yes
Loss on
Ignition
12.1
11.3
11.1
16.2
18.3
17.9
11.5±
0.5
17.5±
1.1
41.0%
Yes
Ash Fusion Temp., °F
Reducing
Atmosphere:
Initial
Deformation
2,332
2,188
2,181
2,402
2,390
2,388
2,234 ± 85
2,393 ±6
6.90%
No
Oxidizing
Atmosphere:
Initial
Deformation
2,310
2,328
2,334
2,393
2,692
2,005
2, 324 ±12
2,363 ± 340
1 .68%
No
3-6
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Southern Research Institute/I]SEP A
April 2008
Table 3-8. Ash TCLP Metals
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Baseline Averages
Cofire Averages
Fuel
100% Coal
Blended
Fuel
Limit/ 40 CFR 261. 24
Silver,
mg/L
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
< 0.001
5.0
Arsenic,
mg/L
0.003
0.008
0.016
0.005
0.004
0.003
0.009
0.004
5.0
Barium,
mg/L
0.27
0.21
0.38
0.30
0.37
0.35
0.29
0.34
100.0
Cadmium,
mg/L
0.001
0.002
0.002
<0.001
<0.001
<0.001
0.002
< 0.001
1.0
Chromium,
mg/L
0.05
0.06
0.079
0.069
0.095
0.096
0.06
0.09
5.0
Mercury,
mg/L
< 0.001
< 0.001
0.002
<0.001
<0.001
<0.001
< 0.002
< 0.001
0.2
Lead,
mg/L
0.02
< 0.001
< 0.001
0.012
0.011
0.012
<0.02
0.01
5.0
Selenium,
mg/L
0.10
0.10
0.14
0.094
0.091
0.094
0.11
0.093
1.0
3-7
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Southern Research Institute/I]SEP A
April 2008
Table 3-9. Fly Ash Class F Requirements (C 618-05)
Test ID
Baseline 1
Baseline 2
Baseline 3
Cofire 1
Cofire 2
Cofire 3
Class F Requirements
Baseline Averages
Cofire Averages
Absolute Difference
% Difference
Fuel
100% Coal
blended
FIIP!
Silicon
Dioxide
(SIO2) +
Aluminum
Oxide (AI2O3)
+ Iron Oxide
(Fe2O3), (%)
24.63
23.82
26.42
13.02
10.74
10.39
70.0 (min %)
24.96
11.38
-13.57
-74.7%
Sulfur
Trioxide
(S03), (%)
14.21
18.12
19.58
10.15
11.35
10.27
5.0 (max %)
17.30
10.59
-6.71
-48.1%
Loss on
ignition,
(%)
12.13
11.32
11.12
16.24
18.25
17.92
6.0 (max
%)
11.52
17.47
5.95
41.0%
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 woody biomass fuel at this site.
3.4.1 GHG Emission Offsets
Energy Used and Associated CO? Emissions to Harvest, Process, and Shred Wood-Based Fuel
The woody biomass fuel used at RFC has a significant level of energy use and associated CO2 emissions
to harvest, process, and shred the timber prior to transportation to the site. However, since the woody
biomass used at RFC comes from such a wide variety of suppliers, both geographically and
organizationally, estimation of this portion of the GHG offset analysis was well beyond the scope of this
project, and therefore not considered here.
Transportation Fuel Use
The RFC receives woody biomass based fuel from the neighboring Blandin Mill and a wide variety of
commercial suppliers throughout the northern plains region. During the first 6 months of 2007, the
facility received a total of approximately 173,000 tons of woody biomass based fuel. Of that,
approximately 83,000 tons came from the Blandin Mill, and the remaining 90,000 tons were purchased
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Southern Research Institute/I]SEP A
April 2008
from commercial providers. Appendix D summarizes the woody biomass deliveries to the REC during
this period.
Fuel and emissions associated with transportation of woody biomass to the Blandin Mill are not
considered in this analysis since the woody biomass is transported to the facility whether used as fuel or
not. The data in Appendix D show that approximately 33,000 gallons of diesel fuel was used to transport
woody biomass based fuels from commercial suppliers to the REC (equating to an estimated 0.37 gallons
per ton of woody biomass delivered). The analysis assumes trucks using 350 Cummins motors or
equivalent were used to transport the fuel at an estimated fuel economy of 6.5 miles per gallon.
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 woody biomass based fuel transported to the facility are:
7.2 Ibs CO2 / ton woody biomass (0.37 gal fuel /ton pellets * 19.564 Ibs CO2/gal).
648 tons CO2 annually (7.2 Ib/ton * 180,000 tons woody biomass delivered annually).
CO? Emissions from Combustion of Bituminous Coal Compared to Woody biomass
Based on data generated during this testing, the CO2 emission rates while firing straight coal and blended
fuel (at a blending rate of approximately 92 percent woody biomass by mass) were 160 and 165
Ib/MMBtu, respectively. However, combustion of wood-based fuel, which is composed of biogenic
carbon, emits no appreciable CO2 emissions under international greenhouse gas accounting methods
developed by the IPCC and adopted by the ICFPA [6]. By analyzing the heat content of the coal and the
woody biomass, the total boiler heat input for the test periods, and boiler efficiency, it was determined
that approximately 90 percent of the heat generated during co-firing test periods is attributable to the
wood-based fuel. It is therefore estimated that the CO2 emissions offset during this testing is
approximately 90 percent, or 148 Ib/MMBtu at this co-firing blend.
REC Boiler 5 typically operates around 220 MMBtu/hr heat generating rate. Assuming an availability
and utilization rate of 75 percent for Boiler 5 at this heat rate, this would equate to estimated annual CO2
emission reductions of approximately 107,000 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, but
this type of complex analysis was not included in the scope of this study.
3-9
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Southern Research Institute/I]SEP A
April 2008
4.0 DATA QUALITY ASSESSMENT
4.1 DATA QUALITY OBJECTIVES
Under the ETV 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.
4-1
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Southern Research Institute/I]SEP A
April 2008
Table 4-1. Summary of Emission Testing Calibrations and QA/QC Checks
Parameter
C02,
NOX,
CO,
SO2,
O2
TPM,
Metals
Metals
HC1,
HF
Calibration/QC Check
Analyzer calibration
error test
System bias checks
System calibration drift
test
Relative accuracy test
audit
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 (last RATA
April 17, 2006)
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
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 accuracies for
NOX, CO, SO2, and O2
CEMS were 11. 7, 3.0,
1.0, and 0.2 percent,
respectively
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
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Southern Research Institute/I]SEP A
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
Invalidated for coal
scales, but not used
for determining
efficiency
Method
repeatability criteria
were met
4.1.4 Technical Systems Audit
A technical systems audit was conducted during the week of March 26-30, 2007 at the REC facility in
support of this verification. The audit was conducted in accordance with SRI's recently drafted
4-3
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Southern Research Institute/I]SEP A
April 2008
ETV/ESTE project QA guideline. The audit was conducted remotely by the quality assurance manager,
Eric Ringler, with the assistance of project staff member, Sarah Fisher, in the field.
Prior to the audit, the QAM developed an audit check-matrix listing each measurement to be conducted
and the audit criteria to be examined. Before leaving for the field, the QAM and field technician went
through the check-matrix and audit procedures to ensure good coordination of the audit. The field
technician examined the check matrix to verify it was consistent with the TQAP and with expected field
conditions. She also determined key test parameters for the audit. According to the project QA guideline,
an audit is considered complete if all key measurements are audited and spot checks conducted for the
remaining measurements.
During field measurements, the QAM and field technician discussed audit progress and findings on a
daily basis by telephone. One deviation from the test plan was noted. Ash samples were collected from
the ESP hopper instead of directly from the stack. The impact of this on data quality is unknown, but
considered to be minor, since ash composition is an ancillary measurement and not one of the verification
parameters. There is some concern about the representativeness of the samples. A corrective action
report was completed.
Apart from this, all audit criteria were satisfied for all key and other audited parameters. The audit was
very thorough and went well beyond the minimum required for a successful audit. The completed check-
matrix and corrective action report is documented at Southern.
4-4
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Southern Research Institute/I]SEP A
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
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Southern Research Institute/I]SEP A
April 2008
Appendix A
Unit 5 Emissions Data
A-l
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Southern Research Institute/I]SEP A
April 2008
Company:
Plant:
Unit:
Power
MN
Boiler 3 Duct
Test Run Number
Source Condition
Date
Stan Taut-
End T;;ue
Total Pnrticulate:
iiTiius divf
Is hi
Filterable PM:
intuis dicf
Ib hr
Co&dereibk PM (Method 202):
a'sius dvcf
Is Ill-
Stack Parameters:
Cms \ clia:wtric Flov.' Rate, ricihi
Cm* Yohaiisu'ic Flov.- Rate, dicfm
Average Gas T-fEiper?.ti'a'e. ~F
Average Gas Yeloatv. ft sec
Fine C-RS Monnire. werceut CA- rohane
Averaee Fh;e ?re>;ure. m. Hs
Barcnie-tnc Pre'sare. 1:1 Es
Averaee r'.;C'O- b^- vchuiie. cln'Kiiii
Avesaae ''oO- bvvoiraae. dr.- ba=.i5.
Df\- N-Ickciilar Vv~t. of G. Ib '.ci-iuole
Gas Sscwle Volume- dscf
Koktuetic \ arwuCv
I
Cos!
9-M
12:12
&.CI6?
S.74i
D.C025
I..2 10
0.0141
7.432
396. 1
41 .339
7 9
Xl 77
29. ~9
12 ^
7.5
30.332
99.601
101.9
1
Coal
U3 2S- 2uO<
12:4"
1 5 : l-»
0.0159
8.432
0.0024
1.266
0.0135
7166
109.584
61.S72
402.3
41.528
7.3
29.77
29.79
12.4
7.3
30.276
96.953
98.8
3
Coal
(! 28 2UU
15:54
1S:22
0.0225
11.214
0.0029
1.461
0.0195
9.753
i03.:02
58.209
3S9.4
59.223
S.C
2^. ; .'
"S ^9
^ "* i
- 7
j-v.276
S9.C41
9C\4
A\*erage
o.oiss
9.462
0.0026
1.346
0.0157
8.117
107.391
60.573
399.3
40.697
7.8
12.5
7 "i
A-2
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Southern Research Institute/I]SEP A
April 2008
Energy Center, Grand Rapids, MN
Boiler No. 5 Ouact
Average Results
1 through 3
3/28/07
Parameter
Arsenic
Barium
Beryllium
Cadmium
Chromium
Zinc
Copper
Lead
Manganese
Mercury
Nickel
Selenium
Stiver
Concentration
1.10E-10
<
< 7.11E-12
1 1
<
1
3.78E-10
< 3.78E-11
1 ,§?E~Qi
1.95E-10
<
1.85E-10
<
Emissions Rate
(Ibs/hr)
3.89E-Q4
<
<
S.83E-QS
<
5.51E-03
1
< 1
5.56E-03
8.89E-Q4
< 1
6.50E-04
< 7.17E-04
grfdscf
7.72E-0?
<
<
1.16E-07
1.12E-06
1
2.65E-06
<
1.10E-05
1 ,37E^06
1
< 1
griacf
4.31 E-07
<
<
6.48E-08
<
S.08E-08
1
< 1
6.16E4«
7.85E-07
<
7.24E-07
*
y§/Mm3
1.768
<
< 0.114
0.268
< 2.557
24.808
6.061
<
25.200
3.131
<
2.i6§
<
A-3
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Southern Research Institute/I]SEP A
April 2008
Project; MinnisQt«i Power
Location: Gullet Duet
Smirasi Bolef 5
Test Number;
Pressure. StackfHg' I:,..,..,.,,....,,.,,.,,.,,.....
Meter Teitip-erature |T),,,. .,..,...-.,
Meter f illbratiori i₯s..,.-. ..., .,--
Dry Standard Flow Rate (d&cfm):.. .......
Test Number:
Piessure, BarorRetiic^Hu"1):,,..,,,, ,,..,.
Pressure, Ste.,,. .,.,.,,. ,.. .,
Average Delia H (AH|
HCt Ifea/tun
HCt
MCI
ftwerjg* Ftow (dsclimj
2S TEST
Condition; Coal
Taken By MB
Fuel Factor:
29.7&0
686 * 22
6*3 - 3 1
81,839
-.
29.7&0
£ 359 74
7119 82
4 159
: a:s
caic
81,872
3
29.790
-0,25
29,772
7121.170
?24!,1iO
77.20
4.169
1,005
DJ10
58,209
4
29.790
-0,25
29.772
?24t,840
7361.700
76.40
4 161
t.QOS
0.010
58,209
r, r"^
. tr_iT
OO:DO
Time:
Csfbon Dioxide Contentl'ii;,.,, ......
HCI :mg],. ,., . ,.., ., ,.. ..
HF (ppm):», .,.,.,<,»»,.,«,.,,,*,,.
HF (Ebs>'*iF}:. ...... ..... ..... ...... ......
HCI !>bs hij- .. , .... ... ,..,..,. .
HF (lbS''MWiBtM}'
HCI r»s:MMBtuJ:... ..........................
Time:
Carbon Dioxide Ctmte-ntlVj:,..,, ..,.,,
HF (rng?
HCI !mgi . ..=.. .... ,. ,. ...... ,. ,. ....
HF i'Jl>S''tif *>'
HCI Ob**' *'hr) "..,., .... ,.. .,.. ,.
HF (ibs^«1!VSB*u}'
HCI nb&'MMBtu^*
Time:
HF fmgj
HCI fmgi., .., .,. ,.., .. ,.. ....
HF i'H3S''fiM;,. .....................................
HCI |5fos hr) , .... , .,..,. ,.
HF ?tbS''MMB*u):..... ...» "- ....,..,.
HCI ^bS'MMBtu1'
Time;
HF ImgJ..,.. ..... .,.,. ,... ....-, . ..
HCI Img'i
HF ilbs.'liM;,. ............. .......................
HCI nbs'hrt',,.,. .,.., ..... ,.., ...... ,.
HF (Ihs^MMBUf't*
HCI :JI>s;MMBtti;:,, ,.. .., ., ,..
Average HFIbs.lif.
Average HF ppm:
Average HF IbsMMBtu:
i:-'~'11-^5
....................... '2./0
7Ci ftfi
,.<«...«<» 0 748
-. jjc,,-,
..... ..... ..... ... 0 1-S33
........................ o.:ooo
12:4-13:4
....................... ^2.40
o--* ^"i
, ,. ,. ,. ,. ,. , u -*4
n ^mT
n "7Q3
.,. ..... .,..., ,. ,. n ic'0
Q -n«:.3-
n ^Qn-3
15:54-16:54
,......,.,«... "230
7 ?Tj
8-^ Ctf*
0 IDn
. ...... ...... ..... n vn
,«.i,^....<*>,t, 1 §1S
........................ n |64?
, ,., , ,, o SPA
,-, "0s;...-*'"-
0 "00n
17:02-18:02
-. -i
... ... ...... -. 0 ".C.T
0 330
0 PF.7
....,.,.,..,. ..... -.. ' *-s*
........................ n ifO
n - -
n -T^^..-*-
, ..... ..... ....... 0 "000
0.1422
0.768
O.OOE-i-OfJ
A-4
-------
Southern Research Institute/I]SEP A
April 2008
Company:
Plant:
Unit;
Power
MX
Boiler 5 Outlet Duct
Test Run Nnmbcr
Source CcndifiO;;
Date
Stsrr Time
End T;me
I
l?s,;CcaKt
S,5«c, 3:.rk
03 29 2007
3:17
10:4?
2
I:>':o Coal &
Sf'^-Bark
03 2? 2007
!2:2S
14:: 6
3
15"fCeal&
SfoBark
,;";; i<.) ~>£,{\'1
15:21
P:4S
Average
Total Particular:
src^uis cUci
ft to-
0-005;-
5.2.50
0 0037
2 0-3
o.-:c?:
1.S42
0.0041
2.3S1
Filtei able PM:
si'ain-. cUcf
ID b-
0.0017
1.039
0.0021
1.125
0.001?
1.0S1
0.0019
1.082
Condemible PM (Method 202):
srciin*. die f
ib In
:'; OH 1 7
i ^ ^ ^
0.0017
0.918
0.0013
0.761
0,0022
1,300
Stack Parameters:
Ga% Yoluinefric Flmv Rate. ?.cihi
Ga> \"clr,irietic Flev," Rste. dicfm
Average Gas Teiriperr-.nu'e. :F
A'/erase &as Velccir,". ft vec
Flue Gas -vio>«-rure- oerceiit bv volume
A\-era2? Fh-.? ?re%in:'e. 10. Ha
Baic.inetric ?re%«.n:'e. m Ez
Average :'cCO- bv vohuae. cVv b.isis
Average 5cO- b-v volume. on.'bii«i4
Dn- M'kculai Wr. cf Gas. Ib lb-inole
&a% Ssiapie \'chuwe. ckcf
rickmenc A"?.riance
147A-2
69.~6y
457 S
56.06S
P.?'
29. S7
29. SO
12.3
- --,
r.C.2(«
121 722'
11 CO
131.836
64,032
444.7
40.961
16.6
29.S7
29.80
12.6
7 T1
30.304
77.515
95.0
137.161
66,791
446.4
51.978
16.3
29.87
29.80
12.5
7.5
30.300
80.099
98.0
138.983
66.864
449.6
52,669
16.9
12.5
7.4
A-5
-------
Southern Research Institute/I]SEP A
April 2008
Energy Center, Grand Rapids, MN
Boiler No, 5 Outlet Duact
Average Results
Tests 1 through 3
3/2910?
Parameter
Arsenic
Barium
Beryllium
Cadmium
Chromium
Zinc
Copper
Lead
Manganese
Mercury
Nickel
Selenium
Siver
Concentration
< 1
3.40E- 0
< 7.44E- 2
1
0
2.Q6E-Oi
1.84E-10
<
3.49E-I0
<
<
< 7.44E-11
< 8.41E-11
(IbslhrJ
< 1.74E-04
1.33E-03
<
5.81E-05
4.06E-04
8.Q2E-03
7.16E-04
< 1.17E-04
1.37E-03
<:
<
<
<
gr/dscf
<
2,38E^08
< S.2tE4)8
1.04E-07
7.31E-07
1.44E-05
1.29E-06
< 2.10E-07
2^44E-06
<
< 1.14E-06
<
<
gr/acf
< 1
1.13E-06
<
4.95E-08
3.48E-0?
6.86E-06
8.15E-0?
< 1
1.16E-06
<:
<
<
<
Ui/Nm3
<
5.448
< 0,119
0-238
1 .873
32.945
2.947
<
5.591
< 1 .288
<
<
< 1.347
A-6
-------
Southern Research Institute/I]SEP A
April 2008
Project: Power
Location: Outlet Duct
Source; Boiler 5
Test Number:
Pressure, Bar0melriC''H£TK
Pressure, Static[H,O"):
Pressure, StiieN|Hp"i:
Meter Temperature (°F)
Meter Calibration (Y)
Awsrape Delta H (M4|
Dry Standard Ftow Rate (dscfra):...
Test number:
Preisure, HZO");.,..., ,.,..,. ,.
Pressure, Staek(H{f'J:
Meter Temperature f°Fl»,,m.,,,.»
Calls (YJ
Delta H (AH)
Dry Standard Ftow (ctscfraf; *»,.,,
Test Humber:
Pressure StatiefBgCT)'
Pressure, StaektBg**};, ,,,i,»il,,,»,,,»,,,,.
Finsl ₯criuiTO (liters).,,,,, .-,.,..., ,,.,.«
Callbralton (Y)
ssssa or. de'.eeaon nit
Average HCI Ibs-tir:
Average HCI ppm:
Average HCI Ibs-MMBtu:
A^eiage Fiow Rate (tlsc-fm!
21 TES
1
29 SOD
1 00
28874
7363 16
7483 34
85-50
4 112
1 005
0010
§8768
2
29 SOD
1 00
28 §74
74845
7604 57
78.50
4 162
1 005
0010
§4 032
3
2iSOD
1 00
29S74
7608 600
7726 800
79.20
4 154
1 005
0010
§6 791
0.181
0.472
O.OOOQ
66864
!T RESULTS
Condition;
Taten By: DtH
fust Fictor:
Time:
Carbop D*oxide Cootenll^):
Nrtfocjen Ccti>tent|%): ,
HF (mg) ,
HCI (rag)
HF (ppm): ,
HCI tppn)!'
HF (Ibs/rir):
Hri (ibs.'hh:
HF lit.S'MMBtu):
HCI (lbs;MMBtu>:
Time:
OM^pen Conten!(%|:,.. ,.»,.»,.
Nitrogen Content|%):
HF{aiB),,,.,.._,,,,..,,, ......,...,,
HCf (mg)
HF (ppmS"
HCI(ppnti: ,
HF (Ibs-hr):
HCI (Ibs'hrl'
HF (Ibs-MMBtu):
HCI (ll>s.'MMB«n:.. ,.
Time:
Carbijn Dfoxicle1 ront^nH^^t):
Nitrogen Co»tenli%): ,
HF (iT'fl)
HCI (rag)
HF (ppm)'
HCI tppnn: ,
HF(lbs-hr):
HCI (lbs:hr)'
HF (lb*;MMBtUt:
Hfl (lbs.'MMBtu>:
HF Ibs/hr:
Averafls HF ppmt
HF
S 57-J, 17
, ,. , ... , 7 5D
001*;
, 3 5fi7
3 '~6?<
'i ~>\i
322-
300--H30
OCD-M
12:28-13:28
..,.,..,...,..,. 1260
,....,.....,. 7 20
80 20
....................... 0026
0087
0 n6c-
, , 337C.
00125
300-+00
00300
1521-1621
^0 Q"
00'"-
OCt.5
3 2",5
, , 047-.
0 04=.'?>
3 "-,1
, OOJF+OO
OC3-"C
0.0751
0.356
O.OOE*DO
A-7
-------
Southern Research Institute/I]SEP A
April 2008
Appendix B
Fuel and Ash Analyses
B-l
-------
Southern Research Institute/I]SEP A
April 2008
Kelley to insert pdf files in final report
B-2
-------
Southern Research Institute/I]SEP A
April 2008
Appendix C
Boiler Efficiency Determinations
c-i
-------
Southern Research Institute/I]SEP A
April 2008
Combustion Calculations - Btu Method
INPUT CONDITIONS - BY TEST OR SPECIFICATION FUEL - Subbituminous Coal, Minnesota
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]
25.0 15 | Ultimate Analysis
41.67 Constituent %byweight
80 A C 54.17
66 B S 0.33
352.11 C H2 2.85
844.47 D H2O 23.54
0.0035 E N2 0.93
0 F O2 14.23
85 G Ash 3.95
220.45 H Total 100.00
16 | Theo Air, lb/100 Ib fuel
K1 | [15]xK1
11.51 623.5
4.32 1.4
34.29 97.7
-4.32 -61.5
Air 661.2
17 1 H2O, lb/100 Ib fuel
K2
8.94
1.00
H2O
0 18 Higher heating value (HHV), Btu/lb fue
0 19 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
[15]xK2
25.48
23.54
49.02
9,445
0.13
7.000
0.09
COMBUSTION GAS CALCULATIONS, Quantity/10,000 Btu Fuel Input
22
23
24
25
26
27
28
29
30
31
32
33
34
36
36
37
Theoretical air (corrected), lb/10,000 Btu
Residue from fuel, lb/10,000 Btu
Total residue, lb/10,000 Btu
[201- [211 x 1151 /[18] + [11]
([15G] + [21])x 100/[18]
[23] + [14
A At Burners B| Infiltration
Excess air, % by weight 25.0 0.0
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)
(1+[25]/100)x[22]
[26] x [7]
[8]x 00 / 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
25.0
8.734
0.031 0.031
0.000 0.000
0.519
1.016
0.000
0.000 0.000
9.781
0.550 0.550
9.231
5.62
0.37
D | Leaving
6.990
0.043
0.043
3lr/Econ
25.0
0.031
0.000
0.519
0.000
0.550
8.734
0.031
0.000
1.016
0.000
0.000
9.781
0.550
9.231
5.62
0.37
EFFICIENCY CALCULATIONS, % Input from Fuel
38
39
40
41
42
43
44
45
46
47
48
49
50
61
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 mois ure in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024 [35D] x ([6] - [3])
H1 = (3.958E-5 x T + 0.4329) x T + 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 Chapter 10, Table 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]
100 -[47] -[52]
KEY PERFORMANCE PARAMETERS
54
55
56
57
58
59
60
61
Input from fuel, 1,000,000 Btu/h
Fuel rate, 1000 Ib/h
Wet gas weight, 1000 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/h] 67.27
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] / 1 00) x [22
[54] x [57]/10
[54] x {([18] - 10.30 x [17H]) / 18] - 0.005
x ([44] + [45]) + Ha a T[5] x [57] / 10,000}
1 000 x [59 / [56]
From Chapter 10, Fg.3 at H = [60], % H2O = [36]
1456.0
48.0
based on output of plant Btu/h
0.01 H@80~1.0
16.94
7.31
0.11
0.13
1.00
1.00
0.00
26.48
-0.80
-0.01
0.01
0.00
-0.80
74.32
Leaving Furnace
290.1
8.765
260.0
295.3
1017.8
3375.0
Leaving Blr/Econ
296.6
31.4
290.1
C-2
-------
Southern Research Institute/I]SEP A
April 2008
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 - Subbituminous Coal, Minnesota
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 n 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
CO2from 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]
23.3 15| Ultimate Analysis
39.96 Constituent % by weight
80 A C 54.84
62 B S 0.33
357.87 C H2 2.92
845.08 D H2O 23.56
0.004 E N2 1.12
0 F O2 13.64
85 G Ash 3.59
225.80 H Total 100.00
16| Theo Air, lb/1 00 Ibfuel
K1 | [15]xK1
11.51 631.2
4.32 1.4
34.29 100.1
-4.32 -58.9
Air 673.8
17| H2O, lb/100 Ibfuel
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/10,000 Btu [16H]x 100 /[18]
0 21 Unburned carbon, % of fuel [19] x [18] / 14,500
[15]xK2
26.10
23.56
49.66
9,491
0.15
7.100
0.10
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 /[18]+[11]
([15G + 21])x 100/[18]
[23] + [14]
A | At Burners B| Infiltration
Excess air, % by weight 23.3 0.0
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/1 0,000 Btu
CO2from 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/10,000 Btu
H2O in gas, % in weight
Residue, % by weight (zero if < 0.15 lbm/10KB)
1 +[25]/100)x[22]
[26] X [7]
[8]x 100/[18]
[17H]X100/[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
23.3
8.739
0.035 0.035
0.000 0.000
0.523
1.015
0.000
0.000 0.000
9.789
0.558 0.558
9.230
5.70
0.34
7.088
0.039
0.039
D | Leaving Blr/Econ
23.3
0.035
0.000
0.523
0.000
0.558
8.739
0.035
0.000
1.015
0.000
0.000
9.789
0.558
9.230
5.70
0.34
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 n 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 [35d] X ([6] - 3])
H 1 = (3.958E-5 X T + 0.4329) X T + 1 062.2
H2 = [3] -32
[29] X ([39] - [40]) / 00
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]
0.0024 X [26D] X ([2] - [3])
0.0045 X [27D] X ([2] - [3])
(H at T[4] - H at T[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, 1000 Ib/h
Air to burners (wet), lb/10,000 Btu
Air to burners (wet), 1000 Ib/h
Heat aval able, 1,000,000 Btu/h
Ha [Btu/h 68.70
Heat aval able/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100X 10]/[53]
1000 X [54] / [18]
[54] X 33 / 10
(1 +[7]) X (1 + [25A] / 1 00) X [22]
54 x[57]/ 10
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]
1456.3
48.0
based on output of plant Btu/h
0.01 H@80~1.0
16.95
7.37
0.12
0.15
1.00
1.00
0.00
26.59
-0.84
-0.01
0.01
0.00
-0.84
74.24
Leaving Furnace
297.7
8.774
266.8
303.0
1017.9
3350.0
Leaving Blr/Econ
304.1
32.0
297.7
C-3
-------
Southern Research Institute/I]SEP A
April 2008
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Combustion Calculations - Btu Method
NPUT CONDITIONS - BY TEST OR SPECIFICATION
Excess air: at burner/leaving boiler/econ, % by weight
Entering air emperature, 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 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]
18.2
39.22
80
63
356.57
840.43
0.0041
0
85
221.32
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
([15G +
0
0
0 2
o ;
FUEL - Subbituminous Coal, Minnesota
15| Ultimate Analysis
Constituent % by weight
(\ C 54.44
B S 0.33
3 H2 2.95
3 H2O 23.85
E N2 0.54
F O2 13.91
3 Ash 3.98
-H Total 100.00
16 1 Theo Air, lb/1 00 Ib fuel
K1 | 15]xK1
11.51 626.6
4.32 1.4
34.29 101.2
-4.32 -60.1
Air 669.1
17| H2O, lb/1 00 Ib fuel
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 [1 9] x 18] / 14,500
[15]xK2
26.37
23.85
50.22
9,422
0.17
7.101
0.11
X1151 /[18]+[11]
21])x100/[18]
[23 +[14]
Excess air, % by weight
Dry air, lb/10,000 Btu
H2Ofromar, 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/1 0,000 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)
M At Burners B| Infiltration
18.2 0.0
(1 +[25]/100)x[22]
[26] x [7]
[8] x 100/[18]
[17H]x 100/[18]
(100-[15G]-[21])x
[12]
100 / 18]
[13]
Summation [26] through [32]
Summation [27] + [28] + [29] + [32]
[33] -[34]
100x[34]/[33]
[9]x[24]
EFFICIENCY CALCULATIONS, % Input from Fuel
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
/[33]
C | Leaving Furnace
18.2
8.382
0.034 0.034
0.000 0.000
0.533
1.018
0.000
0.000 0.000
9.434
0.567 0.567
8.867
6.01
0.39
7.088
0.043
0.043
D | Leaving Blr/Econ
18.2
0.034
0.000
0.533
0.000
0.567
8.382
0.034
0.000
1.018
0.000
0.000
9.434
0.567
8.867
6.01
0.39
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 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, %
0.0024x[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]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(2J_
(H at T[4] - H at T 3])
-[3])
-[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, 1 000 Ib/h
Wet gas weight, 1000 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/h] 68.38
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]/
[54] x 57] / 10
[54]x{([18]- 10.30X
X ([44] +
45]) + Ha a
1000x[59]/[56]
100)x[22]
[17H])/[18]-0.005
T[5]x [57]/10,000}
From Chapter 10, Fig.3 at H = [60], % H2O = [36]
1454.0
48.0
based on output of plant Btu/h
0.01 H@80~1.0
16.18
7.49
0.12
0.17
1.00
1.00
0.00
25.96
-0.82
-0.01
0.01
0.00
-0.82
74.86
Leaving Furnace
278.9
8.416
248.8
293.5
1052.2
3490.0
Leaving Blr/Econ
295.7
31.4
278.9
C-4
-------
Southern Research Institute/I]SEP A
April 2008
Combustion Calculations - Btu Method
INPUT CONDITIONS - BY TEST OR SPECIFICATION FUEL - Subbituminous Coal, Minnesota
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]
22.3 15 1 Ultimate Analysis
44.61 Constituent % by weight
80 A C 29.57
62 B S 0.04
409.77 C H2 2.78
881.09 D H2O 43.60
0.00325 E N2 0.30
0 F O2 22.06
85 G Ash 1.65
227.85 H Total 100.00
16 1 Theo Air, lb/1 00 Ib fuel
K1 | [15]xK1
11.51 340.3
4.32 0.2
34.29 95.4
-4.32 -95.3
Air 340.6
17| H2O, lb/100 Ib fuel
K2
8.94
1.00
H2O
0 18 Higher heating value (HHV), Btu/lb fuel
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
15]xK2
24.87
43.60
68.47
8,972
0.29
3.796
0.18
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/1 0,000 Btu
Residue from fuel, lb/10,000 Btu
Total residu
Excess air,
3, lb/10,000 Btu
20]- 21]x 1151 / 18]+ 11
([15G +[21])x100/[18]
[23] +[14]
A | At Burners B| Infiltration
/ by weight 22.3 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/1 0,000 Btu
H2O from sorbent, lb/10,000 Btu
Total wet gas, lb/10,000 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 < 0.15 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
22.3
4.615
0.015 0.015
0.000 0.000
0.763
1.094
0.000
0.000 0.000
5.725
0.778 0.778
4.947
13.59
0.30
3.774
0.020
0.020
D | Leaving Blr/Econ
22.3
0.015
0.000
0.763
0.000
0.778
4.615
0.015
0.000
1.094
0.000
0.000
5.725
0.778
4.947
13.59
0.30
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 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 [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])
(H atT[4]- HatT3])x 100/[18
Summation [48] through [51]
100- 47] -[52]
KEY PERFORMANCE PARAMETERS
54
55
56
57
58
59
60
6
Input from fuel, 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), 1000 Ib/h
Heat available, 1,000,000 Btu/h
Ha [Btu/h]
81.54
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] / 100) X [22]
[54] X [57]/10
[54]x{([18]- 10.30X 17H])/ [18] -0.005
X ([44 + [45]) + Ha a T[5] X [57] / 1 0,000}
1000x[59]/[56]
From Chapter 10, Fig. 3 at H = [60 , % H2O = 36]
1474.4
48.0
based on output of plant Btu/h
0.01 H @80~ 1.0
9.51
10.89
0.05
0.29
1.00
1.00
0.00
22.74
-0.39
0.00
0.01
0.00
-0.38
77.65
Leaving Furnace
168.0
4.630
135.9
278.5
1658.0
3375.0
Leaving Blr/Econ
293.4
32.7
168.0
C-5
-------
Southern Research Institute/I]SEP A
April 2008
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Combustion Calculations - Btu Method
NPUT 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 tempera ure 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]
20.5
48.19
80
64
409.77
857.90
0.0044
0
85
219.94
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/1 0,000 Btu
[20]-[21]x 1151 /[1
FUEL- Subbituminous Coal, Minnesota
15 | Ultimate Analysis
Constituent % by weight
H C 29.01
3 S 0.05
C H2 2.98
3 H2O 46.02
E N2 0.42
F O2 20.35
3 Ash 1.16
-I Total 100.00
16 | Theo Air, lb/1 00 Ib fuel
K1 | [15]xK1
11.51 333.9
4.32 0.2
34.29 102.3
-4.32 -87.9
Air 348.5
17 1 H2O, lb/100 Ib fuel
K2
8.94
1.00
H2O
8 Higher heating value (HHV), Btu/lb fue
9 Unburned carbon loss, % fuel input
0 Theoretical air, lb/10,000 Btu [16H] x 100 / [18]
1 Unburned carbon, % of fuel 1 9] x 1 8] / 1 4,500
[15]xK2
26.68
46.02
72.70
8,922
0.36
3.906
0.22
] + [11]
([15G] + [21])x 100/[18]
[23] + 14]
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/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/1 0,000 Btu
Water in wet gas, lb/10,000 Btu
Dry gas, lb/1 0,000 Btu
H2O in gas, % in weight
Residue, % by weight (zero if < 0. 1 5 lbm/1 0KB)
(1 +[25]/100)x[22]
[26] x [7]
[8]x 100/[18]
[17H]x 100/[18]
(100- 15G]-[21])x
[12]
<\ At Burners B| Infiltration
20.5 0.0
00/[18]
[13]
Summat on [26] through [32
Summat on [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
20.5
4.671
0.021 0.021
0.000 0.000
0.815
1.105
0.000
0.000 0.000
5.797
0.835 0.835
4.962
14.41
0.23
3.878
0.015
0.015
D | Leaving Blr/Econ
20.5
0.021
0.000
0.815
0.000
0.835
4.671
0.021
0.000
1.105
0.000
0.000
5.797
0.835
4.962
14.41
0.23
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 mois ure in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024 x [35d] x ([6 -
H1 =(3.958E-5xT +
H2 = [3] -32
[3])
0.4329) x T+ 1062.2
[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]
Summat on [38] throi
0.0024 x[26D]x ([2]
gh [46]
[3])
0.0045 x [27D] x ([2] - [3])
(H at T[4] - H at T[3])
x 100 / 18]
Summation [48] through [51]
100-[47 -[52]
KEY PERFORMANCE PARAMETERS
54
55
56
57
58
59
60
6
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/h] 81.54
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100 x [10] / [53]
1000x[54]/ 18]
[54] x [33]/10
(1 +[7 ) x (1 + [25A] /
[54] x 57] / 1 0
100)x[22]
[54] x {([18]- 10.30 x[17H])/ [18] -0.005
x ([44] + 45]) + Ha a
1000x[59]/[56]
T[5]x [57]/1 0,000}
From Chapter 10, F g.3 at H = [60], % H2O = [36]
1462.7
48.0
based on output of plant Btu/h
0.01 H@80~1.0
9.26
11.53
0.07
0.36
1.00
1.00
0.00
23.22
-0.36
0.00
0.01
0.00
-0.35
77.13
Leaving Furnace
165.3
4.692
133.8
269.3
1628.9
3350.0
Leaving Blr/Econ
285.2
32.0
165.3
C-6
-------
Southern Research Institute/I]SEP A
April 2008
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Combustion Calculations - Btu Method
NPUT CONDITIONS - BYTEST OR SPECIFICATION
Excess air: at burner/leaving boiler/econ, % by weight
Entering air emperature, 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 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]
22.9
47.82
80
64
400.57
874.18
0.0055
0
85
220.06
0
0
0
0
FUEL - Subbituminous Coal, Minnesota
15 1 Ultimate Analysis
Constituent % by weight
A C 29.42
B S 0.04
C H2 2.87
D H2O 44.65
E N2 0.44
F O2 20.79
G Ash 1.79
H Total 100.00
16 1 Theo Air, lb/1 00 Ib fuel
K1 | 15]xK1
11.51 338.6
4.32 0.2
34.29 98.3
-4.32 -89.8
Air 347.3
17| H2O, lb/1 00 Ib fuel
K2
8.94
1.00
H2O
1 8 Higher heating value (HHV), Btu/lb fuel
1 9 Unburned carbon loss, % fuel input
20 Theoretical air, lb/10,000 Btu [16H] x 100 /[18]
21 Unburned carbon, % of fuel [1 9] x [18] / 14,500
[15]xK2
25.64
44.65
70.29
8,913
0.33
3.896
0.20
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]x 1151 /[18 +[11]
([15G]+[21])x 100/[18]
[23]+ 14]
Excess air, % by weight
Dry air, lb/10,000 Btu
H2Ofromar, lb/10,000 Btu
Additional moisture, lb/10,000 Btu
H2O from fuel, lb/1 0,000 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
22.9 0.0
(1+[25]/100)x[22]
[26] x [7]
[8]x 100/[18]
[17H]x100/[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
22.9
4.756
0.026 0.026
0.000 0.000
0.789
1.100
0.000
0.000 0.000
5.882
0.815 0.815
5.067
13.85
0.32
3.871
0.022
0.022
D | Leaving Blr/Econ
22.9
0.026
0.000
0.789
0.000
0.815
4.756
0.026
0.000
1.100
0.000
0.000
5.882
0.815
5.067
13.85
0.32
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]-[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] x 14,500/[18]
ABMA curve, Chapter 23
From Chapter 10, Table 14, Item [41]
Summation [38] through [46]
0.0024 x 26D x ( *
0.0045X 27D x (
(H at T[4] - H at T :
-[3])
'- -[3])
])x 100/[18
Summation [48] through [51]
100 -[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/h] 79.26
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
100 x [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 a T[5] x [57] / 10,000}
1000x[59]/[56]
From Chapter 10, Fig.3 at H = [60], % H2O = [36]
1470.9
48.0
based on output of plant Btu/h
0.01 H @80~ 1.0
9.66
11.22
0.09
0.33
1.00
1.00
0.00
23.30
-0.37
0.00
0.01
0.00
-0.36
77.06
Leaving Furnace
168.0
4.782
136.6
270.3
1609.4
3490.0
Leaving Blr/Econ
285.6
32.0
168.0
C-7
-------
Southern Research Institute/I]SEP A
April 2008
Appendix D
Wood Based Fuel Deliveries for Rapids Energy
(1/1/2007 - 6/30/2007
D-l
-------
Southern Research Institute/USEPA
April 2008
REC Wood Burn 01/01 to 06/30, 2007
VENDOR
Ainsworth Bemidji
B Nelson
Cass Forest Products
Cook Logging
Covington Trucking
Dick Walsh Forest
Product
Dukek Logging
Erickson Mills
Erickson Mills
Erickson Timber
Hi Tech Milling
Northland Biomass
J&A Logging
Lonza
MR Chips
MR Chips
Muller Trucking
Norbord Minnesota
Potlatch Lumber Co
Rajala Mill
Rajala Mill
Rajala Mill
Rajala Timber Co
Scheff Logging
Wagner Forest Products
TYPE
Bark
Bark
Bark
Bark
Bark
Bark
Bark
Chips
Shredded
Bark
Chips
Bark
Chips
Bark
Blandin
Private
Bark
Bark
Bark
Bark
Chips
Shredded
Bark
Bark
Bark
Total Lbs
Delivered
14,208,802
3,734,940
6,489,660
1,310,720
3,636,560
35,298,778
10,371,620
303,320
4,022,480
12,666,820
5,147,680
8,489,580
552,800
1,702,864
8,741,840
11,479,260
770,300
3,551,400
24,731,240
941,220
2,935,060
42,160
11,697,800
3,478,670
3,381,740
Number of
Trips
336
87
138
24
76
618
205
6
78
230
105
190
12
54
163
199
15
80
465
28
70
1
259
75
65
Tons
Delivered
7,104
1,867
3,245
655
1,818
17,649
5,186
152
2,011
6,333
2,574
4,245
276
851
4,371
5,740
385
1,776
12,366
471
1,468
21
5,849
1,739
1,691
Miles From gal fuel CO2 emitted
Tons/Trip REC used (ton)
21.1 69 3567 35
21.5 116 1553 15
23.5 53 1125 11
27.3 40 148 1
23.9 80 935 9
28.6 85 8082 79
25.3 95 2996 29
25.3 75 69 1
25.8 75 900 9
27.5 131 4635 45
24.5 26 420 4
22.3 5 146 1
23.0 48 89 1
15.8 5 42 0
26.8 0 00
28.8 0 00
25.7 53 122 1
22.2 82 1009 10
26.6 69 4936 48
16.8 40 172 2
21.0 40 431 4
21.1 40 60
22.6 14 558 5
23.2 29 335 3
26.0 26 260 3
Total
Blandin
Total Wood Burn
89,844
82,881
172,725
32,536
318
D-2
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Southern Research Institute/I]SEP A
April 2008
Appendix E
Dust Collector and Electrostatic Precipitator Data
D-3
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Southern Research Institute/I]SEP A
April 2008
Summary of Electrostatic Precipitator Voltages and Dust Collector Pressure Drop
Run ID
1
2
3
4
5
6
Dust Collector
Pressure Drop (in. we)
-5.2
-5.2
-4.8
-8.4
-6.9
-7.4
Panel A Voltage
268
276
286
287
280
285
Panel B Voltage
274
308
338
372
373
370
Panel C Voltage
324
335
336
335
345
347
D-4
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