Final Version - October 2006
EPA Contract No. EP-C-04-056
Work Assignment No. 1-8-101
October 2006
Test and Quality Assurance
Plan
Environmental and Sustainable Technology
Evaluation - Biomass Co-firing in Industrial
Boilers
Prepared by:
SOUTHERN RESEARCH
INSTITUTE
Affiliated with the
University of Alabama at Birmingham
Southern Research Institute
F01"
U.S. Environmental Protection Agency
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Final Version - October 2006
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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Final Version - October 2006
EPA Contract No. EP-C-04-056
Work Assignment No. 1-8-101
October 2006
Test and Quality Assurance Plan
Environmental and Sustainable Technology Evaluation
Biomass Co-firing in Industrial Boilers
Prepared by:
Southern Research Institute
PO Box 13825
Research Triangle Park, NC 27709 USA
Telephone: 919/806-3456
Reviewed by:
U.S. EPA National Risk Management Research Laboratory (NRMRL)
U.S. EPA Office of Air Quality Planning and Standards (OAQPS)
U.S. EPA Office of Research and Development QA Team (ORD)
U.S. EPA Office of Solid Waste (OSW)
indicates comments are integrated into TQAP
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Final Version - October 2006
Environmental and Sustainable Technology Evaluation
Biomass Co-firing in Industrial Boilers
This Test and Quality Assurance Plan has been reviewed and approved by Southern Research Institute's
Quality Assurance Manager, the U.S. EPA APPCD Project Officer, and the U.S. EPA APPCD Quality
Assurance Manager.
Signed 10/06 Signed 10/06
Richard Adamson Date David Kirchgessner Date
Project Manager APPCD Project Officer
Southern Research Institute U.S. EPA
Signed 10/06 Signed 10/06
Eric Ringler Date Robert Wright Date
Quality Assurance Manager APPCD Quality Assurance Manager
Southern Research Institute U.S. EPA
TQAP Final: October 2006
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TABLE OF CONTENTS
Pag
APPENDICES iii
LIST OF FIGURES iii
LIST OF TABLES iii
DISTRIBUTION LIST iv
1.0 INTRODUCTION 1-1
1.1 BACKGROUND 1-1
1.2 PROJECT DESCRIPTION AND OBJECTIVES 1-1
1.3 PROJECT ORGANIZATION AND RESPONSIBILITIES 1-3
1.4 SCHEDULE 1-4
2.0 VERIFICATION APPROACH 2-1
2.1 HOST FACILITIES AND TEST BOILERS 2-3
2.2 FIELD TESTING 2-7
2.2.1 Field Testing Matrix 2-7
2.2.2 Boiler Operations and Fuels 2-9
2.3 BOILER PERFORMANCE METHODS AND PROCEDURES 2-10
2.3.1 Boiler Efficiency 2-10
2.3.1.1 Data Logged by Host Facilities 2-11
2.3.1.2 Data Logged by Southern 2-11
2.3.1.3 Fuel Sampling and Analyses 2-12
2.3.2 Boiler Emissions 2-13
2.3.3 Fly ash Characteristics 2-14
2.4 SUSTAINABILITY INDICATORS AND ISSUES 2-15
3.0 DATA QUALITY OBJECTIVES 3-1
3.1.1 Emissions Testing QA/QC Checks 3-1
3.1.2 Fly ash and Fuel Analyses QA/QC Checks 3-2
3.1.3 Boiler Efficiency QA/QC Checks 3-3
3.2 INSTRUMENT TESTING, INSPECTION, AND MAINTENANCE 3-4
3.3 INSPECTION/ACCEPTANCE OF SUPPLIES, CONSUMABLES, AND
SERVICES 3-4
3.4 DATA QUALITY OBJECTIVES RECONCILIATION 3-4
3.5 TRAINING AND QUALIFICATIONS 3-5
4.0 DATA HANDLING AND REPORTING 4-1
4.1 DATA ACQUISITION AND DOCUMENTATION 4-1
4.1.1 Corrective Action and Assessment Reports 4-2
4.2 DATA REVIEW, VALIDATION, AND VERIFICATION 4-2
4.3 ASSESSMENTS AND RESPONSE ACTIONS 4-3
4.3.1 Project Reviews 4-3
4.3.2 Technical Systems Audit 4-3
4.3.3 Audit of Data Quality 4-4
4.3.4 Performance Evaluation Audit 4-4
4.4 VERIFICATION REPORT AND STATEMENT 4-4
5.0 HEALTH AND SAFETY PLAN 5-1
6.0 REFERENCES 6-1
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APPENDICES
Page
Appendix A-l Biomass Co-firing Stakeholder Group A-l
Appendix B-l Test Log Form B-l
Appendix B-2 Boiler Efficiency Calculations B-2
Appendix B-3 Sample Chain of Custody Form B-3
Appendix C-l Example Emissions Testing Calibrations C-l
Appendix C-2 Corrective Action Report C-2
Appendix D-l Measurement Uncertainty Analysis D-l
Appendix D-2 Site Safety Log Form D-3
LIST OF FIGURES
Figure 1-1. Project Organization 1-3
Figure 2-1. Site 1 Foster Wheeler Spreader Stoker 2-3
Figure 2-2. Emission Testing Ports for Site 1 2-4
Figure 2-3. University of Iowa Main Power Plant Configuration 2-6
LIST OF TABLES
Table 2-1. MP-5 CEMS 2-4
Table 2-2. UI-10 CEMS 2-7
Table 2-3. ESTE Biomass Co-firing Program Test Matrix 2-8
Table 2-4. MP-5 Fuel Characteristics 2-9
Table 2-5. UI-10 Fuel Characteristics 2-10
Table 2-6. Summary of Boiler Efficiency Parameters 2-11
Table 2-7. Summary of Boiler Efficiency Parameters Logged by Southern 2-12
Table 2-8. Summary of Fuel Analyses 2-12
Table 2-9. Summary of Emission Test Methods and Analytical Equipment 2-14
Table 2-10. Summary of Fly ash Analyses 2-15
Table 3-1. Summary of Emission Testing Calibrations and QA/QC Checks 3-2
Table 3-2. Fuel and Fly ash Analytical QA/QC Checks 3-3
Table 3-3. Boiler Efficiency QA/QC Checks 3-3
in
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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 - CHP Partnerships Program
Kim Grossman
Southern Research Institute
Richard Adamson
William Chatterton
Eric Ringler
IV
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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. Congress funds ESTE 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. Should additional collaborators be accepted for participation in this project
after publication of this TQAP, addenda will be issued outlining site-specific aspects of those additional
tests.
This ESTE project will involve evaluation of co-firing common woody biomass in industrial, commercial
or institutional coal-fired boilers. For this project Southern Research Institute (Southern) is the
responsible contractor. Client offices within the EPA, those with an explicit interest in this project and its
results, include: Office of Air and Radiation (OAR), CHP Partnerships Program, 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.D.A. Forest Service and the Council of Industrial Boiler Owners (CIBO).
1.2 PROJECT DESCRIPTION AND OBJECTIVES
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 Btu 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"
(MACT) standard. There is also interest in development of a Guidance Memo relating to PM 2.5
emissions reductions.
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The focus for this project will be to evaluate performance and emission reductions for ICI boilers as a
result of biomass co-firing. The primary objectives of this project are 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 sourcing and transportation of biomass and disposal
of fly ash
Southern utilizes balanced stakeholder groups to guide the activities and priorities. These groups assist in
selection and prioritization of technologies to be verified, development of testing protocols, outreach
activities, and review of project specific reports and procedures. Previous groups that have guided
Southern's activities include an Executive Stakeholders Group, Oil & Gas Industry Stakeholder Group,
Electrical Generation Stakeholder Group, and several small technical panels (municipal solid waste,
distributed generation, refrigerant systems, and engines and fuels). The Center maintains contact with key
members in Stakeholder groups to address issues and provide guidance regarding specific technologies
and verification tests.
A Biomass Co-firing Stakeholder Group (BCSG) was assembled for this project. This group,
summarized in Appendix A-l is broad-based and represents key industry, regulatory and research
organizations. Together it provides a high degree of expertise in the following areas related to this
project:
• operational issues relating to industrial boilers that may influence acceptance and uptake of
biomass co-firing in response to regulatory developments
• measurement methods and issues relating to combustion processes, especially to co-
firing situations
• data quality requirements and critical factors for data to be used in regulatory guidance
• waste management issues relating to fly ash disposal and beneficial uses of ash and
related physical-chemical material requirements
• biomass sources and characteristics
• establishment of sustainability indicators
This document is the Test and Quality Assurance Plan (TQAP) for this ESTE project and has been
developed based on the project objectives outlined by client EPA offices and technical expertise provided
by the BCGS. This TQAP includes the following components:
• Project organization and responsibilities (§ 1.3)
• Project schedule (§ 1.4)
• Detailed description of the verification approach and parameters (§ 2.0)
• Descriptions of the test locations (§2.1)
• Detailed sampling and analytical procedures (§2.2)
• Data quality objectives and QA/QC procedures (§ 3.0)
• Data handling and reporting (§4.0)
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• Health and safety requirements (§5.0)
This TQAP has been reviewed by representatives of ORD, OAQPS, OSW, the EPA QA team, and the
project stakeholders and collaborators. This TQAP has been prepared to guide implementation of the test
and to document planned test operations and is posted on the Web sites maintained by Southern
(www.sri-rtp.com) and the ETV program (www.epa.gov/etv).
1.3 PROJECT ORGANIZATION AND RESPONSIBILITIES
Figure 1-1 presents the project organization chart. The following section discusses functions,
responsibilities, and lines of communications for the verification test participants.
Southern has overall responsibility for planning and ensuring the successful implementation of this
verification test. Southern will ensure that effective coordination occurs, schedules are developed and
adhered to, effective planning occurs, and high-quality independent testing and reporting occur.
Richard Adamson
Project Manager
Eric Ringler
QA Reviewer
Robert Wright
US EPA APPCD
QA Manager
David Kirchgessner
US EPA APPCD
Project Officer
Bill Chatterton
Field Team Leader
Host Site Operators
GE Energy,
Emissions Testing
Wyoming
Analytical
Laboratories, Inc.,
Analytical Services
Figure 1-1. Project Organization
Richard Adamson is the Project Manager for Southern. He will ensure the staff and resources are
available to complete this verification as defined in this TQAP. He will review the TQAP and Report to
ensure they are consistent with ETV operating principles. He will oversee the activities of Southern staff,
and provide management support where needed. Mr. Adamson will sign the Verification Statement,
along with the EPA-ORD Laboratory Director.
Richard Adamson will also serve as the Project Manager. His responsibilities include:
• Submittal of the TQAP and verification report;
• overseeing the field team leader's data collection activities, and
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• ensuring that data quality objectives are met prior to completion of testing.
The project manager will have full authority to suspend testing should a situation arise that could affect
the health or safety of any personnel. He will also have the authority to suspend testing if the data quality
indicator goals are not being met. He may resume testing when problems are resolved in both cases. He
will be responsible for maintaining communication with the EPA client offices, project collaborator/host
site personnel, and the BCSG.
Bill Chatterton will serve as the Field Team Leader. Mr. Chatterton will be responsible for ensuring that
all personnel and subcontractors at the sites comply with all applicable safety rules specified in
Southern's and the sites' safety plans. He will also provide field support for activities related to all
measurements and data collected. He will install and operate the measurement instruments, supervise and
document activities conducted by the emissions testing contractor, coordinate fuel and fly ash sample
collection and analysis with the laboratory, and ensure that QA/QC procedures outlined in this TQAP are
followed, including QA requirements for field subcontractors. He will submit all results to the Project
Manager, such that it can be determined that the DQOs are met. He will also oversee and manage
subcontractor activities and submittals.
Southern's QA reviewer is Eric Ringler, who is responsible for ensuring that the verification is performed
in compliance with the QA requirements of the Southern's QMP and this TQAP. He has reviewed and is
familiar with each of these documents. He will also review the verification test results and ensure that
applicable internal assessments are conducted as described in these documents. He will reconcile the
DQOs at the conclusion of testing and will conduct or supervise an audit of data quality. He is also
responsible for review and validation of subcontractor activities, review of subcontractor generated data,
and confirmation that subcontractor QA/QC requirements are met. Mr. Ringler will report all internal
reviews, DQO reconciliation, the audit of data quality, and any corrective action results directly to the to
the project manager for corrective action as applicable and citation in the final verification report. He will
review and approve the final verification report and statement. He is administratively independent from
the Southern's management and maintains stop work authority.
The verification will include the services of two subcontractors. Emissions testing will be conducted by
GE Energy with James Tryba serving as project manager. Fuel and fly ash analyses will be conducted by
Wyoming Analytical under the management of Monte Ellis.
Facilities hosting the field testing will assign engineers and boiler operators to assist with field testing,
boiler operations, and site safety. They will provide technical assistance, assist in the installation of
measurement instruments, and coordinate operation of the boilers with verification activities. Barring
unforeseen facility upsets, difficulties, or outages, they will ensure the units are available and accessible
to Southern for the duration of the test. Installation of all test and measurement instrumentation will be
coordinated and approved by site staff prior to beginning any work at the two sites. Site personnel will
also review the TQAP and report and provide written comments.
EPA-ORD will provide oversight and QA support for this verification. The APPCD Project Officer, Dr.
David Kirchgessner, is responsible for obtaining final approval of the TQAP and Report. The APPCD
QA Manager reviews and approves the TQAP and the final Report to ensure they meet Southern's QMP
requirements and represent sound scientific practices.
1.4 SCHEDULE
The tentative schedule of activities for testing is as follows:
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TQAP Development
First Stakeholder Teleconference November 8, 2005
Stakeholder Input Process November 8-30, 2005
Second Stakeholder Teleconference December 8, 2005
Stakeholder Input Summary Report December 15, 2005
Host Sites Confirmed March 31, 2006
Draft TQAP Released for Stakeholder Review April 14, 2006
EPA Review and Final Editing September, 2006
Final TQAP Released September, 2006
Field Testing and Analysis
University of Iowa - Boiler 10 December, 2006
Minnesota Power - Rapids Boiler 5 January, 2007
ESTE Report Development
Internal Draft Development January, 2007
BCSG Review/Revision March, 2007
EPA Review/Revision April, 2007
Final Report Posted April, 2007
Proposed schedules for field testing are tentative at this time and may be altered depending on
circumstances beyond the control of Southern such as biomass availability and host site operating
schedules or unexpected outages. Delays in field testing will likely result in similar delays in the report
development schedule.
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2.0 VERIFICATION APPROACH
This project is designed to evaluate changes in boiler performance due to co-firing woody biomass with
coal. On at least two separate boilers, operational performance with regard to efficiency, emissions, and
fly ash characteristics will be evaluated while combusting 100 percent coal and then reevaluated while co-
firing biomass with coal. The verification will also address site specific sustainability issues associated
with biomass co-firing. This TQAP identifies the first two boilers selected for testing (Section 2.1) and
contains site specific descriptions and instrumentation plans for each. Separate site specific test plans will
be developed based on the TQAP and issued for any additional boilers identified for testing.
The field testing analysis conducted on each of the selected boilers will consist of a simple A/B
comparison of boiler performance with the two different fuel mixes. Due to complexities associated with
boiler performance using different fuels, the testing will be limited to two operating points. Specifically,
the operating points tested will be: the boiler firing coal only at a typical nominal load, and the boiler
firing a biomass/coal co-firing mixture at its normal fuel blend and at the same operating load. By
limiting the testing to two normal operational points on each boiler, the approach minimizes the chance of
other operational changes within the boiler from masking the effects of co-firing.
The project will not include evaluation of the optimum woody biomass co-firing blend on each boiler, but
will use the blending rates used during past operations and optimizations by the facility, than compare
boiler performance and emissions while co-firing to performance and emissions when firing coal only.
The following three step testing approach was developed:
1) Select boilers that are well instrumented and either currently co-firing biomass or
configured to do so with minimum modifications. Review operating logs and historic
biomass co-firing rates for each boiler selected and define the preferred co-firing rate
for each boiler based on past operations.
2) Conduct efficiency, emissions, fuel, and fly ash analyses on the two boilers based on
pure coal baseline operations and biomass co-firing at the normal blend for each boiler
based on past operations. Analyze test results to evaluate changes in boiler emissions
performance attributable to biomass co-firing.
3) Collect data to evaluate sustainability indicators for the two sites selected. It is expected
that these indicators will include mode, and distance of transport of fuel and waste
material (i.e., ash,).
It is desirable to collect data from a larger number of sites. The total number of units tested will be a
function of the amount of collaborator funding or cost sharing that is procured. To this end it is planned
to solicit collaborative support from industry partners. The first level of collaboration is to provide access
to operational boilers along with some operational data. The second is to provide funding for testing at
additional sites.
In addition to the emissions evaluation, this verification will address changes in fly ash composition.
There are many beneficial uses of coal combustion fly ash including a component of cement production,
structural fill and road materials, soil stabilization, and other industrial uses. An important property that
limits the use of fly ash is carbon content. Presence of metals in the ash, particularly Hg, can also be a
limiting factor in certain aspects of beneficial use (e.g., cement kiln feed). Biomass co-firing is likely to
impact fly ash composition and properties, so testing will be conducted to evaluate changes in fly ash
carbon burnout (loss on ignition), minerals content, and metals content.
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For each of the boilers tested, the verification parameters listed below will be evaluated. This list was
developed based on project objectives cited by the client organizations and input from the BCSG.
Verification Parameters:
• Changes in emissions due to biomass co-firing including:
- Nitrogen oxides (NOX)
- Sulfur dioxide (SO2)
- Carbon monoxide (CO)
- Carbon dioxide (CO2)
- Nitrous oxide (N2O)1
- Total particulates (TPM), PM10, and PM2.5 (including condensable particulates)
- Primary metals: arsenic (As), selenium (Se), zinc (Zn), and mercury (Hg)
- Secondary metals: barium (Ba), beryllium (Be), cadmium (Cd), chromium (Cr), copper (Cu),
manganese (Mn), nickel (Ni), and silver (Ag)1
- Hydrogen chloride (HC1) and hydrogen fluoride (HF)
• Boiler efficiency during biomass co-firing and normalize emissions to boiler output
• Changes in fly ash characteristics including:
- Carbon, hydrogen, and nitrogen (CFiN), and minerals content
- Primary metals: arsenic (As), selenium (Se), zinc (Zn), and mercury (Hg)
- Secondary metals: barium (Ba), beryllium (Be), cadmium (Cd), chromium (Cr), copper (Cu),
manganese (Mn), nickel (Ni), and silver (Ag)1
- Potential boiler fouling components: calcium (Ca), sodium (Na), and potassium (K)1
- fly ash fusion temperature
- RCRA metals TCLP
- Air entraining agent index
• Sustainability indicators including sourcing and transportation of biomass and ash disposal under
baseline (no biomass co-firing) and test case (with biomass co-firing) conditions. Consideration
will be given to how the biomass would be disposed of should the co-firing approach not take
place.
For each site where testing will occur, careful planning and coordination will be needed to ensure that test
results are acceptable and useful, the testing has a minimum impact on host site operations, and field
testing is completed within project budgets. The following activities will be planned and managed by
Southern:
o Approval and publishing of this TQAP
o Identification of host sites
o Development of Site Profiles
1 Evaluation of N2O, secondary metals, and potential boiler fouling components are verification parameters suggested by the
BCSG, but not currently funded. These parameters will not be evaluated if additional sources of funding are not secured.
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o Confirm that sufficient uniform source of biomass is available for testing
o Testing is scheduled to minimize impact on site operations
o Test locations and safe access are defined and prepared
o Subcontractors and analytical laboratories are properly prepared and managed
o Site specific health and safety plans are in place
2.1 HOST FACILITIES AND TEST BOILERS
Initially, testing will be conducted on two industrial boilers that are capable of co-firing woody biomass.
The two units currently committed to hosting tests are identified as Minnesota Power's Rapids Energy
Center Boiler 5 (MP-5) which currently co-fires bark with coal, and the University of Iowa Main Power
Plant's Boiler 10 (UI-10) which will be co-firing wood derived palletized fuel with coal. Descriptions of
the two sites and boilers selected are as follows:
Minnesota Power
Minnesota Power's Rapids Energy Center has two identical Foster Wheeler Spreader Stoker Boilers
installed in 1980 (Boilers 5 and 6). This verification will be 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, wood waste, railroad ties, on-site generated waste oils and solvents, and other paper
wastes. Particulate emissions from each boiler are controlled by a Zurn multiclone dust collector and cold
side electrostatic precipitator. 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 will be 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/hr 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 coal:biomass fuel ratio of 15:85 percent. The wood
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
S02
CO
02
Instrument Make/Model
Teledyne Monitor Labs
(TML) 41-H-O2
TML50-H
TML 30-M
TML41-H-O2
Instrument Range
0 - 500 ppm
0-1000 ppm
0 - 5000 ppm
0-25 %
Reporting Units
Ib/MMBtu
Ib/MMBtu
Ib/MMBtu
%
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Operational parameters that will be recorded during this test program include the following:
• Steam flow (Ib/hr)
• Steam pressures (psig)
• Air temperatures (°F)
• Power output (MW)
• Heat input for coal, wood, and total, (Btu/hr)
• Coal and wood feed rates via belt scales, (Ib/hr)
• NOX, SO2, and CO emissions (Ib/MMBtu)
• Multiclone pressure drop (in. w.c.)
• ESP variables (volts, amperes, fields on line)
Data recorded during each test period will be averaged over the test period and reported to document
boiler operations during the testing, co-firing rates, and boiler efficiency.
University of Iowa
The University of Iowa Main Power Plant is a combined heat and power (CHP) facility serving both the
University main campus and the University of Iowa Hospitals and Clinics. The plant operates
continuously supplying steam service and cogenerating electric power. There are four operational boilers
at the facility, one stoker unit (Boiler 10), one circulating fluidized bed boiler (Boiler 11), and two gas
package boilers (Boilers 7 and 8). Three controlled extraction turbine generators with an accredited
capacity of 24.7 MW that cogenerate about 30 percent of the University and Hospital facilities total
electric needs. Figure 2-3, a control room screen snapshot, provides a depiction of the plant's
configuration. For this program, testing will be conducted on the stoker unit - Boiler 10.
Boiler 10 is a Riley Stoker Corporation unit rated at 170,000 Ib/hr steam (206 MMBtu/hr heat input) at
750°F at 600 psi. This unit normally operates in pressure control (swing) mode on a multi-boiler header
at a typical operating range of 120,000 to 140,000 Ib/hr steam. The unit can be base loaded up to its rated
capacity or swing down to a minimum load of 90,0001b/hr.
Currently, this boiler is fired with coal only. However, UI has been very successful in converting the
fluidized bed boiler at the facility to a co-firing unit using an oat hull product generated at a nearby food
processing plant. In keeping with the economic and environmental benefits realized through this effort,
UI is interested in introducing biomass co-firing on Boiler 10 as well. A pelletized wood product
manufactured from woody biomass by Renewafuels, LLC in Minnesota has been identified as a suitable
fuel to be co-fired with coal in Boiler 10. More details regarding the fuels used for this test is presented in
Section 2.2.2.
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Figure 2-3. University of Iowa Main Power Plant Configuration
Emissions testing for this program will be conducted in the ductwork of the selected boiler upstream of
the stack. The testing location and ports are shown in Figure 2-4.
Figure 2-4. Test Port Locations for UI-10
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The facility includes a mechanical dust collector and electrostatic precipitator to control particulate
emissions. Bottom ash and fly ash generated by Boilers 10 and 11 are collected, blended, and shipped to
a nearby limestone quarry where it is mixed with water, solidified, and used to build roads or fill.
Boiler 10 is equipped with a CEMS that monitors SO2 and O2 concentration in the flue gas. Table 2-2
summarizes the CEMS for Boiler 10.
Table 2-2. UI-10 CEMS
Parameter
S02
02
Instrument Make/Model
TML50-H
TML41-HO2
Instrument Range
0 - 1000 ppm
0-25 %
Reporting Units
Ib/MMBtu
%
The facility has a fully equipped control room that continuously monitors boiler operations. The systems
DCS includes a PI Historian software package that allows the facility to customize data acquisition,
storage, and reporting activities. A partial list of parameters monitored by the DCS includes:
• Heat input, (Btu/hr)
• Steam flow (Ib/hr)
• Steam pressures (psig) and temperatures (°F)
• Air flows (Ib/hr) 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 will be averaged over the test period and reported to document
boiler operations during the testing, co-firing rates, and support the boiler efficiency determinations.
2.2 FIELD TESTING
2.2.1 Field Testing Matrix
Field testing will be conducted on both of the boilers selected to evaluate each of the verification
parameters cited. On each unit, a set of three replicate tests will be conducted while firing coal and a
second set of three tests will be conducted while co-firing biomass and coal. The test matrix for each
boiler also includes a third optional test scenario should funding be secured to cover costs associated with
these optional tests. Specifically, the Minnesota Power test matrix includes an option to evaluate boiler
performance and emissions at a fuel blend with less biomass (approximately 40 percent) than that
normally fired at this facility. This will provide data for users that might not have availability to as large
a supply of biomass that this site has. The University of Iowa test matrix includes a second set of co-
firing tests using pelletized blend of wood and agricultural biomass. This fuel will be comprised of a mix
of woody biomass and processed corn stover, a promising renewable energy source for the Midwestern
US. A claimed benefit of this blended fuel over straight wood pellets is improved mechanical binding.
These optional tests will only be conducted if additional sources of funding are available to support the
project.
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Other than changes in fuel composition, all other boiler operations will be replicated as closely as possible
during test sets. Test and sampling procedures will also be consistent between sets of tests. Table 2-3
summarizes the test matrix.
All testing will be conducted during stable boiler operations. A representative of Southern will coordinate
testing activities with boiler operators to ensure that all testing is conducted at the desired boiler operating
set points and the boiler operational data needed to calculate efficiency is properly logged and stored.
Southern will also either conduct or supervise the field testing activities. A log form such as the example
in Appendix B-l will be used to document test periods and conditions.
At the conclusion of field testing, results will be analyzed to evaluate changes in boiler performance and
fly ash characteristics between the two sets of tests on each boiler. A statistical analysis (t-test) will be
conducted to verify the statistical significance of any observed changes in emissions or efficiency.
Table 2-3. ESTE Biomass Co-firing Program Test Matrix
Boiler ID
MP-5
UI-10
Fuel
100 percent sub bituminous
coal
Co-fired blend of nominal
15% coal and 85% woody
biomass
Co-fired blend of nominal
55% coal and 45% woody
biomass (Optional test)
100 percent sub bituminous
coal
Co-fired blend of nominal
75% coal and 25% woody
biomass
Co-fired blend of nominal
75% coal and 25%
agricultural biomass
(Optional test)
Operating Load
Nominal 175,000
Ib/hr steam at each
fuel condition
Nominal 130,000
Ib/hr steam at each
fuel condition
Test Parameters"
- Boiler efficiency
- Boiler emissions
- Fly ash analysis
- Fuel analysis'3
Test Durations and
Sampling Frequency"
- 3 one hour tests
- 3 one hour tests
- 3 integrated samples
- 3 composite samples
a Test parameters, durations, and frequencies will be the same for each set of tests.
b Fuel analyses will include both coal and biomass separately.
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2.2.2 Boiler Operations and Fuels
MP-5
Minnesota Power's Boiler 5 co-fires woody biomass (primarily bark) with sub bituminous coal at a fuel
blend of approximately 85 percent biomass to 15 percent coal. This plant employs belt scales to
gravimetrically measure the consumption of both types of fuels. The scales will be used to measure fuel
consumption and co-firing rates during all test periods, and to calculate boiler heat input with the fuel heat
content analyses. The fuels are not premixed and are fed to the boiler separately.
The facility has agreed to operate the boiler on coal only for a duration of time sufficient to conduct the
baseline testing. During the baseline testing, heat input will be maintained at a level that produces the
nominal 155,000 Ib/hr steam typically produced by the boiler. During co-firing, fuel inputs will be
maintained to replicate boiler output during the baseline test.
Table 2-4 summarizes typical fuel characteristics. More detailed fuel analyses will be conducted during
the tests.
Table 2-4. MP-5 Fuel Characteristics
Fuel
Coal
Wood
Heat Content (Btu/lb)
9,260
4,900
Fly ash (%)
4.9
1.9
Sulfur (%)
0.4
<0.1
Moisture (%)
27
50
UI-10
Boiler 10 at the UI site typically fires coal only, but will co-fire pelletized wood product during this
program. Boiler operations can be controlled using three methods including manually controlling fuel
feed rate, controlling fuel feed using a steam header pressure set point, or controlling fuel feed using a
steam mass flow control point. For this testing, the site has recommended that boiler operations be
controlled using steam flow. During the baseline testing, steam flow will be set at nominal 130,000 Ib/hr.
During co-firing, fuel inputs will be controlled by this set point to maintain the desired steam flow present
during the baseline test.
The pelletized biomass will be provided by Renewafuel, LLC. Renewafuel produces a range of
renewable composite biofuel pellets from renewable feedstock. Use of the fuel is expected to result in
lower emissions of criteria pollutants greenhouse gases compared to coal. Densified pellets allow for
better handling, storage and blending with existing fuels. The products also are consistent in size, heat
value and moisture content.
The two Renewafuel pellets that will be used for the proposed biomass emission evaluation study are: (1)
a wood-based composite pellet; and (2) a wood and corn-stover based pellet (optional testing). The
pellets can be produced in various sizes, but typically are cubed and approximately 1 % x 1 % x 2 inches
and have a density of 25-30 Ib/ft3. Moisture content of the fuels is approximately 12 percent and the fuels
have a higher heating value of approximately 8,200 Btu/pound (at 12% moisture). Feedstock woods for
Renewafuel's pellets come from industrial and agricultural entities. Corn stover comes from local farms.
Table 2-5 summarizes typical fuel characteristics for this site.
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Table 2-5. UI-10 Fuel Characteristics
Fuel
Coal
Palletized wood
Pelletized corn stover
Heat Content (Btu/lb)
12,100
8,200
8,200
Fly ash (%)
<10
1.0
3.7
Sulfur (%)
0.8-1.5
<0.05
<0.05
Moisture (%)
10
12
12
The biomass used in the pellets for the study will come from within a 150-mile radius of Renewafuel's
research and development facility in Battle Creek, Michigan and will be transported to the coal yard of
the University's coal supplier (River Trading Company). Coal and biomass will be blended at the
suppliers' coal yard at a rate of 25 percent biomass, then hauled by truck to the University. The field
team will collect blended fuel samples just ahead of the stoker to validate the fuel blending rate by
evaluating the compositions of the coal, wood, and blended fuels separately.
At the time of development of this draft TQAP, the method for measuring fuel feed rates and
subsequently heat input is not finalized. It is expected that a method of gravimetrically measuring the fuel
consumption will be developed using either batch or continuous feed procedures. An addendum to this
TQAP will be issued when the procedures are finalized.
2.3 BOILER PERFORMANCE METHODS AND PROCEDURES
Conventional field testing protocols and reference methods will be used to determine boiler efficiency,
emissions, and fly ash properties during the testing programs to maximize the overall data quality.
Details regarding the protocols and methods proposed are provided in Sections 2.3.1 through 2.3.4.
2.3.1 Boiler Efficiency
During each test run performed, testing will be conducted to evaluate boiler efficiency. The data will be
used to document efficiencies during biomass co-firing and to normalize measured emission rates to
boiler output. Boiler efficiency will be determined following the Btu method in the B&W Steam manual
[1]. The efficiency determinations will also be used to estimate boiler heat input during each test period.
An example spreadsheet is included as Appendix B-2. Using this procedure, a number of boiler
operational parameters must be logged during the test periods. Table 2-6 summarizes the parameters
needed and the likely source of the data.
Both facilities are well instrumented and log all of the data required for determination of boiler efficiency
on a regular basis. Southern will verify the accuracy of as many facility logged data points as possible by
taking independent spot readings using calibrated sensors (details regarding these QC checks are provided
in Section 3.1). Other parameters such as ambient conditions and flue gas temperatures will be
independently measured by the Southern. The following subsections provide details regarding the
measurements required for efficiency determinations.
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Table 2-6. 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/hr
Combustion air temperature, °F
Steam flow, MMBtu/h or Ib/h
Steam pressure, psig
Steam temperature, °F
Supply water pressure, psig
Supply water temperature, °F
Power generation, kW
Fuel ultimate analyses, both wood and coal
Fuel heating value, Btu/lb
Unburned carbon loss, %
Source of Data
Southern measurements
Southern measurements
Facility operational data
Analytical laboratory
Logging Frequency
Five minute intervals
Twice per test run
One minute averages
One composite biomass,
coal, mixed fuel (UI - 10),
and fly ash samples per
test (3 total for each
condition)
2.3.1.1 Data Logged by Host Facilities
Prior to testing, instrumentation that currently exists on site and is available for collecting test data will be
inventoried and the following information collected:
1. Operational parameter
2. Description of operating principle (e.g. 'orifice plate flow meter')
3. Manufacturer
4. Model number
5. Range
6. Accuracy
7. Response time for sample interval
8. Date of calibration and calibration documentation
9. Measurement location
Wherever possible, cross-checks will be performed between Southern instruments and host-site
equipment. (For example a pressure gauge check at an available valve port, or temperature checks at
thermo-well or using a strap-on sensor.)
2.3.1.2 Data Logged by Southern
Southern will independently measure values contributing to efficiency calculations wherever placement
of measurement devices is feasible. Table 2-7 summarizes some of the measurements that Southern
expects to conduct independently, and the instruments that will be used. If possible, additional
measurements from the list in Table 2-6 (facility logged data) will be conducted or at least verified by
Southern.
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Table 2-7. Summary of Boiler Efficiency Parameters Logged by Southern
Operational Parameter
Fuel temperature, °F
Flue gas temperature at air heater
inlet, °F
Intake air temperature, °F
Moisture in air, Ib/lb dry air
Instrument
Hobo Model H12 with
Type K thermocouple
Hobo Model U10 Data
Logger
Instrument Range
0 - 932 °F
-20 to 158 °F
25 to 95 % relative humidity
Instrument
Accuracy
±6°F
±1°F
±3.5%
The Hobo sensors are equipped with data loggers that will be programmed to log data at 5 minute
intervals throughout the verification. Data logged during each test period will be averaged and the means
used in the efficiency determinations.
2.3.1.3 Fuel Sampling and Analyses
Fuel samples will be collected during each test run. These samples will undergo ultimate and heating
value analysis. A composite of grab samples of coal and biomass (or individual samples of coal and
biomass if fed separately) will be prepared during co-firing test runs and submitted to Wyoming
Analytical Laboratories, Inc. in Laramie, Wyoming for the analyses shown in Table 2-8. Fuel analyses
will be conducted following ASTM standard methods [2].
Table 2-8. Summary of Fuel Analyses
Parameter
Method
Ultimate analysis
Gross calorific value
ASTM D3 176
ASTM D5865 (coal) ASTM
E71 1-87 (biomass)
At Minnesota Power, coal and biomass will be sampled separately. Grab samples of each fuel will be
collected at 30 minute intervals during each test run and combined. One composite sample of each fuel
will be generated for each test run and submitted for analysis. Collected composite samples will be
labeled, packed and shipped to Wyoming Analytical along with completed chain-of-custody
documentation for off-site analysis.
At the UI site, coal samples and blended fuel samples will be collected in a similar matter during each test
run. However, because the blended fuel is delivered premixed, biomass samples will be collected at the
fuel blending facility (coal yard). These samples will be submitted to the field team leader for subsequent
analysis.
Finally, the efficiency analysis requires the unburned carbon loss value, or carbon content of fly ash.
Integrated fly ash samples will also be collected during each test run and submitted for analysis. Details
regarding the collection, handling, and analysis of fly ash samples are provided in Section 2.3.3.
The ultimate analysis will report the following fuel constituents as percent by weight:
• carbon
• water
• ash
• sulfur
• nitrogen
• hydrogen
• oxygen
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Results of these fuel analyses will be used to complete the combustion gas calculations in the Btu method.
For tests conducted during biomass co-firing, weighted average results of the biomass and coal fuel
analyses will be used in the calculations.
The sensitivity of the boiler efficiency analyses will be a function of the accuracy of all of the
contributing measurements. Southern will quantify the error in each of the measurements. By
determining the propagated overall error, the Southern will be able to estimate the sensitivity of the
analysis (that is, how small of a change in efficiency can be quantified). More detail regarding the DQOs
for this analysis are provided in Section 3.1 of this TQAP.
2.3.2 Boiler Emissions
Testing will be conducted on each boiler to determine emissions of the following atmospheric pollutants:
• nitrogen oxides (NOX) • carbon monoxide (CO) • particulate matter (total, PM10, and
• sulfur dioxide (SO2) • carbon dioxide (CO2) PM2.5)
• nitrous oxide (N2O), • primary metals (As, • secondary metals (optional)
optional Hg, Se, Zn) • acid gases (HC1, HF)
A total of three replicate test runs will be conducted on each boiler tested under both the baseline (coal
only) and co-firing operating conditions. Each test run will be approximately 60 minutes in duration.
The emissions testing will be conducted simultaneously with the efficiency evaluations.
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 will be reported in units of ppmvd for
NOX, CO, SO2, HC1, and HF, and percent for CO2. Concentrations of total particulate matter (TPM),
PM10 and PM2.5 will be reported as grains per dry standard cubic foot (gr/dscf). The average emission
rates for each pollutant will also be reported in units of pounds per hour (Ib/hr), and pounds per million
Btu (Ib/MMBtu).
The fuel heat input and boiler output values will be determined during the efficiency determinations. The
remainder of the required measurements will be determined through emissions testing. All testing will be
conducted following EPA Reference or Conditional Methods or for emissions testing [3]. Table 2-9
summarizes the reference methods to be used and the fundamental analytical principle for each method.
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Table 2-9. Summary of Emission Test Methods and Analytical Equipment
Parameter or
Measurement
NOX
CO
SO2
CO2
O2
TPM
PM10,PM2.5/con-
densable PM
Metals
HC1, HF
Moisture
Flue gas flow rate
U.S. EPA
Reference
Method
7E
10
6C
3A
3A
5
CTM040/202
29
26
4
2
Principle of Detection
Chemiluminescence
Non-dispersive infrared (NDIR)-gas filter correlation
Pulse fluorescence or NDUV
NDIR
Paramagnetic or electrochemical cell
Gravimetric
Gravimetric
ICP/CVAAS
Ion chromatography
Gravimetric
Pitot traverse
GE Energy, an organization specializing in air emissions testing will be contracted to perform all stack
testing. The testing contractor will provide all equipment, sampling media, and labor needed to complete
the testing and will operate under the supervision of Southern's Field Team Leader. The reference
methods provide detailed procedures for selecting measurement system performance specifications and
test procedures, quality control procedures, and emission calculations and are not repeated here.
All emissions tests will be conducted under steady state boiler operations and for durations of
approximately 60 minutes each. Steady state operations will be confirmed by the operator based on
achievement of desired nominal fuel and steam flow rates without undue variability. The testing will be
conducted downstream of the pollution control devices at each site as described in detail in the Site
Profiles.:
For isokinetic testing procedures at MP-5 (Methods 5, CTM040/202, and 29), the five ports shown in
Figure 2-2 will be used to conduct a 25 point duct traverse during each test. On UI-10, the eight ports
shown in Figure 2-3 will be used to conduct 32 point traverses. Testing for all other pollutants will be
conducted at a single point near the center of each duct.
Where available, the use of continuous emission monitoring systems (CEMS) will be used to measure
gaseous components such as NOX, SO2, CO, CO2, or O2 in lieu of reference methods. Where CEMS are
available (see Section 2.1), current audit materials will be reviewed to document CEMS accuracy and
functionality. Collected samples for determination of TPM, PM10, PM2.5, metals, HC1, and HF will be
recovered on-site at the conclusion of each test run, and then shipped to the emissions tester's analytical
laboratory along with completed chain-of-custody documentation for off-site analysis. All sample
handling and analysis will be conducted following reference method specifications. Appendix B-3
provides an example chain of custody form.
Details regarding the DQOs for emissions performance testing are provided in Section 3.1.1 of the TQAP.
2.3.3 Fly ash Characteristics
Fly ash samples will be collected during the efficiency and emissions testing periods to evaluate the
impact of biomass co-firing on ash composition. On MP-5, fly ash samples will be collected at the air
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heater outlet during each test run following EPA Reference Method 17 procedures. Depending on
particulate loadings encountered at each test site, fly ash collection testing will be of a duration that
allows testers to obtain ash samples of sufficient mass for the analytical procedures. This approach is not
logistically feasible on IU-10. Alternately, fly ash samples will be collected from hoppers on the
mechanical collector and ESP. Collected samples will be submitted to Wyoming Analytical along with
completed chain-of-custody documentation for determination of carbon, hydrogen, and nitrogen (CHN)
content, minerals content, and TCLP for RCRA metals including arsenic, barium, cadmium, chromium,
lead, mercury, selenium, and silver. The laboratory will also conduct tests to evaluate ash fusion
temperature, and air-entraining agents index. Results will be compared to the Class F (bituminous and
anthracite) or Class C (lignite and subbituminous) fly ash specifications. Table 2-10 summarizes the
analytical methods that will be used.
Table 2-10. Summary of Fly ash Analyses
Parameter
CHN
minerals
RCRA metals
Metals TCLP
Air-entraining agents index
Fly ash fusion temperature
Method
ASTM D5373 [2]
ASTM D4326-04 [2]
SW-846 3052/6010 [4]
SW-846 13 11/60 10 [4]
Foam Index Test
ASTM D 1857 [2]
The laboratory will report method precision using repeatability checks so that Southern can evaluate the
sensitivity of the analysis and level of change in each of the parameters that is quantifiable. More detail
regarding the DQOs for ash analyses is provided in Section 3.1 of the TQAP.
2.4 SUSTAINABILITY INDICATORS AND ISSUES
Sustainability is an important consideration regarding use of woody biomass as a renewable fuel source.
This project will evaluate certain sustainability issues for the two sites selected for field testing. The
following sustainability related issues will be examined:
Estimated daily and annual woody biomass consumption at the nominal co-firing rate
Biomass delivery requirements (distance and mode)
Coal delivery requirements (distance and mode)
Fly ash composition, use, and waste disposal including delivery distance and mode.
Biomass Consumption. Type, and Source
The projected daily and annual biomass consumption rate will be useful in determining whether the
supply of biomass is sustainable. Biomass consumption rates measured during the testing conducted at
each site will be used as the basis to estimate daily and annual biomass consumption for each site.
Estimates will be compared for reasonableness with site records if available. The source, type, and
compositional analyses of the biomass will also be documented during testing. If more than one source is
used, the sources and proportions used will be documented in the Site Profile and confirmed from site
documentation during testing.
Associated Biomass NOy Emissions
By evaluating the average biomass consumption rate at each site, upstream NOX and CO2 emissions
associated with the biomass supply can be estimated for each site. The distance between the biomass
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sources and the units tested along with NOX emission factors for the modes of transportation used to
deliver the biomass will be used to complete this analysis. Emission factors will be determined based on
EPA's AP 42 Emission Factors Database [5].
The same analysis will be conducted for delivery of an equivalent amount of coal (based on heat input)
that the biomass will offset, enabling analysts to determine if mining, processing, and transportation
related emissions are expected to increase or decrease as a result of co-firing biomass at each facility.
This type of analysis however is likely to be very complex and beyond the scope of this project.
Reporting the estimated NOX emissions associated with biomass delivery will provide the first step for
analysts wishing to complete the entire emissions offset estimation.
At the Minnesota Power site, the biomass is a combination of wood byproducts generated at a
neighboring industrial facility, a second industrial facility within 5 miles, and other sources up to 75 miles
from the site. Therefore, emissions associates with biomass delivery to the generator are expected to
provide a significant environmental benefit over coal-only operations.
For the University of Iowa however, the pelletized biomass is produced offsite, shipped to a fuel blending
facility, then shipped again to the power plant. Emissions associated with the delivery scenarios will be
estimated. The following data will be recorded for each plant:
• Mass of coal offset by co-firing (based on biomass heat input)
• Fuel source to generator distance, mode of transport, and mass per load for coal
• Fuel source to generator distance, mode of transport, and mass per load for biomass
• NOX emission factors for each transport type
An alternate scenario in which processing is performed locally using local biomass sources will also be
considered. This is representative of what is likely to occur should UI choose to switch to this fuel.
Solid Waste Issues
Results of the baseline coal fly ash analyses and the co-fired fuel fly ash analyses will be compared to
determine if co-firing biomass has a measurable impact on the carbon content of the ash with respect to
ASTM C618-05 [2] standards for cement admixtures. In addition, results of the RCRA metals analyses
for the baseline and co-fire ash will be compared to evaluate impact on metals content. The metals TCLP
analytical results will be used to examine if co-firing impacts fly ash characteristics with respect to the
TCLP standards cited in 40 CFR 261.24 [6].
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3.0 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. As such, test
results meeting the DQOs will provide an acceptable level of data quality for technology users and
decision makers.
The DQOs for this verification are qualitative in that the verification will produce 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 will meet the QA/QC requirements contained in the ASTM
Methods being used. The verification report will provide sufficient documentation of the QA/QC checks
for all of these determinations to evaluate whether the qualitative DQOs were met. These QA/QC checks
are described in Sections 3.1.1 and 3.1.2.
This verification will not include a stated DQO for boiler efficiency determinations. It is likely that for
certain measurements provided by the facility (e.g., steam flow, steam pressure, and steam temperature),
validation of measurement accuracy may not be possible. Confirmation of the availability of traceable
calibration and accuracy data will be contained in the final reports. Southern will attempt to validate the
accuracy of as many contributing measurements as possible as described in Section 3.1.3. Accuracies for
the boiler efficiency contribution will be propagated to estimate the overall uncertainty in reported boiler
efficiencies.
3.1.1 Emissions Testing QA/QC Checks
Each of the EPA Reference Methods proposed 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 will be included in the verification
report as documentation that the methods were properly executed. Key emissions testing QA/QC checks
are summarized in Table 3-1. Appendix C-l provides an example emissions analyzer calibration form.
Where facility CEMS are used, up to date relative accuracy test audit (RATA) certifications and quarterly
cylinder gas audits (CGAs) will serve be used in to document system accuracy and will be reported.
CEMS not meeting acceptable RATA and CGA criteria will not be used.
In addition to these internal QA/QC checks for each parameter, Southern will issue two independent
audits which will serve as performance evaluation audits (Section 4.5.4). A known concentration of NOX
procured from a reputable supplier of calibration gases will be submitted for blind analysis during field
testing. A NOX Protocol 1 calibration gas with a concentration near the range of readings found at the site
will be selected for the audit. A blind audit will also be submitted for the Hg analysis. A Hg standard of
known concentration will be procured from Accustandard and submitted to the analytical laboratory along
with the collected Hg samples for analysis.
The emissions testing completeness goal for this verification is to obtain valid data for 90 percent of the
test periods on each boiler tested.
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Table 3-1. Summary of Emission Testing Calibrations and QA/QC Checks
Parameter"
NOX,
CO,
C02,
O2,
SO2
NOX
TPM,
PM10,
PM2.5,
Metals
Metals
HC1,
HF
Calibration/QC
Check*
Analyzer calibration
error test
System bias checks
System calibration drift
test
NO2 converter
efficiency
Percent isokinetic rate
Analytical balance
calibration
Filter and reagent
blanks
Sampling system leak
test
Dry gas meter
calibration
Sampling nozzle
calibration
ICP/CVAAS
Sampling system leak
test
Dry gas meter
calibration
Ion chromatograph
When
Performed/Frequency
Daily before testing
Before each test run
After each test run
Once before testing
begins
After each test run
Daily before analyses
Once during testing
after first test run
After each test
Once before and once
after testing
Once for each nozzle
before testing
Analysis 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
98 % minimum
90 -110% for
TPM and metals,
80 - 120% for
PM10, PM2.5
± 0.0002 g
< 10 % of
paniculate catch
for first test run
O.02 cfm
±5%
±0.01 in.
±25% of expected
value
O.02 cfm
±5%
±10% of expected
value
Response to Check
Failure or Out of
Control Condition
Repair or replace
analyzer
Correct or repair
sampling system
Repeat test
Repair or replace
analyzer
Repeat test run
Repair/replace balance
Recalculate emissions
based on high blank
values
Repeat test
Recalculate emissions
based on average
calibration factor
Select different nozzle
Repeat calibration curve
Repeat test
Recalculate emissions
based on average
calibration factor
Repeat calibration curve
" EPA reference methods are used to determine each parameter as listed in Table 2-4.
* Definitions and procedures for each of the calibration and QC checks specified here are included in the applicable
reference method and not repeated here.
3.1.2 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 a strict internal quality assurance protocol, a copy of which is maintained at Southern. Each of
the analytical procedures used here (Tables 2-8 and 2-10) 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. Table 3-2 summarizes the key QA/QC checks for the ash and fuel analyses.
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Table 3-2. Fuel and Fly ash Analytical QA/QC Checks
Analysis
Fuel ultimate analysis
(D3176)
Fuel Calorific Value
(D5865)
Ash CHN (D5373)
Ash fusion temperature
(D1857)
Ash metals (3052/6010) and
metals TCLP (1311/6101)
Calibration/QC
Check2
Duplicate analysis
Matrix spike
analysis
Duplicate analysis
When
Performed
2 samples
Once per batch
of samples
2 samples
Allowable Result
± 10 % difference
Results ± 25 % of
expected value
± 20 % difference
Response to Check
Failure
When allowable
results are exceeded,
analysts will
investigate the
problem, repeat the
QA/QC check, and
repeat completed
analyses
" Definitions and procedures for each of the calibration and QC checks specified here are included in the applicable
reference method and not repeated here.
3.1.3 Boiler Efficiency QA/QC Checks
Table 3-3 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 will document achievement of
the MQOs. After each test run and upon receipt of the laboratory results, analysts will review the data
and classify it as valid or invalid. All invalid data should be associated with a specific reason for its
rejection, and the report should cite those reasons.
Table 3-3. 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 or Ib/h
Steam pressure, psig
Steam temperature, °F
Supply water pressure, psig
Supply water temperature, °F
Power generation, kW
Fuel feed rate, Ib/hr
Fuel ultimate analyses, both wood
and coal
Fuel heating value, Btu/lb
Unburned carbon loss, %
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
NIST-traceable calibration
ASTMD 1945 duplicate
sample analysis and
repeatability
ASTMD 1945 duplicate
sample analysis and
repeatability
Benzoic acid standard
calibration
When Performed
Upon purchase
and every 2 years
Annually
Upon installation
Annually
Annually
2 samples
Weekly
MQO
+ 6°F
+ 1 °F
+ 3.5%
+ 6°F
+ 5 % reading
+ 5 psig
+ 6°F
+ 5 psig
± 2 % of reference standard
+ 5 % reading
+ 5 % reading
Within D 1945 repeatability
limits for each fuel
component
Within D 1945 repeatability
limits for each fuel
component
+ 0.1 % relative standard
deviation
3-3
-------
Final Version - September 2006
The table lists the MQOs for each of the measurements. However, the actual measurement errors
determined using the QA/QC checks will be used to conduct the parameter uncertainty evaluation for
boiler efficiency. The uncertainty evaluation will be conducted by propagating the measurement errors
using the procedures detailed in Appendix D-l
3.2 INSTRUMENT TESTING, INSPECTION, AND MAINTENANCE
Southern personnel, the field team leader, or GE personnel will subject all emissions testing equipment to
the QC checks discussed earlier. Before tests commence, operators will assemble and test all equipment
as anticipated to be used in the field. They will, for example, operate and calibrate all controllers,
analyzers, computers, instruments, and other measurement system sub-components per the specified test
methods and/or this test plan. Test personnel will repair or replace any faulty sub-components before
starting the verification tests. Test personnel will maintain a small amount of consumables and frequently
needed spare parts at the test site. The field team leader, project manager, or GE Energy will handle
major sub-component failures on a case-by-case basis such as by renting replacement equipment or
buying replacement parts.
3.3 INSPECTION/ACCEPTANCE OF SUPPLIES, CONSUMABLES, AND SERVICES
The procurement of purchased items and services that directly affect the quality of environmental
programs defined by this TQAP will be planned and controlled to ensure that the quality of the items and
services is known, documented, and meets the technical requirements and acceptance criteria herein. For
this verification, this includes services provided by Wyoming Analytical for fuel and ash analyses and GE
Energy for emissions testing services.
Procurement documents shall contain information clearly describing the item or service needed and the
associated technical and quality requirements. The procurement documents will specify the quality
system elements of the TQAP for which the supplier is responsible and how the supplier's conformity to
the customer's requirements will be verified.
Procurement documents shall be reviewed for accuracy and completeness by the project manager and QA
manager as noted in Sections 1.4 and 4.2. Changes to procurement documents will receive the same level
of review and approval as the original documents. Appropriate measures will be established to ensure
that the procured items and services satisfy all stated requirements and specifications.
3.4 DATA QUALITY OBJECTIVES RECONCILIATION
A fundamental component of all verifications is the reconciliation of the collected data with its DQO. In
this case, the DQO assessment consists of evaluation of whether the stated methods were followed. The
field team leader and project manager will initially review the collected data to ensure that they are valid
and are consistent with expectations. They will assess the data's accuracy and completeness as they relate
to the stated QA / QC goals. If this review of the test data shows that QA / QC goals were not met, then
immediate corrective action may be feasible, and will be considered by the project manager. DQOs will
be reconciled after completion of corrective actions. As part of the internal audit of data quality, the
Southern QA Manager will include an assessment of DQO attainment.
3-4
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Final Version - September 2006
3.5 TRAINING AND QUALIFICATIONS
This test does not require specific training or certification beyond that required internally by the test
participants for their own activities. Southern's field team leader has approximately 20 years experience
in field testing of air emissions from many types of sources and will directly oversee field activities. He
is familiar with the test methods and standard requirements that will be used in the verification test.
The field team leader has performed numerous field verifications under the ETV program, and is familiar
with EPA and Southern quality management plan requirements. The QA Manager is an independently
appointed individual whose responsibility is to ensure Southern's conformance with the EPA approved
QMP.
3-5
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Final Version - September 2006
4.0 DATA HANDLING AND REPORTING
4.1 DATA ACQUISITION AND DOCUMENTATION
Test personnel will acquire the following electronic data and generate the following documentation
during the verification:
Boiler Operational Data
Boiler operations will be monitored for the following measurements:
Generator power output power quality parameters (if applicable)
Steam flow, temperature, and pressure
Intake air temperature and moisture
Flue gas and combustion air temperature
Supply water pressure and temperature
transfer fluid flow, supply temperature, and return temperature (if applicable)
ambient temperature and barometric pressure
Data collected using Southern instrumentation will be recorded as one-minute averages throughout all
tests and stored on a laptop computer. Data collected by the facilities will be downloaded in the format
and frequencies available and also stored on the laptop computer. Manually logged boiler data will be
stored in a field notebook.
Emissions Testing Data
Emissions testing will result in both electronic and manually recorded data. Southern personnel will
obtain copies of the electronic data from the emission testing contractor prior to leaving the site including
one-minute average pollutant values during test runs, pre- and post-test instrument calibrations, and
emission rate calculations. The contractor will also provide copies of manually recorded data, QA/QC
checks, and sample chain of custody records. After field testing, the contractor will submit to Southern a
comprehensive emissions testing report including descriptions of methods and instrumentation, dates of
analysis, test team participants, test results, sample chain of custody documentation, and all analytical
QA/QC procedures, calibrations, and results. The reports will be reviewed for completeness and
maintained at Southern.
Laboratory Reports
Laboratory reports will be obtained with results of the submitted fuel, fly ash, and emissions testing
samples. These reports will include analytical methods, dates of analysis, analyst names, sample results,
sample chain of custody documentation, and all analytical QA/QC procedures, calibrations, and results.
The reports will be reviewed for completeness and maintained at Southern.
Documentation
Printed or written documentation will be recorded on the log forms and will include:
• Daily test log including test participants, test conditions, starting and ending times for
test runs, notes, etc.
• Forms which show the results of QA / QC checks
4-1
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Final Version - September 2006
• Copies of calibrations and manufacturers' certificates
Southern will archive all electronic data, paper files, analyses, and reports at their Research Triangle Park,
NC office in accordance with their quality management plan.
4.1.1 Corrective Action and Assessment Reports
A corrective action will occur if audits or QA / QC checks produce unsatisfactory results or upon major
deviations from this TQAP. Immediate corrective action will enable quick response to improper
procedures, malfunctioning equipment, or suspicious data. The corrective action process involves the
field team leader, project manager, and QA Manager. Southern's QMP requires that test personnel
submit a written corrective action request to document each corrective action.
The field team leader will most frequently identify the need for corrective actions. In such cases, he or
she will immediately notify the project manager. The field team leader, project manager, QA Manager
and other project personnel, will collaborate to take and document the appropriate actions. Appendix C-2
includes a corrective action report form.
Note that the project manager is responsible for project activities. He is authorized to halt work upon
determining that a serious problem exists. The field team leader is responsible for implementing
corrective actions identified by the project manager and is authorized to implement any procedures to
prevent a problem from recurring.
4.2 DATA REVIEW, VALIDATION, AND VERIFICATION
The project manager will initiate the data review, validation, and analysis process. At this stage, analysts
will classify all collected data as valid, suspect, or invalid. Southern will employ the QA/QC criteria
specified in Section 3.0 and the associated tables. Source materials for data classification include factory
and on-site calibrations, maximum calibration and other errors, subcontractor deliverables, etc.
In general, valid data results from measurements which:
• meet the specified QA/QC checks, including subcontractor requirements,
• were collected when an instrument was verified as being properly calibrated, and
• are consistent with reasonable expectations (e.g., manufacturers' specifications,
professional judgment).
The report will incorporate all valid data. Analysts may or may not consider suspect data, or it may
receive special treatment as will be specifically indicated. If the DQO cannot be met, the project manager
will decide to continue the test, collect additional data, or terminate the test and report the data obtained.
Data review and validation will primarily occur at the following stages:
• on site ~ by the field team leader,
• upon receiving subcontractor deliverables,
• before writing the draft report ~ by the project manager, and
• during draft report QA review and audits ~ by Southern's QA Manager.
The field team leader's primary on-site functions will be to install and operate the test equipment. He will
review, verify, and validate certain data (QA / QC check results, etc.) during testing.
4-2
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Final Version - September 2006
The QA Manager will use this TQAP and documented test methods as references with which to review
and validate the data and the draft report. He will review and audit the data in accordance with
Southern's quality management plan. For example, the QA Manager will randomly select raw data,
including data generated and submitted by subcontractors, and independently calculate the verification
parameters. The comparison of these calculations with the results presented in the draft report will yield
an assessment of Southern's QA/QC procedures.
4.3 ASSESSMENTS AND RESPONSE ACTIONS
The field team leader, project manager, QA Manager, Southern's Program Director, and technical peer-
reviewers will assess the project and the data's quality as the test campaign proceeds. The project
manager and QA Manager will independently oversee the project and assess its quality through project
reviews, inspections if needed, a technical systems audit, an audit of data quality, and performance
evaluation audits.
4.3.1 Project Reviews
The project manager will be responsible for conducting the first complete project review and assessment.
Although all project personnel are involved with ongoing data review, the project manager must ensure
that project activities meet measurement and DQO requirements. The project manager is also responsible
for maintaining document versions, managing the review process, and ensuring that updated versions are
provided to reviewers and tracked.
Southern's Program Director will perform the second project review. The director is responsible for
ensuring that the project's activities adhere to the ETV program requirements and stakeholder
expectations. Southern's Program Director will also ensure that the field team leader has the equipment,
personnel, and resources to complete the project and to deliver data of known and defensible quality.
The QA Manager will perform the third review. He is responsible for ensuring that the project's
management systems function as required by the quality management plan. The QA Manager is
Southern's Program's final reviewer, and he is responsible for ensuring the achievement of all QA
requirements.
Client organizations and select members of the BCSG will then review the report. Finally, Southern's
Program will submit the draft report to EPA QA personnel, and the project manager will address their
comments as needed. Following this review, the report will undergo EPA management reviews,
including Southern's Program Director, EPA ORD Laboratory Director, and EPA Technical Editor.
4.3.2 Technical Systems Audit
The technical systems audit (TSA) will be conducted by the QA Manager during all phases of project
activities. This audit will evaluate all components of the data gathering and management system to
determine if these systems have been properly designed to meet the DQOs for this test. The TSA
includes a review of the experimental design, the Test Plan, and planned field procedures prior to field
activities. The review also includes an assessment of personnel qualifications, adequacy and safety of the
facility and equipment, and the data management system.
4-3
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Final Version - September 2006
During field testing activities, the QA Manager or his designee will inspect the analytical activities and
determine their adherence to the Test Plan. The auditor reports any area of nonconformance to the Field
Team Leader through an audit report. The audit report may contain corrective action recommendations.
If so, follow-up inspections may be required to ensure that corrective actions are taken.
4.3.3 Audit of Data Quality
The audit of data quality (ADQ) is an evaluation of the measurement, processing, and data analysis steps
to determine if systematic errors are present. The QA Manager, or designee, will randomly select
approximately 10 percent of the data. He will follow the selected data through analysis and data
processing. This audit is intended to verify that the data-handling system functions correctly and to assess
analysis quality. The QA Manager will also include an assessment of DQO attainment.
The QA Manager will route audit results to the project manager for review, comments, and possible
corrective actions. The ADQ will result in a memorandum summarizing the results of custody tracing, a
study of data transfer and intermediate calculations, and review of the QA/QC data. The ADQ report will
include conclusions about the quality of the data from the project and their fitness for the intended use.
The project manager will take any necessary corrective action needed and will respond by addressing the
QA Manager's comments in the verification report.
4.3.4 Performance Evaluation Audit
Two PEAs are designed to check the accuracy of the Hg analyses conducted by GE Energy's analytical
laboratory and the NOX determination in the field conducted by GE's field testing crew. As discussed in
Section 3.0, Hg and NOX audit samples will contain analytes of a known concentration. At the invitation
of the QA Manager, the Field Team Leader will conduct the PEAs. He will submit the audit materials to
the laboratories in such a manner as to have the concentration of the PEAs unknown or blind to the
analyst. Upon receiving the analytical data from the analyst, the Field Team Leader will evaluate the
performance data for compliance with the requirements of the project, and report the findings to the QA
Manager.
4.4 VERIFICATION REPORT AND STATEMENT
The report will summarize each verification parameter's results as discussed in Section 2.0 but will not
include the raw data or QA/QC checks that support the findings. All raw and processed measurements
data as well as calibration data and QA/QC checks will be made available to EPA as a separate CD, and
can be provided to other parties interested in assessing data trends, completeness, and quality by request.
The report will clearly characterize the verification parameters, their results, and supporting
measurements as determined during the test campaign. The report will also contain a Verification
Statement, which is a 3 to 5 page document summarizing the technology, the test strategy used, and the
verification results obtained.
The project manager will submit the draft report and Verification Statement to the QA Manager and
Southern's Director for review. A preliminary outline of the report is as follows:
4-4
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Final Version - September 2006
Preliminary Outline
Environmental and Sustainable Technology Evaluation -Biomass Co-firing in Industrial Boilers
Verification Statement
Section 1.0: Verification Test Design and Description
Description of the ESTE Program
Test Facility and Boiler Descriptions
Overview of the Verification Parameters and Evaluation Strategies
Section 2.0: Results
Boiler performance
Boiler emissions
Fly ash characteristics
Sustainability issues
Section 3.0: Reconciliation of Data Quality Objectives
Section 4.0: References
Appendices: Raw Verification or Other Data
Site Profiles
4-5
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Final Version - September 2006
5.0 HEALTH AND SAFETY PLAN
This section applies to Southern personnel and subcontractors. Other organizations involved in the
project have their own health and safety plans which are specific to their roles in the project.
Southern staff will comply with all known host, state/local and Federal regulations relating to safety at the
test facilities. This includes use of personal protective gear (such as safety glasses, hard hats, hearing
protection, safety toe shoes) as required by the host and completion of site safety orientation. Southern's
site safety plan for this verification will include adoption and adherence to the Facility's Site Specific
Safety Plans.
Both facilities maintain strict Site Specific Safety Plans that identify of key site personnel, location of
nearby medical facilities, required personal protective equipment, potential site hazards, and hazard
response activities. Should it be required by the host site or the Project Manager, test personnel will
undergo a safety briefing regarding site policies and procedures. While on-site, the Field Team Leader
will be responsible for ensuring compliance with site safety plans and will maintain a safety log form
such as the example in Appendix D-2.
5-1
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Final Version - September 2006
6.0 REFERENCES
[1] Babcock & Wilcox, Steam - it's Generation and Use - 40th Edition, The Babcock & Wilcox
Company, Barberton, Ohio, 1992.
[2] ASTM, ASTMStandards Catalog 2005, www.astm.org. American Society for Testing and
Materials, West Conshohocken, PA. 1999.
[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, SW-846 - Test Methods for Evaluating Solid Waste, Physical/chemical Methods,
http://www.epa.gov/epaoswer/hazwaste/test/sw846.htm, U.S. Environmental Protection Agency
Office of Solid Waste, Washington D.C., 2005.
[5] 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 B.C., 2005.
[6] 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.
6-1
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Final Version - September 2006
Appendix A-l.
Biomass Co-firing Stakeholder Group
Dr. Jim Cobb, University of Pittsburgh
Kim Grossman, U.S. EPA, CHP Partnerships
Keith Cummer, Black & Veatch
Jim Eddinger, U.S. EPA, OAQPS
Dennis Kennedy, Duke University
Dr. David Kirchgessner, U.S. EPA, ORD
Dr. Alex Livnat, U.S. EPA, Office of Solid Waste
Bob Morrow, Detroit Stoker
Bill Perdue, American Furniture Mfr's Association
Donna Perla, U.S. EPA, ORD Sustainable Development
Dr. John Pinkerton, NCASI
John Steinhoff, Envise
Bryce Stokes, Forest Service, Vegetation Mgmt
Tom Tucker, Envise
A-l
-------
Final Version - September 2006
Project ID:_
Date:
Appendix B-l
Test Log Form
Unit Description:
Clock synchronization performed (Initials):.
Location (city, state):.
Signature:
Run ID:
Time
Boiler Load Setting
Biomass Blend Rate, %
Steam Flow, MMBtu/hr
Steam Pressure, psig
Steam Temperature, °F
Combustion Air Temp., °F
Ambient Temp., °F
Ambient Pressure, psia
Generating Rate, kW
Start
End
Notes:
B-l
-------
Final Version - September 2006
Appendix B-2
Boiler Efficiency Calculations
- Babcock & Wilcox -
Table 13A
Combustion Calculations- Btu Method
INPUT CONDITIONS-BY TEST OB SPECIFICATION
1
2
3
4
5
6
7
a
8
10
It
1?
13
14
22
23
24
25
26
27
28
28
30
31
32
33
34
35
36
37
Excess air at towrner/leaving bolietfecon, % by wetplit
Entering air temperature, F
Reference temperature, F
Fuel temperature, F
Air temperature leaving ai? heater, F
Flue gas temperature leaving (excluding teakage), F
Moisture In air, 1Mb dry sir
Additional moisture. IW100 Ib fuel
Residue leaving bolter/economizer, % Total
Output, 1,000,000 Bill*
20/20
m
SO A
80 B
3SO C
390 D
BM3 E
0 f
85 G
285.6 H
Corrections for sorheint {from Table 14 if used)
Additional theoretical air, IWIO.OOO atu Table tt.ltem [21]
CO, Ifom sortwnt. IWW.OOO Btu Table 14,ltem [1fl]
H/} from sorbent, IbHOjOtM Blu Table 14,ltem (20)
Spent sorbent, itmo.OOO Btu Table U.itcm [24|
0 18
0 19
C 20
0 2t
COMBUSTION QAS CALCULATIONS, Quantity f 10,000 Btu Fuel Input
Theoretical air (corrected), Ibl 10,090 Btu
Residue Irom (uul. ibno.OOO Btu
Total residue, lb/10,000 Btu
FUEL- Bituminous coal. Virginia
15 I UltimsiG Analyses
Ccwi^tituant % by weight
c ao.st
S 1S4
H2 44T
Hf> ZSO
N, t.3S
O, 285
Ash &SS
Total 100 00
te [ Thfio Air IWHW l& Iu6! 17 | H^O, ibf 100 Ib ru*l
K1 [IS)xK1 K2
11.S1 324.4 : "", , -
4JS «,7
34.29 rS3.3 8.94
- " v ; 1.00
- 4.32 - 12.3 ,-•-,--•
Air 1072.1 H/J
Higher heating value (H HVt. Btunb luel
Unt>urne
04,1
/6(M
oyi
(20) - [21j x 1(51 '{«»] + [11J [ 7,57?
fltSG) + (21]| * 100 /[18J I 004v
(23} * [Ml 1 0 04i
Ai
Excess air. % by weight
Dry air, lb/10,000 Stu
MjO from air, IW1O.OOO Btu
Additional moisture, U10.000 Blu
HjQ from f u«l, IWIO.OOO Btu
Wet gas Irom fuel, IWIO.QQO Btu
CO, from sorOent, IWW.OOO 8tu
Hjgjroni sofbanl, IbdO.OOO Blu
Total wel gas, IbMQ.OOO Blu
Water in wel gas, IWIO.OOO Btu
Dry gas, Ibf 10,000 Blu
HjO in gas, % by weight
Residue, % by weight
[26] x [7]
At Sufnens I B InfllfrAtion
MO I 00
[8)11001(181
I™i5jipji'8i
(100 - (16G) - [21])* 100 ([1H]
[12)
(13)
Summatton [26] through (32]
Summation [27] + [28] + [29] + |32J
(33] - (34J
[WOJx [34]/(331
H x (2*1 ; [Ml
908S- •
one 0119 one
o.ooo "-woj O-000
0.304 ^ Lj^'i O304
oeeo\ „ -
0000} ^ ' j
0.000 O.OOO1 0000
S.964f
042f\ 0.<»l 04?}
90H*
0111
OOOfl^
....' "1
o.ooo
9.SSJ
041'J
9.442 9.442
4.28 4.1S
0.42 041
EFFICIENCY CALCULATIONS, % Inimt from Fuel
38"
39
40
41
42
43
44
45
46
47
48
49
SO
51
52
S3
Losses
Dry fl»s, %
Walw from Enthalpy o! slsam at 1 psl, T = (6)
fuel, as-fired Enthalpy of water at T a J3]
%
Moislure in air. %
UnbuTned carbon, %
RadlaNon and convec^onL%
Unaccounted lor and manufacturers margin, %
Sorbenl net losses, % if sorbertt Is used
Summation of losses, %
Credrls
Heat in dry asr, ^ft
Heat in moisture In air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
0.0024 K[3SD]xJ6]
-PB
H, = (3.SS8E-5 XT + 0.4326) xT + 1062.2
H, f [3| - 32
j3*j3ar,Hoi0
0.0045 x |S70| x ({8)
- |3](
I19] or (21] x 14.500/ [18]
ABMA curve, Chapter 22
From Table It Item [41]
Summation [38| Ihroustt [46)
0 0024 x |26D) x p)
-[3»
0.0045 X |27D] X ([21 - [3D
(H al T[4] - H al T [3J x 100 / [16]
Summation [48] through [51 ]
100 - [4?1 + 1521
KEV PERFORMANCE PARAMETERS
54
55
56
57
58
sa
60
61
Input from fuel, 1,000,000 Slufh
Fuel rats, 1000 Uh
Wel gas weight, 1000 Ibrti
Air to burners (wM), IW10,000 Blu
Air to burners (wet), 1000 lb;ti
Heal available, 1,000,000 Blum
H. = = (3SJ
1337.1
48.0
'Ml
— '.™
asr
040
0.40
1.50
0.00
13M
000
0.00
0.00
0.00
o.w
ses?
Leaving Furnace f Leaving Blr^Econ
• -
, 1™"~-, l •; ,
32B.S ':
2JJ
324.1 324.1
9205 ,^^;Jt._,J,,^.... '
301 6
MS 2
1034! : .
^.,,
3SSO
Steam 40 / Principles of Combustion
B-2
-------
Final Version - September 2006
Appendix B-3
Southern Research Institute Chain-of-Custody Record
Important: Use separate Chain-of-Custody Record for each laboratory and/or sample type.
Project ID: Location (city, state):
Originator's signature:.
Unit description:.
Sample description & type (gas, liquid, other.):
Laboratory: Phone:_
Address: City:
Relinquished by:_
Received by:
Relinquished by:_
Received by:
Relinquished by:_
Received by:
Fax:_
State:
Zip:_
Sample ID
Date, Time Collected
Sample Matrix
Sample Temp. (°F)
Analyses Req'd
Date:_
Date:_
Date:_
Date:_
Date:_
Date:
Time:.
Time:.
Time:.
Time:.
Time:.
Time:
Notes: (shipper tracking #, other)_
B-3
-------
Version 1.2-July 2006
Do not cite, quote, use, or distribute without written permission from Southern
Appendix C-l
Example Emissions Testing Calibrations
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Appendix C-2. Corrective Action Report
Corrective Action Report
Verification Title:
Verification Description:,
Description of Problem:_
Originator: Date:
Investigation and Results:,
Corrective Action Taken:
Investigator: Date:
Originator: Date:_
Approver: Date:_
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Appendix D -1. Uncertainty Estimation
This Appendix presents compounded error estimation procedures for quantities which are developed from
two or more instruments (or analyses) with individual measurement errors. In addition to following the
specified procedures to evaluate data quality, evaluation and reporting of the achieved uncertainty is an
important aspect of this TQAP. Where applicable, two methods of uncertainty evaluation are acceptable.
For boiler efficiency determinations, the achieved parameter uncertainty may be calculated based on
actual measurement instrument calibration data, actual laboratory error, field conditions, and other
uncertainties determined as described in the TQAP. Analysts may compound the measurement errors to
determine the achieved uncertainty (or relative error) for the parameter of interest using the methods
specified below.
Measurement Error
This Appendix defines measurement error, uncertainty, or accuracy as the combination of all contributing
instrument errors and instrument precision. It makes no effort to separate the two or to quantify sampling
error. An instrument manufacturer's accuracy specification (or laboratory analysis accuracy statement,
etc.) is sufficient if it is accompanied, at a minimum, by current applicable National Institutes of
Standards and Technology (NIST)-traceable calibration(s), appropriate QA/QC checks, or other
supporting documents which support the accuracy statements.
Absolute and Relative Errors
Absolute measurement error is an absolute value compared to a given value or operating range. An
example is: "±0.6 °F between 100 and 212 °F" for a temperature meter.
Relative measurement error, generally stated as a percentage, is:
PW
errrd = a-^-100 Eqn. G-1
reading
Where:
errrei = relative error, percent
errabs = absolute error, stated in the measurement's units
reading = measurement result, stated in the measurement's units
The reference basis for relative accuracy statements can be either the instrument's full scale or span or the
measurement reading. The following examples show the relationships between relative and absolute
measurement errors.
Relative Error Accuracy Statement FS (or span) Absolute Error
"Temperature accuracy is ± 1.0 %, FS" 120 °F ±1.2 °F at 60 °F
"Temperature accuracy is ± 1.0 % of reading" n/a ± 0.6 °F at 60 °F
Compounded Error for Added and Subtracted Quantities
For added or subtracted quantities, the absolute errors compound as follows:
22 Eqn. G-2
Where:
errc abs = compounded error, absolute
= error in first added or subtracted quantity, absolute value
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errabs2 = error in second subtracted quantity, absolute value
As an example, a heat transfer fluid AT is defined as the difference between Tsuppiy and Treturn. The
uncertainties in each temperature measurement compound together to yield the overall AT uncertainty. If
the absolute error for each temperature meter is ± 0.6 °F, from 100 to 212 °F. The resulting AT absolute
error is constant at V0.62 +0.62 , or ± 0.85 °F. Relative error will vary with the actual AT found during
testing.
Compounded Error for Multiplied or Divided Quantities
For two multiplied or divided quantities, the relative errors compound to yield the overall error estimate:
Where: errc rei = compounded relative error, percent
erri rei = relative error for first multiplied quantity, percent
err2, rei = relative error for second multiplied quantity, percent
For example, a power meter measures the current (CT) output and applies the appropriate scaling factor
by multiplication. For a meter with current THD accuracy of ± 4.9 percent at 360 Hz, compounded with
the specified ±1.0 percent CT accuracy at that frequency, the overall current THD accuracy is
V4.92 +1.02 or ± 5.0 percent.
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Appendix D-2. Site Safety Log Form
Site Safety Plan
Site Name: Southern Research Site Personnel:
Address: Namel:
Contact Name: Home Phone: CellPhone:
Contact Phone: Name2:
Home Phone: CellPhone:
Company Contact Name:
Company: Local Hospital Name:
Contact Phone: Address: Phone:
Work Dates: Signature I/date:
Signature2/date:
Southern Research Safety Officer signature/date:
Southern Research Office Contact:
Backup Contact:
Work Description:
This project will require extended presence in industrial setting and close proximity to industrial boilers. Collection
of coal, wood, and fly ash samples and supervision of emissions testing crews.
Expected Hazards, Hazardous Conditions, or Potentially Hazardous Systems:
|^ Flying fragments, dust, or dirt
O Illumination or work lighting O Electrical wiring
|^ Climbing, scaffolding, or access CH Power systems; VAC
|^ Lifting or material moving O Control/DAS systems; VDC
|^ Handling hot objects CH Plumbing
£3 Falling objects, bumps, pinchpoints O Water; °F _ psig
£3 Noise CD Potable CH Black/gray
£3 Breathing or atmospheric hazard O Liquid; °F psig
O Extreme ambient heat or cold Description:
Splashes or spills £3 Gas; °F 750 psig
Description: Flue gases
Engineering, Personal Protective Equipment, or other methods to address each expected hazard
checked above:
IMPORTANT: During field execution of this project, all Southern Research field personnel must wear
hard hats, safety glasses, hearing protection, long sleeve shirts, trousers, and leather or other hard closed-
toe shoes (not tennis or running shoes) during testing. Rings and other jewelry should be removed during
field activities. Head coverings are recommended at all times.
~ Southern Research site personnel will check in with the site contact upon arrival and at the start of each work day
and will abide by all site safety requirements not specified here.
~ Flying fragments, dust, or dirt: Southern Research site personnel will wear safety glasses with side shields while
dismounting, disassembling, and packing test equipment and collecting fuel and ash samples.
~ Climbing, scaffolding, or access: Southern Research site personnel will use only existing ladders, platforms, and
scaffolds that are approved by the facility safety manager to access sampling points.
~ Lifting or material moving: Manual handling of the equipment is unavoidable, and some may be heavy. Southern
Research site personnel will seek local assistance if necessary to lift or move heavy equipment. They will also
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review the NC "Guide to Manual Materials Handling and Back Safety" and undergo a training session at the RTF
office prior to departure.
~ Handling hot objects: Test personnel will use high temperature gloves and great caution when removing hot
probes from contact with hot flue gases. Probes will be allowed to cool a minimum of 30 minutes prior to
disassembly or sample recovery.
~ Noise: Hearing protection is required when working at or near the boilers.
~ Breathing or Atmospheric Hazards: Fitted half mask respirators will be available near work sites for respiratory
protection should excess dust or fumes be evident.
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