SRI/USEPA-GHG-VR-22
September 2004
Environmental
Technology
Verification Report
Swine Waste Electric Power and Heat
Production - Martin Machinery Internal
Combustion Engine
Prepared by:
Greenhouse Gas Technology Center
Southern Research Institute
Under a Cooperative Agreement With
U.S. Environmental Protection Agency
and
Under Agreement With
Colorado Governor's Office of Energy Management and
Conservation
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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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THE ENVIRONMENTAL TECHNOLOGY VERIFICATION PROGRAM
&EPA
U.S. Environmental Protection Agency
ETV Joint Verification Statement
TECHNOLOGY TYPE: Biogas-Fired Internal Combustion Engine Combined
With Heat Recovery System
APPLICATION: Distributed Electrical Power and Heat Generation
TECHNOLOGY NAME: Martin Machinery Internal Combustion Engine
COMPANY: Colorado Pork, LLC
ADDRESS: Lamar, Colorado
The U.S. Environmental Protection Agency (EPA) has created the Environmental Technology
Verification (ETV) program to facilitate the deployment of innovative or improved environmental
technologies through performance verification and dissemination of information. The goal of the ETV
program is to further environmental protection by accelerating the acceptance and use of improved and
cost-effective technologies. ETV seeks to achieve this goal by providing high-quality, peer-reviewed data
on technology performance to those involved in the purchase, design, distribution, financing, permitting,
and use of environmental technologies.
ETV works in partnership with recognized standards and testing organizations, stakeholder groups that
consist of buyers, vendor organizations, and permitters, and with the full participation of individual
technology developers. The program evaluates the performance of technologies by developing test plans
that are responsive to the needs of stakeholders, conducting field or laboratory tests, collecting and
analyzing data, and preparing peer-reviewed reports. All evaluations are conducted in accordance with
rigorous quality assurance protocols to ensure that data of known and adequate quality are generated and
that the results are defensible.
The Greenhouse Gas Technology Center (GHG Center), one of six verification organizations under the
ETV program, is operated by Southern Research Institute in cooperation with EPA's National Risk
Management Research Laboratory. A technology of interest to GHG Center stakeholders is the use of
microturbines and engines as distributed generation sources. Distributed generation (DG) refers to
power-generation equipment that provides electric power at a site much closer to customers than central
station generation. Recently, biogas production from livestock manure management facilities has become
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a promising alternative for fueling DG technologies. These technologies, commonly referred to as
anaerobic digesters, decompose manure in a controlled environment and recover methane produced from
the manure digestion. The recovered methane can fuel power generators to produce electricity, heat, and
hot water. Digesters also reduce foul odor and can reduce the risk of ground- and surface-water pollution.
The GHG Center collaborated with the Colorado Governor's Office of Energy Management and
Conservation (OEMC) to evaluate the performance of two combined heat and power systems (CHP
systems) that operate on biogas recovered from anaerobic digestion of swine waste at the Colorado Pork
farm in Lamar, Colorado. This verification statement provides a summary of the test results for the
internal combustion (1C) engine CHP system designed and installed by Martin Machinery, Inc.
TECHNOLOGY DESCRIPTION
The following technology description is based on information provided by Martin Machinery and OEMC
and does not represent verified information. The CHP system tested includes an 1C engine, a generator,
and a heat exchanger. Power is generated with a Caterpillar (Model 3306 ST) 1C engine with a rated
nominal power output of 100 kW (60 °F, sea level). The engine is a 6 cylinder, 4-stroke, naturally
aspirated unit with a 10.5:1 compression ratio and a speed range of 1,000 to 1,800 rpm. The 1C engine is
used to drive an induction generator manufactured by Marathon Electric (Model No. MCTG-80-3).
The generator produces nominal 208 volts alternating current. The unit supplies a constant electrical
frequency of 60 Hz, and is equipped with a control system that allows for automatic and unattended
operation. All operations, including startup, operational setting (kW command), dispatch, and shutdown,
are performed manually. Electricity generated at this load is fully consumed by equipment used at the
facility. During normal farm operations, power demand exceeds the available capacity of the
engine/generator set, and power is drawn from the grid. On rare occasions when the power generated
exceeds farm demand, a reverse power relay (required by the utility company) throttles down the engine.
In the event of a grid power failure, the biogas induction generator is shut down, and the facility has a
backup emergency generator to provide power for farm operations.
No digester gas conditioning or compression is needed to operate the engine under site conditions.
Digester gas is directed to the engine and fired at the pressure created in the digester (approximately 17 to
18 inches water column). Because the digester gas is not conditioned (e.g., moisture and sulfur removal),
engine lubrication oil is changed every 10 days as precautionary maintenance. The configuration of the
engine's fuel input jets, along with the low heating value of the biogas (approximately 625 Btu/scf),
currently restrict the engine's power output to approximately 45 kW. This is lower than the equipment
manufacturer's (Caterpillar) recommended minimum rating for this engine.
The engine is equipped with a Thermal Finned Tube (Model 12-12-60CEN-W) heat exchanger for heat
recovery. The heat recovery system consists of a fin-and-tube heat exchanger that circulates water
through the heat exchanger at approximately 120 gallons per minute (gpm). The engine exhaust, at
approximately 1,100 °F, is the primary source of heat to the exchanger. The engine cooling water is also
cycled through the digester heating loop to recover additional heat and provide engine cooling.
Circulation of engine coolant is thermostatically controlled to maintain coolant temperature at
approximately 175 °F. In the event temperatures exceed 185 °F, excess heat is discarded with the use of
an external radiator. The radiator's return water line serves as the coolant for the engine water jacket.
The Colorado Pork facility is a sow farrow-to-wean farm in Lamar, Colorado that began operation in
1999 and houses up to 5,000 sows. The facility employs a complete mix anaerobic digester to reduce
odor and meet water quality regulations mandated by the Colorado Department of Public Health and
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Environment. The anaerobic digester promotes bacterial decomposition of volatile solids in animal
wastes. The resulting effluent stream consists of mostly water, which is allowed to evaporate from a
secondary lagoon. Solids produced by the process accumulate in the digester and are manually removed.
Recovered heat from the 1C engine CHP is circulated through the waste in the digester to maintain the
digester temperature at approximately 100 °F. Cool water returning from the digester remains relatively
constant throughout the year (approximately 100 °F). A temperature sensor continuously monitors this
temperature, and in the event this temperature exceeds 105 °F, an automated mixing valve reduces the
flow of hot water entering the digester.
VERIFICATION DESCRIPTION
Testing was conducted during the period of February 2 through 13, 2004. The verification included a
series of controlled test periods in which the GHG Center intentionally controlled the unit to produce
electricity at three power output levels within its range of operation at this site including 30, 38, and 45
kW. Three replicate test runs were conducted at each setting. The controlled test periods were preceded
by 9 days of continuous monitoring to verify electric power production, heat recovery, and power quality
performance over an extended period. Normal site operations were maintained during all test periods,
where heat was recovered and routed through the digester at temperatures of approximately 105 °F. The
classes of verification parameters evaluated were:
• Heat and Power Production Performance
• Emissions Performance (NOX, CO, CH4, SO2, TRS, TPM, NH3, and CO2)
• Power Quality Performance
Evaluation of heat and power production performance included verification of power output, heat
recovery rate, electrical efficiency, thermal efficiency, and total system efficiency. Electrical efficiency
was determined according to the ASME Performance Test Code for Internal Combustion Engines (ASME
PTC-17). Tests consisted of direct measurements of fuel flow rate, fuel lower heating value (LFfV), and
power output. Heat recovery rate and thermal efficiency were determined according to ANSI/ASHRAE
test methods and consisted of direct measurement of heat-transfer fluid flow rate and differential
temperatures. Ambient temperature, barometric pressure, and relative humidity measurements were also
collected to characterize the condition of the combustion air used by the engine. All measurements were
recorded as 1-minute averages during the controlled test periods and throughout the 7-day monitoring
period.
The evaluation of emissions performance occurred simultaneously with efficiency testing. Pollutant
concentration and emission rate measurements for nitrogen oxides (NOX), carbon monoxide (CO), total
hydrocarbons (THC), methane (CH4), sulfur dioxide (SO2), total reduced sulfur (TRS), total particulate
matter (TPM), ammonia (NH3), and carbon dioxide (CO2) were conducted in the engine exhaust stack.
All test procedures used in the verification were U.S. EPA reference methods recorded in the Code of
Federal Regulations (CFR). Pollutant emissions are reported as concentrations in parts per million
volume, dry (ppmvd) corrected to 15-percent oxygen (O2), and as mass per unit time (Ib/hr). The mass
emission rates are also normalized to engine power output and reported as pounds per kilowatt hour
(Ib/kWh).
Annual NOX and CO2 emissions reductions for the engine were estimated by comparing measured Ib/kWh
emission rates with corresponding emission rates for the baseline power-production systems (i.e., average
regional grid emission factors for U.S. and Colorado). Electrical power quality parameters, including
electrical frequency and voltage output, were measured during the 9-day extended test. Current and
voltage total harmonic distortions (THD) and power factors were also monitored to characterize the
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quality of electricity supplied to the end user. The guidelines listed in "The Institute of Electrical and
Electronics Engineers' (IEEE) Recommended Practices and Requirements for Harmonic Control in
Electrical Power Systems" were used to perform power quality testing.
Quality Assurance (QA) oversight of the verification testing was provided following specifications in the
ETV Quality Management Plan (QMP). The GHG Center's QA manager conducted an audit of data
quality on at least 10 percent of the data generated during this verification and a review of this report.
Data review and validation was conducted at three levels including the field team leader (for data
generated by subcontractors), the project manager, and the QA manager. Through these activities, the
QA manager has concluded that the data meet the data quality objectives that are specified in the Test and
Quality Assurance Plan.
VERIFICATION OF PERFORMANCE
Test results are representative of engine operations at this site only. Although not independently verified,
heat and power production performance and particularly CO and THC emissions performance were likely
negatively impacted by operating the engine below manufacturer's recommended minimum rating. The
digester system's operation, maintenance, or design could have also negatively impacted engine
performance.
Heat and Power Production Performance
ENGINE CHP HEAT AND POWER PRODUCTION
Test Condition
(Power
Command)
45 kW
38 kW
30 kW
Electrical Power Generation
Power
Delivered
(kW)
44.7
37.5
29.6
Efficiency
(%)
19.7
17.1
13.8
Heat Recovery Performance
Heat Recovery
(103Btu/hr)
250
227
219
Thermal
Efficiency
(%)
32.4
30.3
30.0
Total CHP
System
Efficiency
(%)
52.1
47.4
43.8
• At a 45 kW power command, average power output was 44.7 kW and electrical efficiency averaged 19.7
percent.
• Electrical efficiency at the reduced loads was 17.1 percent at a power output of 37.5 kW, and 13.8
percent at 29.6 kW.
• Total CHP efficiency during the controlled test periods ranged from 52.1 percent at the 45 kW load to
43.8 percent at 30 kW. Normal heat recovery operations were maintained during the controlled test
periods with the system configured to maintain the digester temperature at approximately 100 °F.
• During the 9-day monitoring period, the engine operated on biogas for a total of 75 hours. During this
time, a total of 3,358 kWh electricity was generated at an average rate of 44.6 kW, and 17.85 million Btu
(5,232 kWh) of heat was recovered and used at an average heat recovery rate of 238 x 103 Btu/hr.
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Emissions Performance
ENGINE EMISSIONS (Ib/kWh)
Power
Command
45 kW
38 kW
30 kW
NOX
0.012
0.006
0.002
CO
0.058
Above range
Above range
CH4
0.112
0.114
0.150
SO2
0.023
0.024
0.030
TRS
0.005
0.007
0.009
TPM
0.00009
Not tested
Not tested
NH3
0.000004
Not tested
Not tested
CO2
1.97
2.07
2.21
• NOX emissions at 45 kW were 0.012 Ib/kWh and decreased as power output decreased. CO
emissions averaged 0.058 Ib/kWh at 45 kW and exceeded the analytical range of the CO
analyzer at the lower loads (greater than 10,000 ppm).
• Hydrocarbon emissions were also very high. THC concentrations were above the analyzer
range (10,000 ppm as CHO and therefore not reported. Using an on-site gas chromatograph
and flame ionization detector, analysts were able to quantify QrU emissions at an average of
0.112 Ib/kWh at 45 kW. CH4 emissions increased to a high of 0.150 Ib/kWh at the 30 kW
power command.
• Emissions of SO2 and TRS averaged 0.023 and 0.005 Ib/kWh respectively at 45 kW. Both
increased slightly at the lower loads tested. Emissions of TPM and NH3 were very low
during the full load tests.
• NOX emissions per unit electrical power output at 45 kW (0.012 Ib/kWh), are higher than the average
fossil fuel emission levels reported for the U.S. and Colorado regional grids (0.0066 and 0.0077
Ib/kWh respectively). The average fossil fuel CO2 emissions for the U.S. and Colorado regional grids
are estimated at 2.02 and 2.13 Ib/kWh, both slightly higher than the engine CHP emissions of 1.97
Ib/kWh at maximum power output. These values yield an average annual emission increase of 0.37
and 0.29 tons (82 and 55 percent) for NOX for the two scenarios. Annual CO2 emissions are
estimated to be reduced by the CHP by 137 and 145 tons (2.2 and 7.6 percent) for the two scenarios.
These estimated changes in annual emissions are based on electrical generation only and do not
include environmental benefits that may be realized through recovery and use of waste heat.
Power Quality Performance
• Average electrical frequency was 59.998 Hz and average voltage output was 208.63 volts.
• The power factor remained relatively constant for all monitoring days with an average of 79.74 percent.
• The average current total harmonic distortion was 5.23 percent and the average voltage THD was 0.92
percent. The THD threshold specified in IEEE 519 is ± 5 percent.
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Details on the verification test design, measurement test procedures, and Quality Assurance/Quality
Control (QA/QC) procedures can be found in the Test plan titled Test and Quality Assurance Plan for
Swine Waste Electric Power and Heat Production Systems: Capstone MicroTurbine and Martin
Machinery Internal Combustion Engine (SRI 2002). Detailed results of the verification are presented in
the Final Report titled Environmental Technology Verification Report for Swine Waste Electric Power
and Heat Production - Martin Machinery Internal Combustion Engine (SRI 2004). Both can be
downloaded from the GHG Center's web-site (www.sri-rtp.com) or the ETV Program web-site
(www. epa. gov/etv).
Signed by Lawrence W. Reiter, Ph.D. 9/27/04 Signed by Stephen D. Piccot 9/13/04
Lawrence W. Reiter, Ph.D. Stephen D. Piccot
Acting Director Director
National Risk Management Research Laboratory Greenhouse Gas Technology Center
Office of Research and Development Southern Research Institute
Notice: GHG Center verifications are based on an evaluation of technology performance under specific,
predetermined criteria and the appropriate quality assurance procedures. The EPA and Southern Research Institute
make no expressed or implied warranties as to the performance of the technology and do not certify that a
technology will always operate at the levels verified. The end user is solely responsible for complying with any and
all applicable Federal, State, and Local requirements. Mention of commercial product names does not imply
endorsement or recommendation.
EPA REVIEW NOTICE
This report has been peer and administratively reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Mention of trade names or commercial products does not constitute endorsement or
recommendation for use.
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SRI/USEPA-GHG-VR-22
September 2004
Greenhouse Gas Technology Center
A U.S. EPA Sponsored Environmental Technology Verification ( £j^ ) Organization
Environmental Technology Verification Report
Swine Waste Electric Power and Heat Production
Martin Machinery Internal Combustion Engine
Prepared By:
Greenhouse Gas Technology Center
Southern Research Institute
PO Box 13825
Research Triangle Park, NC 27709 USA
Telephone: 919/806-3456
Under EPA Cooperative Agreement CR 829478
U.S. Environmental Protection Agency
Office of Research and Development
National Risk Management Research Laboratory
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711 USA
EPA Project Officer: David A. Kirchgessner
Colorado Governor's Office Project Officer: Edward Lewis
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TABLE OF CONTENTS
Page
LIST OF FIGURES iii
LIST OF TABLES iii
ACKNOWLEDGMENTS iv
ACRONYMS AND ABBREVIATIONS v
1.0 INTRODUCTION 1-1
1.1. BACKGROUND 1-1
1.2. CONBINED HEAT AND POWER TECHNOLOGY DESCRIPTION 1-3
1.3. TEST FACILITY DESCRIPTION 1-5
1.4. PERFORMANCE VERIFICATION OVERVIEW 1-7
1.4.1. Heat and Power Production Performance 1-8
1.4.2. Power Quality Performance 1-12
1.4.3. Emissions Performance 1-13
1.4.4. Estimated Annual Emission Reductions 1-14
2.0 VERIFICATION RESULTS 2-1
2.1. OVERVIEW 2-1
2.2. HEAT AND POWER PRODUCTION PERFORMANCE 2-3
2.2.1. Electrical Power Output, Heat Recovery Rate, and Efficiency During
Controlled Tests 2-3
2.2.2. Electrical and Thermal Energy Production and Efficiency During the
Extended Test Period 2-6
2.3. POWER QUALITY PERFORMANCE 2-8
2.3.1. Electrical Frequency 2-8
2.3.2. Voltage Output 2-8
2.3.3. Power Factor 2-9
2.3.4. Current and Voltage Total Harmonic Distortion 2-10
2.4. EMISSIONS PERFORMANCE 2-12
2.4.1. CHP System Stack Exhaust Emissions 2-12
2.4.2. Estimation of Annual Emission Reductions 2-15
3.0 DATA QUALITY ASSESSMENT 3-1
3.1. DATA QUALITY OBJECTIVES 3-1
3.2. RECONCILIATION OF DQOs AND DQIs 3-2
3.2.1. Power Output 3-5
3.2.2. Electrical Efficiency 3-6
3.2.2.1. PTC-17 Requirements for Electrical Efficiency Determination 3-7
3.2.2.2. Ambient Measurements 3-8
3.2.2.3. Fuel Flow Rate 3-8
3.2.2.4. Fuel Lower Heating Value 3-8
3.2.3. Heat Recovery Rate and Efficiency 3-8
3.2.4. Total Efficiency 3-9
3.2.5. Exhaust Stack Emission Measurements 3-10
3.2.5.1. NOX, CO, CO2, SO2, TRS, and O2 Concentrations 3-10
3.2.5.2. CFLt Concentrations 3-11
3.2.5.3. Total Particulate Matter and Exhaust Gas Volumetric Flow Rate 3-12
3.2.5.4. NH3 Concentrations 3-12
4.0 REFERENCES 4-1
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LIST OF FIGURES
Pas
Figure 1-1
Figure 1-2
Figure 1-3
Figure 1-4
Figure 1-5
Figure 2-1
Figure 2-2
Figure 2-3
Figure 2-4
Figure 2-5
Figure 2-6
Figure 2-7
Figure 2-8
Figure 2-9
The Colorado Pork 1C Engine CHP System 1-3
1C Engine CHP System Process Diagram 1-4
Colorado Pork Anaerobic Digester 1-5
Colorado Pork Waste-to-Energy Process Diagram 1-7
Schematic of Measurement System 1-11
Engine Operations During Extended Monitoring Test Periods 2-2
CHP System Efficiency During Controlled Test Periods 2-6
Heat and Power Production During the Extended Monitoring Period 2-7
Ambient Temperature Effects on Power and Heat Production 2-7
1C Engine Frequency During Extended Test Period 2-8
1C Engine Voltage During Extended Test Period 2-9
1C Engine Power Factor During Extended Test Period 2-10
1C Engine Current THD During Extended Test Period 2-11
1C Engine Voltage THD During Extended Test Period 2-11
LIST OF TABLES
Pas
Table 1-1
Table 1-2
Table 1-3
Table 1-4
Table 2-1
Table 2-2
Table 2-3
Table 2-4
Table 2-5
Table 2-6
Table 2-7
Table 2-8
Table 3-1
Table 3-2
Table 3-3
Table 3-4
Table 3-5
Martin Machinery CHP Specifications 1-4
Controlled and Extended Test Periods 1-9
Summary of Emissions Testing Methods 1-13
CO2 and NOX Emission Rates for Two Geographical Regions 1-15
Engine CHP Heat and Power Production Performance 2-4
Engine CHP Fuel Input and Heat Recovery Unit Operating Conditions 2-5
Electrical Frequency During Extended Period 2-8
1C Engine Voltage During Extended Period 2-9
Power Factors During Extended Period 2-10
1C Engine THD During Extended Period 2-10
1C Engine CHP Emissions During Controlled Periods 2-13
Comparison of 1C Engine CHP Emissions to Regional Emissions for Equivalent
Grid Power 2-16
Verification Parameter Data Quality Objectives 3-1
Summary of Data Quality Goals and Results 3-3
Results of Additional QA/QC Checks 3-6
Variability Observed in Operating Conditions 3-7
Summary of Emissions Testing Natural Calibrations and QC Checks 3-11
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ACKNOWLEDGMENTS
The Greenhouse Gas Technology Center wishes to thank the Colorado Governor's Office of Energy
Management and Conservation, especially Edward Lewis, for providing funding for this project, and for
reviewing and providing input on the testing strategy and this Verification Report. Thanks are also
extended to the Colorado Pork Farm (a subsidiary of Custom Swine Corporation) for hosting the
verification. Finally, special thanks to Gerald Licano of Colorado Pork for his assistance with site
operation and execution of the verification testing.
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ACRONYMS AND ABBREVIATIONS
Abs Diff.
AC
acf
ADER
ADQ
amp
ANSI
APPCD
ASHRAE
ASME
Btu
Btu/hr
Btu/lb
Btu/min
Btu/scf
CAR
Cl
CH4
CHP
CO
CO2
CT
DAS
DG
DOE
DP
DQI
DQO
dscf/106Btu
EIA
EPA
ETV
°C
°F
FID
fps
ft3
gal
GC
GHG Center
gpm
GU
Hg
HHV
hr
absolute difference
alternating current
actual cubic feet
average displaced emission rate
Audit of Data Quality
amperes
American National Standards Institute
Air Pollution Prevention and Control Division
American Society of Heating, Refrigerating and Air-Conditioning Engineers, Inc.
American Society of Mechanical Engineers
British thermal units
British thermal units per hour
British thermal units per pound
British thermal units per minute
British thermal units per standard cubic foot
Corrective Action Report
quantification of methane
methane
combined heat and power
carbon monoxide
carbon dioxide
current transformer
data acquisition system
distributed generation
U.S. Department of Energy
differential pressure
data quality indicator
data quality objective
dry standard cubic feet per million British thermal units
Energy Information Administration
Environmental Protection Agency
Environmental Technology Verification
degrees Celsius
degrees Fahrenheit
flame ionization detector
feet per second
cubic feet
U.S. gallons
gas chromatograph
Greenhouse Gas Technology Center
gallons per minute
generating unit
Mercury (metal)
higher heating value
hour
(continued)
IV
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Hz
1C
IEEE
ISO
kVA
kVAr
kW
kWh
kWhe
kWh/yr
Ib
Ib/Btu
Ib/dscf
lb/ft3
Ib/hr
Ib/kWh
Ib/yr
LHV
103Btu/hr
106Btu/hr
106cf
mol
N2
NDIR
NIST
NO
NO2
NOX
NSPS
02
O3
OEMC
ORD
PEA
ppmv
ppmvw
ppmvd
psia
psig
PT
QA/QC
ACRONYMS/ABBREVIATIONS
(continued)
hertz
internal combustion
Institute of Electrical and Electronics Engineers
International Standards Organization
kilovolt-amperes
kilovolt reactive
kilowatts
kilowatt hours
kilowatt hours electrical
kilowatt hours thermal
kilowatt hours per year
pounds
pounds per British thermal unit
pounds per dry standard cubic foot
pounds per cubic feet
pounds per hour
pounds per kilowatt-hour
pounds per year
lower heating value
thousand British thermal units per hour
million British thermal units per hour
million cubic feet
mole
nitrogen
nondispersive infrared
National Institute of Standards and Technology
nitrogen oxide
nitrogen dioxide
nitrogen oxides
New Source Performance Standards
oxygen
ozone
Colorado Governor's Office of Energy Management and Conservation
Office of Research and Development
Performance Evaluation Audit
parts per million volume
Parts per million volume wet
parts per million volume, dry
pounds per square inch, absolute
pounds per square inch, gauge
potential transformer
Quality Assurance/Quality Control
(continued)
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QMP
Rel. Diff.
Report
RH
rms
RTD
scf
scfh
scfm
Southern
T&D
Test plan
THCs
THD
TSA
U.S.
VAC
ACRONYMS/ABBREVIATIONS
(continued)
Quality Management Plan
relative difference
Environmental Technology Verification Report
relative humidity
root mean square
resistance temperature detector
standard cubic feet
standard cubic feet per hour
standard cubic feet per minute
Southern Research Institute
transmission and distribution
Test and Quality Assurance Plan
total hydrocarbons
total harmonic distortion
technical systems audit
United States
volts alternating current
VI
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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 Technology Verification (ETV) program to facilitate the deployment of innovative
technologies through performance verification and information dissemination. The goal of ETV is to
further environmental protection by accelerating the acceptance and use of improved and innovative
environmental technologies. Congress funds ETV 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 Greenhouse Gas Technology Center (GHG Center) is one of six verification organizations operating
under the ETV program. The GHG Center is managed by EPA's partner verification organization,
Southern Research Institute (Southern), which conducts verification testing of promising greenhouse gas
mitigation and monitoring technologies. The GHG Center's verification process consists of developing
verification protocols, conducting field tests, collecting and interpreting field and other data, obtaining
independent peer-reviewed input, and reporting findings. Performance evaluations are conducted
according to externally reviewed verification Test and Quality Assurance Plans (test plan) and established
protocols for quality assurance.
The GHG Center is guided by volunteer groups of stakeholders. These stakeholders guide the GHG
Center on which technologies are most appropriate for testing, help disseminate results, and review Test
plans and Technology Verification Reports (report). The GHG Center's Executive Stakeholder Group
consists of national and international experts in the areas of climate science and environmental policy,
technology, and regulation. It also includes industry trade organizations, environmental technology
finance groups, governmental organizations, and other interested groups. The GHG Center's activities
are also guided by industry specific stakeholders who provide guidance on the verification testing strategy
related to their area of expertise and peer-review key documents prepared by the GHG Center.
A technology of interest to GHG Center stakeholders is the use of microturbines and engines as
distributed generation sources. Distributed generation (DG) refers to power-generation equipment,
typically ranging from 5 to 1,000 kilowatts (kW), that provide electric power at a site much closer to
customers than central station generation. A distributed power unit can be connected directly to the
customer or to a utility's transmission and distribution system. Examples of technologies available for
DG include gas turbine generators, internal combustion engine generators (e.g., gas, diesel),
photovoltaics, wind turbines, fuel cells, and microturbines. DG technologies provide customers one or
more of the following main services: stand-by generation (i.e., emergency backup power), peak shaving
capability (generation during high-demand periods), baseload generation (constant generation), or
cogeneration {combined heat and power [CHPJgeneration}.
Recently, biogas production from livestock manure management facilities has become a promising
alternative for fueling DG technologies. EPA estimates annual U.S. methane emissions from livestock
manure management at 17.0 million tons carbon equivalent, which accounts for 10 percent of total 1997
methane emissions. The majority of methane emissions come from large swine and dairy farms that
manage manure as slurry. EPA expects U.S. methane emissions from livestock manure to grow by over
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25 percent from 2000 to 2020. Cost effective technologies are available that can stem this emission
growth by recovering methane and using it as an energy source. These technologies, commonly referred
to as anaerobic digesters, decompose manure in a controlled environment and recover methane produced
from the manure. The recovered methane can fuel power generators to produce electricity, heat, and hot
water. Digesters also reduce foul odor and can reduce the risk of ground- and surface-water pollution.
The GHG Center and the Colorado Governor's Office of Energy Management and Conservation (OEMC)
agreed to collaborate and share the cost of verifying two DG technologies that operate on biogas
recovered from swine waste. These verifications evaluated the performance of a microturbine combined
heat and power (CHP) system offered by Capstone Turbine Corporation and an internal combustion (1C)
engine CHP system offered by Martin Machinery, Inc. Both units are currently in operation at an
anaerobic digestion facility managed by Colorado Pork, LLC near Lamar, Colorado. This is the only
swine farm in Colorado that is producing electrical power from animal waste. The electricity is used by
Colorado Pork to offset electricity purchases from the local electric cooperative. Some of the recovered
heat is used to control digester temperature, which optimizes and enhances biogas production. Both CHP
systems are interconnected to the electric utility grid, but excess power is not presently exported. The
OEMC team is currently under negotiations with the local utility to export power for sale.
The GHG Center evaluated the performance of the two CHP systems by conducting field tests over a
fourteen-day verification period (February 2 - 15, 2004). These tests were planned and executed by the
GHG Center to independently verify the electricity generation rate, thermal energy recovery rate,
electrical power quality, energy efficiency, emissions, and greenhouse gas emission reductions for the
Colorado Pork farm. This verification statement and report provides the results of the 1C engine CHP
performance evaluation. Results of the testing conducted on the microturbine CHP system are reported in
a separate report titled Environmental Technology Verification Report - Swine Waste Electric Power and
Heat Production - Capstone 30 kWMicroturbine System [1].
Details on the verification test design, measurement test procedures, and Quality Assurance/Quality
Control (QA/QC) procedures can be found in the test plan titled Test and Quality Assurance Plan - Swine
Waste Electric Power and Heat Production Systems: Capstone Microturbine and Martin Machinery
Internal Combustion Engine [2]. It can be downloaded from the GHG Center's web-site (www.sri-
rtp.com) or the ETV Program web-site (www.epa.gov/etv). The test plan describes the rationale for the
experimental design, the testing and instrument calibration procedures planned for use, and specific
QA/QC goals and procedures. The Test plan was reviewed and revised based on comments received
from OEMC and the EPA Quality Assurance Team. The Test plan meets the requirements of the GHG
Center's Quality Management Plan (QMP) and satisfies the ETV QMP requirements. Deviations from the
Test plan were required in some cases. These deviations and the alternative procedures selected for use
were initially documented in Corrective Action Reports (CARs) and are discussed in this report.
The remainder of Section 1.0 describes the 1C engine CHP system technology and test facility and
outlines the performance verification procedures that were followed. Section 2.0 presents test results, and
Section 3.0 assesses the quality of the data obtained.
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1.2. CONBINED HEAT AND POWER TECHNOLOGY DESCRIPTION
The Colorado Pork facility uses an 1C engine fired with digester gas to generate electricity and thermal
energy. This system, designed and built by Martin Machinery, is one of the first cogeneration
installations in the country that generates both electrical and thermal energy using digester gas for fuel.
The CHP system tested (Figure 1-1) includes an 1C engine, an electric generator, and a heat exchanger.
Figure 1-2 illustrates a simplified process flow diagram of the CHP system, and a discussion of key
components is provided.
Digester Gas
Fuel Supply
100 kW
Generator
Cold Water Return
From Digester
pt Water Supply
to Digester
Caterpillar Model
3306 1C Engine
Finned Tube
Heat Exchanger
Figure 1-1. The Colorado Pork 1C Engine CHP System
Power is generated with a Caterpillar (Model 3306 ST) 1C engine, with a nominal power output of 100
kW (60 °F, sea level). Table 1-1 summarizes the specifications reported by Martin Machinery for this
engine/generator set. The 1C engine is a 6 cylinder, 4-stroke, naturally aspirated unit with a 10.5:1
compression ratio and a speed range of 1,000 to 1,800 rpm. The 1C engine is used to drive an induction
generator manufactured by Marathon Electric (Model No. MCTG-80-3). This engine was overhauled in
December 2003.
The generator produces nominal 208 volts alternating current (VAC). The unit supplies a constant
electrical frequency of 60 Hz, and is supplied with a control system that allows for automatic and
unattended operation. All operations, including startup, operational setting (kW command), dispatch, and
shutdown, are performed manually.
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Cool Water ^m
^^*-
Air Intake
CHP System From To
Exhaust Digester Digester
Raw Biogas
Input
Utility Grid
Figure 1-2. 1C Engine CHP System Process Diagram
Table 1-1. Martin Machinery CHP Specifications
(Source: Colorado Pork, Martin Machinery)
Weight
Max. engine speed
Electrical inputs
Electrical outputs
Fuel pressurerequired
Fuel input
Electrical efficiency,
lower heating value
(LHV) basis
Heat rate
Heat recovery potential
Engine only
Power (startup)
Power at ISO conditions 60 °F (at sea level)
for electric
w/o gas compressor
Heat input
Flow rate (LHV = 905 btu/ft3)
With natural gas (ISO conditions)
At full load
Exhaust gas temperature
Exhaust energy available for heat recovery
2,090 Ib
1,800 rpm
Utility grid or backup generator
100 kW, 208 VAC,
60 Hz, 3 -phase
2 to 20 psi, nominal
1, 133,060 Btu/hr at 100 kW
905,000 Btu/hr at 75 kW
~ 820,292 Btu/hr at 65 kW
693,230 Btu/hr at 50 kW
1,252 scfh at 100 kW
!,OOOscfhat75kW
766 scfh at 50 kW
30% at 100 kW
28% at 75 kW
25% at 50 kW
ll,331Btu/kWh
1,100 °F
508,980 Btu/hr at 100 kW
3 11,954 Btu/hr at 50 kW
Biogas production rate, biogas heat content, and engine fuel jet configuration currently limit engine
operation to approximately 45 kW, or about 45 percent of rated capacity when operating on biogas. It
should be noted here that operation at this load is below the engine manufacturer's recommended
minimum operating point of 50 percent of rating. Electricity generated at this load is fully consumed by
equipment used at the facility. During normal farm operations, power demand exceeds the available
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capacity of the engine and generator set, and additional power is drawn from the grid. Typically, the
engine is run at 45 kW and switched to run on natural gas overnight to avoid reducing biogas pressure and
collapsing the digester cover. When the microturbine is used, it can be run on biogas continuously. In the
event of a grid power failure, the engine shuts down and the facility has a backup emergency generator to
provide power for farm operations.
No digester gas conditioning or compression is needed to operate the engine under site conditions.
Digester gas is directed to the engine and fired at the pressure created in the digester (approximately 17 to
18 inches water column). Because the digester gas is not conditioned (e.g., moisture and sulfur removal),
engine lubrication oil is changed every 10 days as precautionary maintenance.
The engine is equipped with a thermal finned tube (Model 12-12-60CEN-W) heat exchanger for heat
recovery. The heat recovery system consists of a fin-and-tube heat exchanger, which circulates water
through the heat exchanger at approximately 120 gallons per minute (gpm). The engine exhaust, at
approximately 1,100 °F, is the primary source of heat to the exchanger. The engine cooling water is also
cycled through the digester heating loop to recover additional heat and provide engine cooling.
Circulation of engine coolant is thermostatically controlled to maintain coolant temperature at
approximately 175 °F. In the event temperatures exceed 185 °F, excess heat is discarded with the use of
an external radiator. The radiator's return water line serves as the coolant for the engine water jacket.
1.3. TEST FACILITY DESCRIPTION
The Colorado Pork facility is a sow farrow-to-wean farm in Lamar, Colorado that began operation in
1999 and houses up to 5,000 sows. The facility employs a complete mix anaerobic digester (Figure 1-3)
to reduce odor and meet water quality regulations mandated by the Colorado Department of Public Health
and Environment. The anaerobic digester promotes bacterial decomposition of volatile solids in animal
wastes. The resulting effluent stream consists of mostly water, which is allowed to evaporate from a
secondary lagoon.
Figure 1-3. Colorado Pork Anaerobic Digester
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Waste from 5,000 sows is collected in shallow pits below the slatted floors of the hog barns. These pits
are connected via sewer lines to an in-ground concrete holding tank (50,000 gallon capacity). Each
morning, the pits are drained on a rotating basis to flush about 15,000 gallons of waste to the holding
tank. The holding tank is equipped with a 17 horsepower (Hp) chopper pump that breaks up large pieces
of waste. Each morning, about 15,000 gallons of waste is pumped from the holding tank into the digester.
The digester is a 70 x 80 x 14 foot deep in-ground concrete tank with a capacity of 500,000 gallons. The
digester is equipped with two propeller type mixers on each end. The mixers normally operate for 30
minutes daily to rejuvenate gas production that would otherwise decline between waste charging events.
Hot water is circulated through the digester using a matrix of 3-inch black steel pipe (total length of about
0.5 mile) to maintain the digester temperature at 100 °F. Small adjustments to the water flow rate are
required periodically and are conducted manually by the site operator. The retention time in the digester
is about 40 days.
The effluent exits the digester over a weir, and is directed gravimetrically to a lagoon for sludge settling
and water evaporation. The lagoon is designed to hold up to 20 years of sludge production. Tests
performed by environmental regulatory personnel have determined the site meets current odor and
discharge requirements.
The biogas produced from the decomposed waste is collected under a high-density polyethylene (HDPE)
cover at a pressure of 15 to 20 inches water column. A manifold collects the biogas and routes it to the
engine/turbine building. A pressure relief valve senses pressure buildup when neither the engine nor the
turbine are operating, and diverts the biogas to a flare. The digester is currently producing about 20,000
cubic feet of biogas per day. The primary gas constituents of the raw biogas are CH4 (around 67 %) and
CO2 (approximately 32 %). Analysis of samples collected at the site show hydrogen sulfide (H2S)
concentrations in the gas ranging from 700 to 6,800 parts per million (ppm) and averaging around 6,000
ppm. The gas also contains trace amounts of ammonia (NH3), mercaptans, and other noxious gases, and
is saturated with water vapor. The lower heating value (LHV) of the biogas is approximately 625 Btu/scf.
Figure 1-4 is a schematic of the waste-to-energy production process at Colorado Pork showing integration
of the digester, 1C engine CHP, and microturbine CHP. In May 2000, the 1C engine CHP system was
installed first to offset electricity purchase costs. The microturbine CHP system was installed in February
2002, to evaluate the feasibility and economics of the two different power generation technologies. Both
systems are currently housed in a building adjacent to the digester.
With the 1C engine CHP system, biogas is not pre-treated. The 1C engine's heat recovery system
produces hot water at approximately 105 °F. In the event this temperature exceeds 185 °F (i.e., during
extremely hot summer days), an automatic valve is activated, which discards some of the excess heat
through a radiator. The radiator's return water line is used to cool the engine water jacket and prevent
overheating the engine.
The 1C engine hot water line combines with the microturbine hot water line, and the mixture is circulated
through the waste in the digester to maintain the digester temperature at 100 °F. Cool water returning
from the digester remains relatively constant throughout the year (approximately 100 °F). A temperature
sensor continuously monitors this temperature, and in the event this temperature exceeds 105 °F, an
automatic mixing valve reduces the flow of hot water entering the digester. This adjustment is performed
only a few times per year, as digester temperatures remain relatively stable.
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Raw B log as
(nominal 17 in. w.c.
5% H,0)
Waste from holding
tank, 15,000 gallons
per day
Effluent to lagoon
If water temperature at this
point is >105°F, then valve is
opened to divert hot water
from entering digester loop
If water temperature at this
point is >185°F, then valve is
opened to reject heat and cool
engine water jacket
Figure 1-4. Colorado Pork Waste-to-Energy Process Diagram
1.4. PERFORMANCE VERIFICATION OVERVIEW
This verification test was designed to evaluate the performance of the 1C engine CHP system—not the
overall system integration or specific management strategy. The test plan specified a series of controlled
test periods in which the GHG Center intentionally modulated the unit to produce electricity at nominal
power output commands of 40, 50, 65, and 80 kW. Additionally, the test plan specified that these tests
would be conducted with the heat recovery potential maximized by increasing the hot water supply
temperature from the heat recovery unit to approximately 135 °F. However, changes in CHP system
operations at the farm have occurred since development of the test plan. Specifically, engine operation is
currently limited to approximately 45 kW when operating on biogas due to limitations in gas production
rate and the design of the engines' fuel delivery system. In addition, hot water supply temperatures are
controlled to maintain the optimum digester temperature of approximately 100 °F. It was not possible
during the verification testing to reach the power output levels or supply temperatures originally proposed
without adversely affecting digester operations.
Instead, the center conducted the tests at nominal power output commands of 30, 38, and 45 kW. The
heat recovery unit was set to operate under normal conditions to maintain digester temperature. At this
condition, hot water supply temperatures were approximately 105 °F during the tests. Three replicate
controlled load test runs were conducted at each of the three power output settings.
The controlled test periods were preceded by a 9-day period of extended monitoring to evaluate power
and heat production and power quality over a range of ambient conditions and farm operations. During
this period, site operators maintained typical 1C engine operations as previously described. Specifically,
the engine was run on biogas or natural gas intermittently as allowed by biogas production rates. In
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addition, three short engine shutdown episodes occurred to allow for routine maintenance. More details
regarding the engine operations during this period are provided in Section 2.0.
The specific verification parameters associated with the test are listed below. Brief discussions of each
verification parameter and its method of determination are presented in Sections 1.4.1 through 1.4.5.
Detailed descriptions of testing and analysis methods are provided in the test plan and not repeated here.
Heat and Power Production Performance
• Electrical power output and heat recovery rate at selected loads
• Electrical, thermal, and total system efficiency at selected loads
Power Quality Performance
• Electrical frequency
• Voltage output
• Power factor
• Voltage and current total harmonic distortion
Emissions Performance
• Nitrogen oxides (NOX), carbon monoxide (CO), total hydrocarbons (THC),
ammonia (NH3), total reduced sulfur (TRS), total particulate matter (TPM),
carbon dioxide (CO2), and methane (CH^ concentrations at selected loads
• NOX, CO, THC, NH3, TRS, TPM, CO2, and CHt emission rates at selected
loads
• Estimated NOX and greenhouse gas emission reductions
Each of the verification parameters listed were evaluated during the controlled or extended monitoring
periods as summarized in Table 1-2. This table also specifies the dates and time periods during which the
testing was conducted.
Simultaneous monitoring for power output, heat recovery rate, heat input, ambient meteorological
conditions, and exhaust emissions was performed during each of the controlled test periods. Manual
samples of biogas were collected to determine fuel lower heating value and other gas properties.
Replicate and average electrical power output, heat recovery rate, energy conversion efficiency
(electrical, thermal, and total), and exhaust stack emission rates are reported for each test period.
Results from the extended test are used to report total electrical energy generated and used on site, total
thermal energy recovered, greenhouse gas emission reductions, and electrical power quality. Greenhouse
gas emission reductions for on-site electrical power generation are estimated using measured greenhouse
gas emission rates and emissions estimates for electricity produced at central station power plants.
1.4.1. Heat and Power Production Performance
Electrical efficiency determination was based upon guidelines listed in ASME Performance Test Code for
Reciprocating Internal Combustion Engines, PTC-17 [3], and was calculated using the average measured
net power output, fuel flow rate, and fuel lower heating value (LHV) during each controlled test period.
The fluid circulation pump that drives the hot water through the engine heat exchanger and digester
heating loop is the only parasitic load for this CHP system. This verification did not include a separate
measurement of this parasitic load, but evaluated electrical power output after the pump and therefore
reports the net system efficiency (based on the usable power delivered by the system).
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Table 1-2. Controlled and Extended Test Periods
Controlled Test Periods
Start Date,
Time
02/10/04, 16:00
02/11/04,15:47
02/12/04, 16:45
End Date,
Time
02/11/04,14:30
02/12/04, 16:07
02/13/04, 12:25
Test Condition
Power command of 45 kW, three 60-minute
test runs (120 minutes for TPM and NH3)
Power command of 30 kW, three 60-minute
test runs
Power command of 38 kW, three 60-minute
test runs
Verification Parameters Evaluated
NOX, CO, SO2, TRS, TPM, NH3, CH4, CO2
emissions, and electrical, thermal, and total
efficiency
NOX, CO, SO2, TRS, CH4, CO2 emissions,
and electrical, thermal, and total efficiency
Extended Test Period
Start Date,
Time
02/02/04, 10:30
End Date,
Time
02/11/04,10:30
Test Condition
Engine operated as dispatched by farm
operators
Verification Parameters Evaluated
Total electricity generated; total heat
recovered; power quality; and emission
offsets
The electrical power output was measured continuously throughout the verification period using
instrumentation provided and installed by the GHG Center. Heat input was determined by metering the
fuel consumption and determining biogas energy content. Fuel gas sampling and energy content analysis
(via gas chromatograph) was conducted according to ASTM procedures to determine the lower heating
value of the biogas. Ambient temperature, relative humidity, and barometric pressure were measured
near the engine air intake to support the determination of electrical conversion efficiency as required in
PTC-17. Electricity conversion efficiency was computed by dividing the average electrical energy output
by the average energy input using Equation 1.
T)=-
34U.\4kW
(Equation.1)
where:
*7 = efficiency (%)
kW = average net electrical power output measured over the test interval (kW),
(engine power output minus power consumed by circulation pump)
HI = average heat input using LHV over the test interval (Btu/hr); determined by
multiplying the average mass flow rate of biogas to the system converted to standard
cubic feet per hour (scfh) times the gas LHV (Btu per standard cubic foot, Btu/scf)
3412.14 = converts kW to Btu/hr
Simultaneous with electrical power measurements, heat recovery rate was measured using a heat meter
(Controlotron Model 1010EP). The meter enabled 1-minute averages of differential heat exchanger
temperatures and water flow rates to be monitored. Published fluid density and specific heat values for
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water were used so that heat recovery rates could be calculated at actual conditions per ANSI/ASHRAE
Standard 125 [4].
Heat Recovery Rate (Btu/min) =VpCp(Tl-T2) (Equation. 2)
where:
V = total volume of liquid passing through the heat meter flow sensor during a minute (ft3)
p = density of water solution (lb/ft3), evaluated at the avg. temp. (T2 plus Tl)/2
Cp = specific heat of water solution (Btu/lb °F), evaluated at the avg. temp. (T2 plus Tl)/2
Tl = temperature of heated liquid exiting heat exchanger (°F), (see Figure 1-4)
T2 = temperature of cooled liquid entering heat exchanger (°F), (see Figure 1-4)
The average heat recovery rates measured during the controlled tests and the extended monitoring period
represent the heat recovery performance of the CHP system. Thermal energy conversion efficiency was
computed as the average heat recovered divided by the average energy input:
riT = 60* Qavg /HI (Equation. 3)
where:
T|T = thermal efficiency
Qavg = average heat recovered (Btu/min)
HI = average heat input using LFfV (Btu/hr); determined by multiplying the average mass
flow rate of natural gas to the system (converted to scfh) times the gas LFfV (Btu/scf)
Figure 1-5 illustrates the location of measurement variables contained in Equations 1 through 3. Power
output was measured using a 7500 ION Power Meter (Power Measurements Ltd.) at a rate of
approximately one reading every 8 to 12 milliseconds and logged on the center's data acquisition system
(DAS) as 1-minute averages. The power meter was located in the main switchbox connecting the CHP to
the host site and represented power delivered to the farm. The logged one-minute average kW readings
were averaged over the duration of each controlled test period to compute electrical efficiency. The kW
readings were integrated over the duration of the verification period to calculate total electrical energy
generated in units of kilowatt hours (kWh).
Biogas fuel input was measured with an in-line Dresser-Roots Series B Model 3M175 rotary type
displacement meter. Meter readings were recorded, manually at 10-minute intervals during the controlled
test periods, and daily during the extended monitoring period. Gas temperature and pressure sensors were
installed to enable flow rate compensation to provide mass flow output at standard conditions (60 °F,
14.696 psia).
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CHP System From To
Exhaust Digester Digester
Raw Biogas
Input
Utility Grid
Figure 1-5. Schematic of Measurement System
A total of six biogas samples were collected and analyzed during the controlled test periods to determine
gas composition and heating value. Samples were collected at a point in the biogas delivery line
downstream of the meter and are representative of the 1C engine fuel. All samples were submitted to
Empact Analytical Systems, Inc., of Brighton, CO, for compositional analysis in accordance with ASTM
Specification D1945 for quantification of methane (Cl) to hexane plus (C6+), nitrogen, oxygen, and
carbon dioxide [5]. The compositional data were then used in conjunction with ASTM Specification
D3588 to calculate LHV and the relative density of the gas [6].
In addition to the ASTM D1945 compositional analyses, ASTM Method 5504 provided an extended
analysis to quantify concentrations of H2S [7]. This method is essentially an extension of the ASTM
D1945 procedures that uses additional chromatographic columns to separate H2S and heavier
hydrocarbons.
A Controlotron Model 1010EP1 energy meter was used to monitor water flow rate and supply and return
temperatures. This meter is a digitally integrated system that includes a portable computer, ultrasonic
fluid flow transmitters, and 1,000-ohm platinum resistance temperature detectors (RTDs). The meter has
an overall rated accuracy of ± 2 percent of reading and provides a continuous 4-20 mA output signal over
a range of 0 to 200 gpm. The meter was installed in the 3-1/2-inch carbon steel water supply line.
The water flow rate and supply and return temperature data used to determine heat recovery rates were
logged as one-minute averages throughout all test periods. The heat transfer fluid density and specific
heat were determined by using ASHRAE and ASME density and specific heat values for water corrected
to the average water temperature measured by the RTDs.
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1.4.2. Power Quality Performance
The GHG Center and its stakeholders developed the following power quality evaluation approach to
account for these issues. Three documents [8, 9, 10] formed the basis for selecting the power quality
parameters of interest and the measurement methods used. The GHG Center measured and recorded the
following power quality parameters during the extended monitoring period:
• Electrical frequency
• Voltage
• Voltage THD
• Current THD
• Power factor
The 7500 ION power meter used for power output determinations was used to perform these
measurements as described below and detailed in the test plan. The ION power meter continuously
measured electrical frequency at the generator's distribution panel. The DAS was used to record one-
minute averages throughout the extended period. The mean, maximum, and minimum frequencies as
well as the standard deviation are reported.
The CHP unit generates power at nominal 208 volts (AC). The electric power industry accepts that
voltage output can vary within ± 10 percent of the standard voltage without causing significant
disturbances to the operation of most end-use equipment. Deviations from this range are often used to
quantify voltage sags and surges. The ION power meter continuously measured true root mean square
(rms) line-to-line voltage at the generator's distribution panel for each phase pair. The DAS recorded
one-minute averages for each phase pair throughout the extended period as well as the average of the
three phases. The mean, maximum, and minimum voltages, as well as the standard deviation for the
average of the three phases are reported.
THD is created by the operation of non-linear loads. Harmonic distortion can damage or disrupt many
kinds of industrial and commercial equipment. Voltage harmonic distortion is any deviation from the
pure AC voltage sine waveform. THD gives a useful summary view of the generator's overall voltage
quality. The specified value for total voltage harmonic is a maximum THD of 5.0 percent based on
"recommended practices for individual customers" in the IEEE 519 Standard. The ION meter
continuously measured voltage THD up to the 63rd harmonic for each phase. The DAS recorded one-
minute voltage THD averages for each phase throughout the test period and reported the mean, minimum,
maximum, and standard deviation for the average THD for the three phases.
Current THD is any distortion of the pure current AC sine waveform. The current THD limits
recommended in the IEEE 519 standard range from 5.0 to 20.0 percent, depending on the size of the CHP
generator, the test facility's demand, and its distribution network design as compared to the capacity of
the local utility grid. Detailed analysis of the facility's distribution network and the local grid are beyond
the scope of this verification. The GHG Center, therefore, reported current THD data without reference
to a particular recommended THD limit. The ION power meter, as with voltage THD, continuously
measured current THD for each phase and reported the average, minimum, and maximum values for the
period.
The ION power meter also continuously measured average power factor across each generator phase.
The DAS recorded one-minute averages for each phase during all test periods. The GHG Center reported
maximum, minimum, mean, and standard deviation power factors averaged over all three phases.
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1.4.3. Emissions Performance
Pollutant concentration and emission rate measurements for NOX, CO, TRS, CH4, and CO2 were
conducted on the engine exhaust stack during all of the controlled test periods. Testing for determination
of TPM and NH3 was conducted at the 45 kW power command only. THC concentrations, likely
impacted by operating the engine below recommended load, exceeded the analyzer's highest selectable
range of 10,000 ppm at all test conditions and therefore, the THC analyses could not be completed. CO
concentrations were also very high and the analyzer was configured to a range of 0 to 10,000 ppm.
Emissions testing coincided with the efficiency determinations described earlier. Test procedures used
were U.S. EPA reference methods, which are well documented in the Code of Federal Regulations (CFR).
The reference methods include procedures for selecting measurement system performance specifications
and test procedures, quality control procedures, and emission calculations (40CFR60, Appendix A) [11].
Table 1-3 summarizes the standard test methods that were followed. A complete discussion of the data
quality requirements {for example, NOX analyzer interference test, nitrogen dioxide [NO2] converter
efficiency test, sampling system bias and drift tests} is presented in the test plan.
Table 1-3. Summary of Emissions Testing Methods
Pollutant
NOX
CO
S02
THC
CH4
C02
02
TRS
NH3
TPM
EPA Reference
Method
7E
10
6C
25A
18
3A
3A
EPA 16A
BAAQMD ST-1B
EPA 5
Analyzer Type
California Analytical Instruments (CAI) 400-
CLD (chemiluminescense)
TEI Model 48 (NDIR)
Bovar721-AT(NDUV)
JUM Model 3-300 (FID)
Hewlett-Packard 5890 GC/FID
CAI 200 (NDIR)
CAI 200 (electrochemical)
Ametek 921 White Cell (NDUV)
Ion Specific Electrode
Gravimetric
Range
0 - 1,000 ppm
0 - 10,000 ppm
0 - 1,000 ppm
0 - 10,000 ppm
0 - 25,000 ppm
0 - 25%
0 - 25%
0 - 1,000 ppm
Not specified
Not specified
Emissions testing was conducted by Cubix Corporation of Austin, Texas under the on-site supervision of
the GHG Center field team leader. A detailed description of the sampling system used for each parameter
listed is provided in the test plan and is not repeated in this report. Sampling was conducted during each
test for approximately 60 minutes at a single point near the center of the 3-inch diameter stack (120
minutes for TPM and NH3). Results of the gaseous pollutant testing are reported in units of parts per
million volume dry (ppmvd) and ppmvd corrected to 15-percent O2. Concentrations of TPM are reported
in units of grains per standard cubic foot (gr/dscf).
To convert measured pollutant concentrations to mass emissions, exhaust gas flow rate determinations
were conducted during each test run in accordance with EPA Method 2C. Stack gas velocity and
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temperature traverses were conducted using a calibrated thermocouple, a standard pitot tube, and an
inclined oil manometer. The number and location of traverse points sampled was selected in accordance
with EPA Method 1A due to the small diameters of this stack. Separate ports were located downstream
of the sampling location (2 diameters) to allow velocity traversing to occur simultaneously with the
sampling. At the conclusion of each test run, equations specified in the reference methods were used to
calculate exhaust gas velocity, actual volumetric flow rate, and volumetric flow rate at standard
conditions.
After converting measured pollutant concentrations to mass units of Ib/dscf, emission rate values were
calculated in units of Ib/hr using the standardized volumetric flow rates. The mean of the three test results
at each load factor is reported as the average emission rate for that load factor. Emission rates for each
pollutant are then normalized to system power output and reported in terms of Ib/kWh.
1.4.4. Estimated Annual Emission Reductions
The electric energy generated by the 1C engine offsets electricity otherwise supplied by the utility grid.
Consequently, the reduction in electricity demand from the grid caused by this offset will result in
changes in CO2 and NOX emissions associated with producing an equivalent amount of electricity at
central power plants. If the CHP emissions per kWh are less than the emissions per kWh produced by an
electric utility, it can be inferred that a net reduction in emissions will occur at the site. If the emissions
from the on-site generators are greater than the emissions from the grid, possibly due to the use of higher
efficiency power generation equipment or zero emissions generating technologies (nuclear and
hydroelectric) at the power plants, a net increase in emissions may occur. Emission reductions associated
with heat recovery were not conducted, as this process requires baseline GHG emission assessment from
standard waste management practices. Due to the significant resources required to do this, OEMC elected
to verify emission reductions from electricity generation only.
Emissions from the 1C engine scenario for this verification are compared with the baseline scenario
(utility grid) to estimate annual NOX and CO2 emission levels and reductions (Ib/yr). Reliable emission
factors for the electric utility grid are available for both gases. Emission reductions were computed as
follows:
Reduction (Ibs) = EGRiD - ECHP (Equation. 4)
Reduction (%) = (EGRiD-ECHp)/EGRiD * 100
Where:
Reduction = Estimated annual emission reductions from on-site electricity generation,
Ibs or %
ECHP = Estimated annual emissions from 1C engine, Ibs (Section 2.5.1)
EGRID = Estimated annual emissions from utility grid, Ibs
The following describes the methodology used.
Step 1 - Estimation of 1C engine CO? and NOy Emissions
The first step in calculating emission reductions was to estimate the emissions associated with generating
electricity with biogas at the site over a given period of time (one year), operating at normal site
conditions (45 kW). Based on the total electrical generation over the nine-day monitoring period
1-14
-------
(extrapolated to a one-year period), and the measured emission rates, the 1C engine emissions can be
estimated as follows:
ECHP =
*kWhc
-CHP
(Equation. 5)
Where:
ECHP = Estimated annual emissions from 1C engine at 45 kW load, Ibs
(Section 1.4.4)
ERcHp = Engine CO2 or NOX emission rate at 45 kW, Ib/kWh
kWhcHp = Total annual electrical energy generated at the site, kWh
Step 2 - Estimation of Grid Emissions
The host facility's utility provider is the Southeast Colorado Power Association (SECPA) with
headquarters in La Junta, Colorado. Energy Information Administration data [12] indicate that SECPA
does not generate any electricity; it distributes and resells utility and non-utility power from other
vendors. Because of this, information which could identify specific generating units (GUs) which would
be offset by power generated at the host facility is not publicly available.
This verification, therefore, compares the 1C engine emissions to aggregated emission data for the three
major types of fossil fuel-fired power plants: coal, petroleum, and natural gas. The GHG Center
employed well-recognized data from DOE and the Energy Information Administration (EIA) for the
computations. These data consist of the total emissions and total power generated for each fuel type and
are available for the nationwide and Colorado power grids. Total emissions divided by total generated
power for each of these geographical regions yields the emission rate in Ib/kWh for CO2 and NOX for
each fuel. The emission rate multiplied by the percent power generated by each fuel yields the weighted
emission rate, and the sum of the weighted emission rates is the overall emission rate for each region.
The following table presents the resulting emission rates for 1999.
Table 1-4. CO2 and NOX Emission Rates for Two Geographical Regions
Region
Nationwide
Colorado
Fuel
coal
petroleum
gas
Percent of
Fossil Fuel
Total
82.2
4.0
13.8
coal
petroleum
gas
94.0
0.1
5.9
CO2 Ib/kWh
2.150
1.734
1.341
Total
Weighted
CO2 Ib/kWh
2.193
1.812
1.114
Total
Weighted
CO2 Ib/kWh
Weighted
C02lb/kWh
1.767
0.070
0.185
2.022
2.061
0.002
0.066
2.129
NOX Ib/kWh
0.00741
0.00283
0.00254
Total
Weighted
NOX Ib/kWh
0.00804
n/a
0.00293
Total
Weighted
NOX Ib/kWh
Weighted
NOX Ib/kWh
0.00609
0.00011
0.00035
0.00655
0.00756
0
0.00017
0.00773
Estimated power grid emissions for equivalent power production, therefore, are based on the annual
estimated kilowatt-hours generated by the on-site CHP system, line losses, and the grid emission rates for
CO2 or NOX as shown in Equation 6.
1-15
-------
EGR1D = kWhCHP * ERORID * 1.114 (Equation. 6)
Where:
EGRID = Annual grid CO2 or NOX emissions, Ibs
kWhCHp= annual engine power generated, kWh
ERoRiD = CO2 or NOX emission rates from Table 1-4, Ib/kWh
1.114 = Total T&D losses
Step 3 - Estimation of Emissions Offsets
Emissions offsets are then estimated (using equation 4) as the difference between the calculated emissions
resulting from the production of the quantity of power produced on site by the CHP system (grid
emission), and the calculated emissions from the CHP system for the same quantity of power produced,
on an annual basis.
1-16
-------
2.0 VERIFICATION RESULTS
2.1. OVERVIEW
The verification period started on February 2, 2004, and continued through February 13, 2004. The
controlled tests were conducted on February 11 through 13, and were preceded by a nine-day period of
continuous monitoring to examine heat and power output, power quality, efficiency, and emission
reductions. Test results are representative of engine operations at this site only. Heat and power
production performance and particularly CO and THC emissions performance were likely negatively
impacted by operating the engine below manufacturer's minimum rating.
The GHG Center acquired several types of data that represent the basis of verification results presented
here. The following types of data were collected and analyzed during the verification:
• Continuous measurements (biogas pressure, biogas temperature, power output and quality,
heat recovery rate, and ambient conditions)
• Manual biogas flow meter readings
• Biogas compositional data
• Emissions testing data
• CHP and facility operating data
The field team leader reviewed, verified, and validated some data, such as DAS file data and
reasonableness checks while on site. The team leader reviewed collected data for reasonableness and
completeness in the field. The data from each of the controlled test periods was reviewed on site to verify
that PTC-17 variability criteria were met. The emissions testing data was validated by reviewing
instrument and system calibration data and ensuring that those and other reference method criteria were
met. Calibrations for fuel flow, pressure, temperature, electrical and thermal power output, and ambient
monitoring instrumentation were reviewed on site to validate instrument functionality. Other data such as
fuel LFfV analysis results were reviewed, verified, and validated after testing had ended. All collected
data was classed as either valid, suspect, or invalid upon review, using the QA/QC criteria specified in the
test plan. Review criteria are in the form of factory and on-site calibrations, maximum calibration and
other errors, audit gas analyses results, and lab repeatability results. Results presented here are based on
measurements which met the specified Data Quality Indicators (DQIs) and QC checks and were validated
by the GHG Center.
The continuous monitoring days listed above include periods when the unit was operating under normal
site conditions. The GHG Center has made every attempt to obtain a reasonable set of short-term data to
examine daily trends in atmospheric conditions, electricity and heat production, and power quality. It
should be noted that these results may not represent performance over longer operating periods or at
significantly different operating conditions.
As described earlier, under typical 1C engine operations the engine will be periodically run on biogas or
natural gas, and short term shut downs for routine maintenance are common. These typical operations
were observed during the 9-day monitoring period as illustrated in Figure 2-1. Unshaded areas in the
figure highlight the time periods when the engine was operating on biogas. The shaded areas in the figure
represent periods when the engine was either shut down (indicated by breaks in the power output plot), or
running on natural gas. The biogas temperature plot was used to determine the time periods when this
occurred. When the engine operates on natural gas, the biogas flow past the temperature sensor stops and
2-1
-------
the gas temperature drops. Periods where the biogas temperature is consistently above 70 °F indicate the
periods of time when the engine was firing biogas.
Engine Power
Output
Shaded areas represent periods when engine was either idle
or operating on natural gas.
120
2/2/04
10:30
9 Consecutive Days of Monitoring
10:30
Figure 2-1. Engine Operations During the Extended Monitoring Period
Figure 2-1 includes a total of 216 hours of monitoring. During that period, the engine was running on
biogas at a nominal output of 45 kW for a total of 75.3 hours (about 35 percent of the time). The engine
ran on natural gas for a total of 188.9 hours (or about 55 percent of the time). The engine was down the
remainder of the time (21.8 hours). Results of the extended monitoring period presented in the following
sections are based solely on the 75.3 hours during which the engine was running on biogas. Data
collected while operating on natural gas are not included in this report.
Test results are presented in the following subsections:
Section 2.1- Heat and Power Production Performance
(controlled test periods and extended monitoring)
Section 2.2 - Power Quality Performance
(extended monitoring)
Section 2.3 - Emissions Performance and Reductions
(controlled test periods)
The results show that the CHP system produces high quality power and is capable of operating in parallel
with the utility grid. The unit produced a steady 45 kW of electrical power throughout the extended
2-2
-------
monitoring period. The highest heat recovery rate measured during the extended monitoring period was
approximately 277 x 103 Btu/hr. Electrical and thermal efficiencies at 45 kW averaged 19.7 and 32.4
percent, respectively, with a corresponding total CHP system efficiency of 52.1 percent. It is likely that
these efficiencies might improve should site conditions allow the engine to operate at its full design
capacity. NOX emissions averaged 0.012 Ib/kWh at 45 kW. Emissions of CO and hydrocarbons were
very high during all test periods. Annual NOX emissions are estimated to be at least 55 percent higher
than the average grid emissions. CO2 emission reductions are estimated to be at least 2.2 percent.
Detailed analyses are presented in the following sections.
In support of the data analyses, the GHG Center conducted an audit of data quality (ADQ) following
procedures specified in the QMP. A full assessment of the quality of data collected throughout the
verification period is provided in Section 3.0.
2.2. HEAT AND POWER PRODUCTION PERFORMANCE
The heat and power production performance evaluation included electrical power output, heat recovery,
and CHP efficiency determinations during controlled test periods. The performance evaluation also
included determination of total electrical energy generated and used and thermal energy recovered over
the extended test period.
2.2.1. Electrical Power Output, Heat Recovery Rate, and Efficiency During Controlled Tests
Table 2-1 summarizes the power output, heat recovery rate, and efficiency performance of the CHP
system. Ambient temperature ranged from 35 to 56 °F, relative humidity ranged from 20 to 48 percent,
and barometric pressure was between 12.70 and 12.83 psia during the controlled test periods. The results
shown in Table 2-1 and the discussion that follows are representative of conditions encountered at this
site and are not intended to indicate performance at other operating conditions such as cooler
temperatures and different elevations.
Biogas fuel conditions and heat recovery unit operation data corresponding to the test results are
summarized in Table 2-2. A total of 12 samples were collected for compositional analysis and
determination of LHV. There was very little variability in the biogas composition. Average biogas CH4
and CO2 concentrations were 68.1 and 31.2 percent, respectively. The average LHV was 625 Btu/scf and
biogas compressibility averaged 0.997. H2S concentrations in the biogas averaged 3,730 ppm.
The average net electrical power delivered to the farm was 44.7 kWe at the highest achievable load
setting. The average electrical efficiency at this power command was 19.7 percent. Electrical efficiencies
at the 38 and 30 kW power commands averaged 17.1 and 13.8 percent, respectively. Electric power
generation heat rate, which is an industry-accepted term to characterize the ratio of heat input to electrical
power output, averaged 17,320 Btu/kWhe at the 45 kW setting.
The average heat-recovery rate at the 45 kW power command was 250 x 103 Btu/hr, or 73.3 kWth, and
thermal efficiency was 32.4 percent. Results of three runs indicated that the total efficiency (electrical
and thermal combined) was 52.1 percent at this condition. The net heat rate, which includes energy from
heat recovery, was 6,549 Btu/kWh.
2-3
-------
Table 2-1. Engine CHP Heat and Power Production Performance
Test ID
Runl
Run 2
Run 3
Avg.
Run 4
Run 5
Run 6
Avg.
Run 7
Run8
Run 9
Avg.
Test
Condition
45 kW power
command
30 kW power
command
3 8 kW power
command
Heat Input,
HI
(103Btu/hr)
751
789
783
774
705
744
743
731
768
742
740
750
Electrical Power
Generation Performance
Power
Delivered"
(kW)
44.6
44.7
44.7
44.7
29.7
29.6
29.5
29.6
37.5
37.6
37.6
37.5
Efficiency
20.3
19.2
19.5
19.7
14.4
13.6
13.5
13.8
16.6
17.3
17.3
17.1
Heat Recovery
Performance
Heat
Recovery
Rateb
(103Btu/hr)
275
238
238
250
207
226
225
219
225
233
224
227
Thermal
Efficiency
(%)
36.6
30.2
30.4
32.4
29.4
30.4
30.3
30.0
29.3
31.4
30.3
30.3
Total CHP
System
Efficiency
56.8
49.6
49.9
52.1
43.8
43.9
43.8
43.8
46.0
48.7
47.6
47.4
Ambient Conditions c
Temp (°F)
55.9
47.5
47.4
50.3
42.7
37.7
38.7
39.7
34.9
38.8
43.4
39.0
RH (%)
20.3
38.9
35.7
31.6
48.1
32.6
31.3
37.3
33.9
30.1
29.8
31.3
a Represents actual power available for consumption at the test site.
b Divide by 3.412 to convert to equivalent kilowatts (kWfh).
0 Barometric pressure remained relatively consistent throughout the test runs (12.70 to 12.83 psia).
2-4
-------
Table 2-2. Engine CHP Fuel Input and Heat Recovery Unit Operating Conditions
Test ID
Runl
Run 2
Run3
Avg.
Run 4
Run 5
Run 6
Avg.
Run?
Run8
Run 9
Avg.
Test
Condition
45 kW power
command
30 kW power
command
3 8 kW power
command
Biogas Fuel Input
Gas Flow
Rate (scfm)
20.3
21.2
21.0
20.8
18.9
19.8
19.7
19.5
20.4
19.7
19.7
19.9
LHV
(Btu/scf)
616.4
621.1
621.1
619.5
621.1
628.0
628.0
625.7
628.0
627.0
627.0
627.3
Gas
Pressure
(psia)
13.7
13.7
13.7
13.7
13.8
13.8
13.8
13.8
13.8
13.7
13.7
13.7
Gas Temp
(°F)
82.2
75.1
75.4
77.6
75.5
70.4
71.0
70.0
67.6
70.0
72.5
70.0
Heating Loop Fluid Conditions
Fluid Flow
Rate, V
(gpm)
118.2
117.6
117.7
117.8
118.2
117.8
117.9
118.0
118.1
118.0
118.0
118.0
Outlet
Temp., Tl
(°F)
106.5
105.3
105.3
105.7
103.8
104.4
104.4
104.2
103.8
104.0
103.7
103.8
Inlet
Temp., T2
(°F)
101.8
101.2
101.2
101.4
100.3
100.6
100.6
100.5
99.2
100.0
99.8
99.7
Temp.
Diff. (°F)
4.68
4.09
4.07
4.28
3.53
3.86
3.84
3.74
3.84
3.98
3.83
3.88
2-5
-------
Results of the reduced load tests are also included in the tables. Results show that electrical efficiency
decreases as the power output is reduced. Thermal efficiency, however, was relatively consistent
throughout the range of operation tested. This is illustrated in Figure 2-2 which displays the electrical and
thermal system efficiency for each of the controlled test conditions.
35 -
30
*? 25 -
3?
1 20
u ^ ~
'O
E 15
10 -
5 _
0 -
-v~-/~V~|
L-v~~ -w-—'' •
»
jS
Power Output
45 kW Power
Command Tests
Electrical Efficiency
X.
I , ^
38 kW Power
Command Tests
Thermal Efficiency
'
*• • • -~~~~~»~
30 kW Power
Command Tests
90
80
70
fin
50
40
30
20
I
4-1
Q.
O
k.
6
Figure 2-2. CHP System Efficiency During Controlled Test Periods
The figure shows the decrease in electrical efficiency at lower loads, and the relative stability of heat
recovery efficiency regardless of power output. Although not verified, Figure 2-2 further suggests that
electrical efficiency would improve at higher operating set points closer to the rated output of the engine.
The high heat recovery efficiency measured during the first test run is the result of a larger temperature
differential between the supply and return lines than what was normally seen. Although this test run was
conducted at significantly warmer ambient temperatures than the others, a true relationship between
ambient temperature and heat recovery rate is not evident (see results of extended monitoring in Section
2.2.2 below).
2.2.2. Electrical and Thermal Energy Production and Efficiency During the Extended Test
Period
Figure 2-3 presents a time series plot of 1-minute average power production and heat recovery during the
extended verification period. As described earlier, although the extended monitoring period spanned nine
full days, the engine was operating on biogas for only about 75 hours during the period. Data presented
here includes only those time periods.
A total of 3,358 kWhe electricity and 5,232 kWhth of thermal energy (or 17,850 x 103 Btu) were generated
from biogas over the nine-day period. All of the electricity and heat generated was used by the facility.
The average power generated over the extended period was 44.6 kWe with very little variability in the
engine's generating rate.
2-6
-------
50
20 4
75.3 Hours of Monitoring the Engine Running on Biogas
Figure 2-3. Heat and Power Production During the Extended Monitoring Period
Three reverse spikes in power output are shown in the figure. Each of these reductions in power output
were two minutes or less in duration with the largest being a quick drop to 7 kW. The cause of these
reductions is not known. Review of other parameters monitored by the center indicate steady CHP
system operations when these reductions occurred. The average heat recovery rate over the extended
period was 237.9 x 103 Btu/hr. The heat recovery rate data does exhibit some variability, but the source
of the variability is not clear based on other data collected during the period. No changes in power output
were observed, and there is not a clear relationship with ambient temperature (Figure 2-4).
50
20
150
10 15 20 25 30 35 40
Ambient Temperature (°F)
45
50
55
60
Figure 2-4. Ambient Temperature Effects on Power and Heat Production
2-7
-------
2.3. POWER QUALITY PERFORMANCE
2.3.1. Electrical Frequency
Electrical frequency measurements (voltage and current) were monitored continuously during the
extended period. The one-minute average data collected by the electrical meter were analyzed to
determine maximum frequency, minimum frequency, average frequency, and standard deviation for the
verification period. These results are summarized in Table 2-3 and illustrated in Figure 2-5. The average
electrical frequency measured was 59.998 Hz and the standard deviation was 0.022 Hz.
Table 2-3. Electrical Frequency During Extended Period
Parameter
Average Frequency
Minimum Frequency
Maximum Frequency
Standard Deviation
Frequency (Hz)
59.998
58.660
60.048
0.022
60.06
60.04
59.92
75.3 Hours of Monitoring the Engine Running on Biogas
Figure 2-5. 1C Engine Frequency During Extended Test Period
2.3.2. Voltage Output
It is typically accepted that voltage output can vary within ± 10 percent of the standard voltage (208 volts)
without causing significant disturbances to the operation of most end-use equipment. The 7500 ION
electric meter was configured to measure 0 to 600 VAC. The engine was grid-connected and operated as
2-S
-------
a voltage-following current source. The voltage levels measured are, therefore, more indicative of the
grid voltage levels that the engine tried to respond to.
Figure 2-6 plots one-minute average voltage readings and Table 2-4 summarizes the statistical data for the
voltages measured on the engine throughout the verification period. The voltage levels were well within
the normal accepted range of ± 10 percent.
Table 2-4. 1C Engine Voltage During Extended Period
Parameter
Average Voltage
Minimum Voltage
Maximum Voltage
Standard Deviation
Volts
208.63
204.65
210.72
1.10
215
210
o
205
200
75.3 Hours of Monitoring the Engine Running on Biogas
Figure 2-6. 1C Engine Voltage During Extended Test Period
2.3.3. Power Factor
Figure 2-7 plots one-minute average power factor readings and Table 2-5 summarizes the statistical data
for power factors measured on the engine throughout the verification period except during the three
reverse spikes in power output. Test results show that the power factor was very stable throughout the
period.
2-9
-------
Table 2-5. Power Factors During Extended Period
Parameter
Average Power Factor
Minimum Power Factor
Maximum Power Factor
Standard Deviation
%
79.74
71.34
82.71
0.338
84
80 -
70
a! 76 -
o
Q.
74 -
72 -
Power Output'
45
O
-------
75.3 Hours of Monitoring the Engine Running on Biogas
Figure 2-8. 1C Engine Current THD During Extended Test Period
75.3 Hours of Monitoring the Engine Running on Biogas
Figure 2-9. 1C Engine Voltage THD During Extended Test Period
2-11
-------
2.4. EMISSIONS PERFORMANCE
2.4.1. CHP System Stack Exhaust Emissions
Stack emission measurements were conducted during each of the controlled test periods summarized in
Table 1-2. All testing was conducted in accordance with the EPA reference methods listed in Table 1-3.
The CHP system was maintained in a stable mode of operation during each test run based on PTC-17
variability criteria.
Emissions results are reported in units of parts per million volume dry, corrected to 15-percent O2 (ppmvd
at 15-percent O2) for NOX, CO, SO2, TRS, NH3, and THC. Concentrations of CO2 are reported in units of
volume percent, and TPM concentrations are reported as grains per dry standard cubic foot (gr/dscf).
These pollutant concentration data were converted to mass emission rates using measured exhaust stack
flow rates and are reported in units of pounds per hour (Ib/hr). The emission rates are also reported in
units of pounds per kilowatt hour electrical output (lb/kWhe). They were computed by dividing the mass
emission rate by the electrical power generated.
Sampling system QA/QC checks were conducted in accordance with test plan specifications to ensure the
collection of adequate and accurate emissions data. These included analyzer linearity tests, sampling
system bias and drift checks, and sampling train leak checks. Results of the QA/QC checks are discussed
in Section 3. The results show that DQOs for all gas species met the reference method requirements.
Table 2-7 summarizes the emission rates measured during each run and the overall average emissions for
each set of tests.
In general, engine emissions were uncharacteristically high at all load points tested. This is most likely
attributable to the fact that the engine operates well below design capacity due to the limitations in the
biogas fuel delivery system. The engine received a complete overhaul in December 2003, but the
excessively high levels of CO and CH4 in the exhaust gases indicate that clearly the engine was not
performing well at these loads. NOX concentrations averaged 255 ppmvd at 15% O2 at the 45 kW power
command, and decreased to approximately 41 ppmvd at 15% O2 at the lowest load tested. The overall
average NOX emission rate at 45 kW, normalized to power output, was 0.012 Ib/kWh. Annual published
data from Energy Information Administration (EIA) reveal that the measured CHP system emission rate
is well above the average rate for coal and natural gas-fired power plants in the U.S. The rates are 0.0074
Ib/kWh for coal-fired plants and 0.0025 Ib/kWh for natural gas-fired plants. It is important to note
however, that the ability of this system to recover and use engine exhaust heat offsets this increase in
emissions somewhat.
2-12
-------
Table 2-7. 1C Engine CHP System Emissions During Controlled Test Periods
Run 1
Run 2
Run 3
AVG
Run 4
Run 5
Run 6
AVG
Run 7
Run 8
Run 9
AVG
8 _
m>
shl
44.6
44.7
44.7
44.7
29.7
29.6
29.5
29.6
37.5
37.6
37.6
37.6
Exhaust
02 (%)
4.3
4.2
4.2
4.2
6.1
4.6
4.5
5.1
4.7
5.6
5.6
5.3
NOX Emissions
(ppm at
15%O2)
279
244
242
255
51
35
36
41
80
150
162
131
(Ib/hr)
0.556
0.529
0.539
0.541
0.082
0.061
0.063
0.069
0.140
0.260
0.280
0.227
Qb/kWhJ
1 .25E-02
1.18E-02
1 .21 E-02
1.21E-02
2.77E-03
2.06E-03
2.14E-03
2.32E-03
3.73E-03
6.93E-03
7.44E-03
6.03E-03
CO Emissions
(ppm at
15%O2)
1081
2100
2716
1966
ND
ND
ND
NA
ND
ND
ND
NA
(Ib/hr)
1.31
2.77
3.69
2.59
ND
ND
ND
NA
ND
ND
ND
NA
Qb/kWhJ
0.029
0.062
0.082
0.058
ND
ND
ND
NA
ND
ND
ND
NA
CH4 Emissions
(ppm at
15%O2)
5957
7202
7013
6724
7078
7502
8011
7530
7647
7262
6439
7116
(Ib/hr)
4.12
5.44
5.44
5.00
3.97
4.50
4.88
4.45
4.63
4.38
3.87
4.30
(Ib/kWh)
0.092
0.122
0.122
0.112
0.134
0.152
0.165
0.150
0.124
0.117
0.103
0.114
CO2 Emissions
(%)
12.7
12.0
12.0
12.2
8.20
12.2
12.1
10.8
12.1
12.3
12.7
12.4
(Ib/hr)
85.9
88.1
90.4
88.1
50.4
72.9
73.0
65.4
73.5
78.8
81.0
77.8
(Ib/kWh)
1.93
1.97
2.02
1.97
1.70
2.46
2.47
2.21
1.96
2.09
2.16
2.07
ND = No data collected. Emissions exceeded analyzer range (10,000 ppm).
NA = Not applicable
(Continued)
2-13
-------
Table 2-7. 1C Engine CHP System Emissions During Controlled Test Periods (Continued)
Run 1
Run 2
Run 3
AVG
Run 4
Run 5
Run 6
AVG
Run 7
Run 8
Run 9
AVG
Electrical
Power
Output
(kW)
44.6
44.7
44.7
44.7
29.7
29.6
29.5
29.6
37.5
37.6
37.6
37.6
Exhaust
02 (%)
4.3
4.2
4.2
4.2
6.1
4.6
4.5
5.1
4.7
5.6
5.6
5.3
Particulate Emissions
(gr/dscf)
0.0024
0.0027
0.0083
0.0045
ND
ND
ND
NA
ND
ND
ND
NA
(Ib/hr)
0.0020
0.0025
0.0078
0.0041
ND
ND
ND
NA
ND
ND
ND
NA
(Ib/kWh)
4.48E-05
5.59E-05
1 .74E-04
9.18E-05
ND
ND
ND
NA
ND
ND
ND
NA
NH3 Emissions
(ppm at
15%02)
0.29
0.17
0.22
0.23
ND
ND
ND
NA
ND
ND
ND
NA
(Ib/hr)
2.10E-04
1 .40E-04
1 .80E-04
1.77E-04
ND
ND
ND
NA
ND
ND
ND
NA
(Ib/kWh)
4.71 E-06
3.13E-06
4.03E-06
3.96E-06
ND
ND
ND
NA
ND
ND
ND
NA
SO2 Emissions
(ppm at
15%02)
364
338
355
352
374
360
376
370
373
374
376
374
(Ib/hr)
1.01
1.02
1.10
1.04
0.84
0.87
0.92
0.88
0.91
0.90
0.91
0.91
(Ib/kWh)
0.023
0.023
0.025
0.023
0.028
0.029
0.031
0.030
0.024
0.024
0.024
0.024
TRS Emissions
(ppm at
15%02)
56.3
64.8
113
78.0
79.0
134
125
113
160
20.4
157
112
(Ib/hr)
0.16
0.20
0.35
0.24
0.18
0.32
0.30
0.27
0.39
0.05
0.38
0.27
(Ib/kWh)
0.004
0.004
0.008
0.005
0.006
0.011
0.010
0.009
0.010
0.001
0.010
0.007
ND = No data collected. These pollutants not tested at reduced loads.
NA = Not applicable
2-14
-------
Exhaust gas CO concentrations averaged 1,966 ppmvd at 15% O2 at 45 kW and were beyond the range of
the CO analyzer at reduced loads (greater than 10,000 ppmvd). Corresponding average CO emission
rates at 45 kW were approximately 0.06 Ib/kWh.
The center was unable to quantify THC concentrations at any power setting because they exceeded the
10,000 ppm range of the analyzer. However, the on-site GC/FID used for CFLt determinations confirmed
that there were no hydrocarbons other than CH4 present in the exhaust gas in significant quantities. CH^
concentrations were high over the entire range of operations tested, averaging over 6,700 ppmvd at 15%
O2 at 45 kW and over 7,500 ppmvd at 15% O2 at the 30 kW power command. Corresponding CFLj
emission rates at these power commands were approximately 0.11 and 0.15 Ib/kWh, respectively.
Concentrations of CO2 in the CHP system exhaust gas averaged 12.2 percent at 45 kW and decreased as
power output was reduced to a low of 10.8 percent. These concentrations correspond to average CO2
emission rates of 1.97 Ib/kWh and 2.21 Ib/kWh, respectively. The CHP system CO2 emission rate at full
load is slightly lower than the weighted average emission factors for both the US and Colorado regional
grids (2.02 and 2.13 Ib/kWh, respectively).
Emissions of total particulate matter and NH3 were extremely low during each of the three test replicates
conducted at 45 kW. SO2 emissions from the CHP were fairly consistent throughout the range of
operation. SO2 concentrations at 45 kW averaged 352 ppmvd at 15% O2 and corresponding emission
rates averaged 0.023 Ib/kWh. Emissions of TRS, the sulfurous compounds in the fuel that were not
oxidized during combustion, averaged approximately 78.0 ppmvd at 15% O2 and 0.005 Ib/kWh during the
full load tests.
2.4.2. Estimation of Annual Emission Reductions
The average engine CHP emission rates for NOX and CO2 were 0.012 and 1.97 Ib/kWh, respectively. The
extended monitoring period is representative of normal site operations. During that 216-hour period, the
engine ran at 45 kW on biogas for 75.3 hours (34.9 percent of the time) and produced 3,358 kWh
electricity. Projecting that power production rate over the course of a year, the engine would produce
approximately 136,000 kWh electricity using biogas fuel. Based on the measured emission rates and the
estimated annual power production, approximate annual emissions from the engine CHP system would be
around 0.82 and 134 tons per year NOX and CO2, respectively. Table 2-8 summarizes how those
emission rates compare to the emissions associated with the U.S. and Colorado regional grid fossil fuel
emission factors for an equivalent amount of power production.
2-15
-------
Table 2-8. Comparison of 1C Engine CHP Emissions to Regional
Emissions for Equivalent Fossil Fuel Grid Power (to produce 136,000 kWh)
Pollutant
NOX
CO2
Estimated
Annual CHP
Emissions (tons)
0.82
134
U.S. Regional
Annual
Emissions (tons)8
0.45
137
Percent
Reduction
(Increase)
(82)
2.2
Colorado Regional
Annual Emissions
(tons)"
0.53
145
Percent
Reduction
(Increase)
(55)
7.6
a Based on average U.S. regional NOX and CO2 emission factors of 0.00655 and 2.022 Ib/kWh, respectively [12].
b Based on average Colorado regional NOX and CO2 emission factors of 0.00773 and 2. 129 Ib/kWh, respectively [12].
It is estimated that power generation using the 1C engine CHP at Colorado Pork increases annual NOX
emissions by approximately 0.37 tons using the U.S. regional scenario and 0.29 tons using the Colorado
scenario. Estimated annual CHP CO2 emissions are 3 and 11 tons lower than the regional average CO2
emissions. As noted earlier, recovery and use of waste heat provides additional environmental benefits
and emissions offsets that were not evaluated here. In addition, using biogas as fuel potentially decreases
agricultural releases of methane to the atmosphere, another important environmental benefit of this
system.
2-16
-------
3.0
DATA QUALITY ASSESSMENT
3.1. DATA QUALITY OBJECTIVES
The GHG Center selects methodologies and instruments for all verifications to ensure a stated level of
data quality in the final results. The GHG Center specifies data quality objectives (DQOs) for each
verification parameter before testing commences. Each test measurement that contributes to the
determination of a verification parameter has stated data quality indicators (DQIs) which, if met, ensure
achievement of that verification parameter's DQO.
The establishment of DQOs begins with the determination of the desired level of confidence in the
verification parameters. Table 3-1 summarizes the DQOs established in the test planning stage for each
verification parameter. The actual data quality achieved during testing is also shown. The next step is to
identify all measured values which affect the verification parameter and determine the levels of error
which can be tolerated. These DQIs, most often stated in terms of measurement accuracy, precision, and
completeness, are used to determine if the stated DQOs are satisfied. The DQIs for this verification -
used to support the DQOs listed in Table 3-1 - are summarized in Table 3-2.
Table 3-1. Verification Parameter Data Quality Objectives
Verification Parameter
Original DQO Goal3
Relative (%) /Absolute (units)
Achieved1"
Relative (%) /Absolute (units)
Power and Heat Production Performance
Electrical power output (kW)
Electrical efficiency (%)
Heat recovery rate (103Btu/hr)
Thermal energy efficiency (%)
CHP production efficiency (%)
±1.50%/0.98kW
±1.52%/0.41%c
±2.0% /5.75xl03Btu/hrc
±1.68%/0.75%c
±1.18%/0.82%c
±1.0%/0.45kW
±1.10%/0.22%c
±2.0%/5.5xl03Btu/hrc
± 2.24 / 0.73%c
±1.46%/0.76%c
Power Quality Performance
Electrical frequency (Hz)
Voltage
Power factor (%)
Voltage and current total harmonic distortion (THD)
± 0.01% / 0.006 Hz
± 1.01 % I 1.21 Vc
± 0.50% / TBD
±1.00%/TBD
± 0.01% / 0.006 Hz
± 1.0 %/ 2.09 Vc
± 0.50% / 0.40%
±1.0%/0.05%
Emissions Performance
NOX, CO, CO2, O2, TRS, and SO2 concentration
accuracy
CH4 concentration accuracy
TPM and NH3 concentration accuracy
±2.0%ofspand
±5.0%ofspand
± 5.0%
±2.0%ofspand
±5.0%ofspand
± 10.0%
a Original DQO goals as stated in test plan. Absolute errors were provided in the test plan, where applicable, based on anticipated
values.
b Overall measurement uncertainty achieved during verification. The absolute errors listed are based on these uncertainties, and the
average values measured during the verification
0 Calculated composite errors were derived using the procedures described in the corresponding subsections (Sections 3.2.2 through
3.2.5).
Qualitative data quality indicators based on conformance to reference method requirements.
The DQIs specified in Table 3-2 contain accuracy, precision, and completeness levels that must be
achieved to ensure that DQOs can be met. Reconciliation of DQIs is conducted by performing
independent performance checks in the field with certified reference materials and by following approved
3-1
-------
reference methods, factory calibrating the instruments prior to use, and conducting QA/QC procedures in
the field to ensure that instrument installation and operation are verified. The following sections address
reconciliation of each of the DQI goals.
This verification was supported by an Audit of Data Quality (ADQ) conducted by the GHG Center QA
manager. During the ADQ, the QA manager randomly selected data supporting each of the primary
verification parameters and followed the data through the analysis and data processing system. The ADQ
confirmed that no systematic errors were introduced during data handling and processing. A performance
evaluation audit (PEA) and a technical systems audit (TSA) were planned but not conducted. Similar
PEAs were recently conducted on two recent CHP verifications [13, 14] and it was decided to not repeat
the PEA a third time. Likewise, a full TSA was recently completed on a similar verification [13] where
the same measurement systems were used, so this QA activity was not repeated here. Instead, the GHG
Center QA manager conducted an abbreviated project review to ensure that the verification approach and
analytical procedures specified in the TQAP were followed or, in cases where changes to the verification
were necessary, these changes were justified and documented.
3.2. RECONCILIATION OF DQOs AND DQIs
Table 3-2 summarizes the range of measurements observed in the field and the completeness goals.
Completeness is the number or percent of valid determinations actually made relative to the number or
percent of determinations planned. The completeness goals for the controlled tests were to obtain
electrical and thermal efficiency as well as emission rate data for three test runs conducted at each of four
different load conditions. This completeness goal was partially achieved in that three valid runs were
conducted at each load. However, only three different load conditions were tested due to the limited
range of engine operations (limited to a range of about 30 to 45 kW).
Completeness goals for the extended tests were to obtain 90 percent of 7 days of power quality, power
output, heat recovery rate, and ambient measurements. This goal was exceeded—9 complete days of
valid data were collected. These data were useful in establishing trends in power and heat performance
capability at varying ambient temperatures as discussed in Section 2.0.
Table 3-2 also includes accuracy goals for measurement instruments. Actual measurement accuracies
achieved are also reported based on instrument calibrations conducted by manufacturers, field
calibrations, reasonableness checks, or independent performance checks with a second instrument. Table
3-3 includes the QA/QC procedures that were conducted for key measurements in addition to the
procedures used to establish DQIs. The accuracy results for each measurement and their effects on the
DQOs are discussed below.
3-2
-------
Table 3-2. Summary of Data Quality Indicator Goals and Results
Measurement Variable
CHP System
Power Output
and Quality
CHP System
Heat
Recovery
Rate
Ambient
Conditions
Power
Voltage
Frequency
Current
Voltage THD
Current THD
Power Factor
Inlet
Temperature
Outlet
Temperature
Water Flow
Ambient
Temperature
Ambient
Pressure
Relative
Humidity
Instrument
Type and
Manufacturer
Electric Meter/
Power
Measurements
7500 ION
Controlotron
Model 1010EP
RTD/Vaisala
Model HMD
60YO
Setra Model
280E
Vaisala Model
HMD 60 YO
Instrument
Range
0 to 100 kW
0 to 600 V
55 to 65 Hz
0 to 200A
0 to 100%
0 to 100%
0 to 100%
80 to 150°F
80 to 150 °F
Oto 150gpm
-50 to 150°F
0 to 25 psia
0 to 100% RH
Range
Observed in
Field
29.2 to 46.3 kW
204 to 210V
58.6 to 60.0 Hz
36 to 161 A
0.5 to 10.8%
1.4 to 10.7%
69.3 to 83.6%
92 to 103 °F
92 to 108 °F
106 to 122 gpm
12 to 59 ° F
12. 53 to 12. 84
psia
18to50%RH
Accuracy
Goal
± 1.5% reading
± 1 .0% reading
± 0.01% reading
± 1 .0% reading
± 1.0% full scale
± 1.0% full scale
± 0.5% reading
Temps must be ±
1.5°Fofref.
Thermocouples
± 1.0% reading
± 0.2 °F
±0-1% full scale
± 2%
Actual
± 1.0% reading
± 1.0% reading
± 0.01% reading
± 1.0% reading
± 1.0% full scale
± 1.0% full scale
± 0.5% reading
± 0.7 °F for outlet,
± 0.8 °F for inlet
± 0.1% reading
± 0.2 °F
± 0.05% full scale
± 0.2%
How Verified or
Determined
Instrument
calibration from
manufacturer prior to
testing
Independent check
with calibrated
thermocouple
Instrument
calibration from
manufacturer prior
to testing
Instrument
calibration from
manufacturer prior to
testing
Completeness
Goal
Controlled
tests: three
valid runs per
load meeting
PTC 17
criteria.
Extended
test: 90% of
one minute
readings for 7
days.
Actual
Controlled
tests: three
valid runs per
load meeting
PTC 17
criteria.
Extended
test: 100% of
one minute
readings for 9
days.
(continued)
3-3
-------
Table 3-2. Summary of Data Quality Indicator Goals and Results (continued)
Measurement Variable
Fuel Input
Exhaust
Stack
Emissions
Gas Flow Rate
Gas Pressure
Gas
Temperature
LHV
NOX Levels
CO Levels
CH4 Levels
SO2 Levels
O2 / CO2 Levels
TRS Levels
NH3 Levels
TPM
concentrations
Stack gas
velocity
Instrument Type
and
Manufacturer
Dresser-Roots
Model 2M175 SSM
Series B3 rotary
displacement
Omega Model
PX205-030AI
transducer
Omega TX-93 Type
K thermocouple
Gas Chromatograph
/HP 5890 11
Chemiluminescent/
CAI 400-CLD
NDIR / TEI Model
48
HP 5890
Bovar721-AT
CAI 200
Ametek921
Ion specific
electrode
gravimetric
Pilot and
thermocouple
Instrument
Range
0 to 30 scfm
0 to 30 psia
0 to 200 °F
0 to 100% CH4
Oto 1,000 ppm vd
0 to 10,000
ppmvd
Oto 25,000 ppmv
Oto 1,000 ppmvd
0 to 25%
0 to 1,000 ppmvd
0 to 5 ug/ml
Not specified
Not specified
Measurement
Range
Observed
19 to 21 scfm
12 to 14 psia
54 to 97 °F
67 to 69% CH4
616to633Btu/ft3
95 to 800 ppmvd
3,000 to 8,000
ppmvd a
16,000 to 23,000
ppmv
900 to 1,000
ppmvd
4 to 6% O2
8 to 13% CO2
50 to 440 ppmvd
0 to 4.2 ug/ml
0.01 to 0.04 g
3552 to 3753 fpm
Accuracy
Goal
1.0% of
reading
± 0.75% full
scale
± 0.10%
reading
±3.0%
accuracy, ±
0.2%
repeatability
0.1%
repeatability
± 2% full scale
± 2% full scale
± 5% full scale
± 2% full scale
± 2% full scale
± 2% full scale
± 5% full scale
± 1 mg
± 5% reading
Actual
± 0.3% of
reading
± 0.25% full
scale
± 0.10% reading
± 0.5% accuracy,
± 0.05%
repeatability
± 0.06%
repeatability
< 2% full scale
< 2% full scale
< 5% reading
< 2% full scale
< 2% full scale
< 2% full scale
< 5% full scale
± .05 mg
< 5% reading
How Verified or
Determined
Factory calibration with
volume prover
Instrument calibration to
NIST traceable standards
analysis of NIST-traceable
CH4 standard, and
duplicate analysis on 3
samples
Conducted duplicate
analyses on 3 samples
Calculated following EPA
Reference Method
calibrations (Before and
after each test run)
Completeness
Goal
Controlled
tests: three
valid runs
per load
meeting
PTC 17
criteria.
Extended
test: 90% of
one minute
readings for
7 days.
Controlled
tests: two
valid
samples per
load
Controlled
tests: three
valid runs
per load.
Actual
Controlled
tests: three
valid runs
per load
meeting
PTC 17
criteria.
Extended
test: 100%
of one
minute
readings
for 9 days.
Controlled
tests: two
valid
samples
per load
Controlled
tests:
three valid
runs per
load.
a The range of CO concentrations is for runs 1 through 3 only. All others exceeded the 10,000 ppm analyzer span.
3-4
-------
3.2.1. Power Output
Instrumentation used to measure power was introduced in Section 1.0 and included a Power
Measurements Model 7500 ION. The data quality objective for power output was ±1.5 percent of
reading, which includes compounded error of the instrument, the CTs, and the PT. The test plan specified
factory calibration of the ION meter with a NIST-traceable standard to determine if the power output
DQO was met. The test plan also required the GHG Center to perform several reasonableness checks in
the field to ensure that the meter was installed and operating properly. The following summarizes the
results.
The meter was factory calibrated by Power Measurements in April 2003. Calibrations were conducted in
accordance with Power Measurements' standard operating procedures (in compliance with ISO
9002:1994) and are traceable to NIST standards. The meters were certified by Power Measurements to
meet or exceed the accuracy values summarized in Table 3-2 for power output, voltage, current, and
frequency. NIST-traceable calibration records are archived by the GHG Center. Pretest factory
calibrations on the meters indicated that accuracy was within ±0.05 percent of reading and this value,
combined with the 1.0-percent error inherent to the current transformers resulted in an overall error of ±
1.01-percent. The potential transformer was not needed, eliminating that error. Using the manufacturer-
certified calibration results and the average power output measured during the full-load testing, the error
during all testing is determined to be ± 0.45 kW.
Additional QC checks were performed on the 7500 ION to verify the operation after installation of the
meters at the site and prior to the start of the verification test. The results of these QC checks
(summarized in Table 3-3) are not used to reconcile the DQI goals, but to document proper operation in
the field. Current and voltage readings were checked for reasonableness using a hand-held Fluke
multimeter. These checks confirmed that the voltage and current readings between the 7500 ION and the
Fluke were within the range specified in the test plan as shown in Table 3-3.
These results led to the conclusion that the 7500 ION was installed and operating properly during the
verification test. The ± 1.0-percent error in power measurements, as certified by the manufacturer, was
used to reconcile the power output DQO (discussed above) and the electrical efficiency DQO (discussed
in Section 3.2.2).
3-5
-------
Table 3-3. Results of Additional QA/QC Checks
Measurement
Variable
Power Output
Fuel Flow Rate
Fuel Heating
Value
Heat Recovery
Rate
QA/QC Check
Sensor diagnostics in
field
Reasonableness checks
Reasonableness checks
Calibration with gas
standards by laboratory
Independent
performance checks
with blind audit sample
Meter zero check
Independent
performance check of
temperature readings
When
Performed/Frequency
Beginning and end of test
Throughout test
Throughout test
Prior to analysis of each
lot of samples submitted
Twice during previous
year
Prior to testing
Beginning of test period
Expected or Allowable
Result
Voltage and current checks
within ± 1% reading
Readings should be around 45
kW net power output at full
load
Readings expected to be
around 18 scfm at 45 kW
power output
± 1 .0% for each gas
constituent
± 3.0% for each major gas
constituent (methane, CO2)
Reported flow rate
<0.1 gpm
Difference in temperature
readings should be < 1.5 °F
Results Achieved
± 0.1% voltage
± 0.9% current
Readings were 44 to 46 kW
Readings were 19 to 21
scfm
Results satisfactory, see
Section 3.2.2.4
-0.06 gpm recorded
Temperature readings
within 0.8 °F of reference.
3.2.2. Electrical Efficiency
The DQO for electrical efficiency was to achieve an uncertainty of ± 1.52 percent at full electrical load or
less. Recall from Equation 1 (Section 1.4.1) that the electrical efficiency determination consists of three
direct measurements: power output, fuel flow rate, and fuel LHV. The accuracy goals specified to meet
the electrical efficiency DQO consisted of ± 1.5 percent for power output, ±1.0 percent for fuel flow rate,
and ± 0.2 percent for LHV. The accuracy goals for each measurement were met. The following
summarizes actual errors achieved and the methods used to compute them.
Power Output: As discussed in Section 3.2.1, factory calibrations of the 7500 ION with a NIST-
traceable standard and the inherent error in the current and potential transformers resulted in ± 1.0-percent
error in power measurements. Reasonableness checks in the field verified that the meter was functioning
properly. The average power output at full load was measured to be 45 kW and the measurement error is
determined to be ± 0.45 kW.
Heat Input: Heat input is the product of measured fuel flow rate and LHV. The DQI goal for fuel flow
rate was reconciled through calibration of the gas meter and the gas temperature and pressure sensors
used to correct measured gas volumes to standard conditions. All three components were calibrated with
NIST-traceable standards. As shown in Table 3-2, the individual instruments errors were 0.3, 0.25, and
0.1 percent for flow, pressure, and temperature respectively. The overall error in biogas flow rate then is
0.40 percent of reading. Therefore, the average flow rate at full load was 20.8 scfm with a measurement
error of ± 0.08 scfm. Complete documentation of data quality results for fuel flow rate is provided in
Section 3.2.2.3.
3-6
-------
Uncertainty in the biogas LHV results was within the 0.2 percent DQI goal (Section 3.2.2.4). The
average LHV during testing was 622 Btu/ft3 and the measurement error corresponding to this heating
value is ± 1.2 Btu/ft3. The heat input compounded error then is:
Error in Heat Input = -^(flowmetererrorf + (LHVerrorf
(Equation. 7)
= A/(0.004)2+(0.002)2 = 0.0045
The measurement error amounts to approximately ± 3.48 x 103Btu/hr, or 0.45 percent relative error at the
average measured heat input of 774.1 x 103Btu/hr.
The errors in the divided values compound similarly for the electrical efficiency determination. The
electrical power measurement error is ± 1.0 percent relative (Table 3-2) and the heat input error is ± 0.45
percent relative. Therefore, compounded relative error for the electrical efficiency determination is:
Error in Elec. Power Efficiency = -^(powermetererror) + (heatinputerrorj (Equation. 8)
= -J(0.010)2+(0.0045)2 =0.0110
Electrical efficiency for the controlled test periods at 45 kW was 19.7 ± 0.22 percent, or a relative
compounded error of 1.10 percent.
3.2.2.1. PTC-17 Requirements for Electrical Efficiency Determination
PTC-17 guidelines state that efficiency determinations were to be performed within 60 minute test periods
in which maximum variability in key operational parameters did not exceed specified levels. Table 3-4
summarizes the maximum permissible variations observed in power output, ambient temperature, ambient
pressure, biogas pressure at the meter, and biogas temperature at the meter for each test run. The table
shows that the PTC-17 requirements for all parameters were met for all test runs.
Table 3-4. Variability Observed in Operating Conditions
Maximum Allowable
Variation
Runl
Run 2
Run 3
Run 4
Run 5
Run 6
Run?
Run8
Run 9
Maximum Observed Variation" in Measured Parameters
Power
Output (%)
±3
1.1
0.4
1.2
0.8
0.8
0.8
0.8
0.5
0.6
Ambient
Temp. (°F)
±5
2.3
0.5
0.7
0.9
0.6
0.4
1.7
3.1
1.7
Ambient
Pressure (%)
±1
0.04
0.08
0.03
0.06
0.05
0.04
0.03
0.04
0.06
Biogas
Pressure (%)
±2
0.07
0.04
0.13
0.11
0.05
0.07
0.05
0.08
0.07
Biogas
Temperature
(°F)
±4
1.5
0.4
0.4
0.4
0.6
0.6
1.7
2.2
1.6
a Maximum (Average of Test Run - Observed Value) / Average of Test Run • 1 00
3-7
-------
3.2.2.2. Ambient Measurements
Ambient temperature, relative humidity, and barometric pressure at the site were monitored throughout
the extended verification period and the controlled tests. The instrumentation used is identified in Table
3-2 along with instrument ranges, data quality goals, and data quality achieved. All three sensors were
factory-calibrated using reference materials traceable to NIST standards. The pressure sensor was
calibrated prior to the verification testing, confirming the ± 0.1 percent accuracy. The temperature and
relative humidity sensors were also calibrated within a year prior to testing which verified that the ± 0.2
°F accuracy goal for temperature and ± 2 percent accuracy goal for relative humidity were met.
3.2.2.3. Fuel Flow Rate
The Dresser-Roots Model 2M175 rotary displacement gas meter was factory-calibrated prior to
installation in 1999. Calibration records were obtained and reviewed to ensure that the ± 1.0-percent
instrument accuracy goal was satisfied. Roots meter calibrations are permanent, indicating that this
meter's accuracy is ± 0.32 percent.
3.2.2.4. Fuel Lower Heating Value
Full documentation of biogas sample collection date, time, run number, and canister ID were logged
along with laboratory chain of custody forms and were shipped along with the samples. Copies of the
chain of custody forms and results of the analyses are stored in the GHG Center project files. Collected
samples were shipped to Empact Analytical Laboratories of Brighton, CO, for compositional analysis and
determination of LHV per ASTM test Methods D1945 [5] and D3588 [6], respectively. The DQI goals
were to measure methane concentrations within ±3.0 percent of a NIST-traceable blind audit sample and
to achieve less than ± 0.2 percent difference in LFfV duplicate analyses results. Blind audits were
submitted to Empact on two similar verifications within the past year to evaluate analytical accuracy on
the methane analyses [13, 14]. Both audits indicated analytical accuracy within 0.5 percent, and
repeatability of within ± 0.2 percent. Since the same sampling and analytical procedures were used here
by the same analyst, the audit was not repeated a third time.
In addition to the blind audit samples, duplicate analyses were conducted on three of the samples
collected during the controlled test periods. Duplicate analysis is defined as the analysis performed by the
same operating procedure and using the same instrument for a given sample volume. Results of the
duplicate analyses showed an average analytical repeatability of 0.06 percent for methane and 0.06
percent for LHV. The results demonstrate that the ± 0.2 percent LHV accuracy goal was achieved. As
such, both DQIs were met with the methane accuracy at ± 0.5 percent and the LHV repeatability at ± 0.06
percent.
3.2.3. Heat Recovery Rate and Efficiency
Several measurements were conducted to determine CHP system heat-recovery rate and thermal
efficiency. These measurements include water flow rate, water supply and return temperatures, and CHP
system heat input. The individual errors in each of the measurements is then propagated to determine the
overall error in heat-recovery rate and efficiency. The Controlotron ultrasonic heat meter was used to
continuously monitor water flow rate. This meter has a NIST-traceable factory-calibrated accuracy of ±
1.0 percent of reading (this flow through calibration was conducted on October 9, 2002). This
certification serves as the primary DQI. A zero check was also performed on the flow meter. The meter
reading was -0.06 gpm with the CHP system shut down and the circulation pump off.
3-8
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Table 3-2 showed that the DQI for supply and return temperatures (delta T) was achieved. Each
temperature sensor was calibrated against a reference thermocouple with NIST-traceable accuracy. The
error in the two temperature sensors resulted in an overall delta T uncertainty of 0.8 °C. This absolute
error equates to a relative error of 2.0 percent at the average fluid temperatures measured during the full-
load testing (about 39.4 °C). The overall error in heat recovery rate is then the combined error in flow
rate and temperature differential. This error compounds multiplicatively as follows:
= VCO.010)2 +(0.020)2 = 0.022 (Equatlon 9)
The heat recovery rate determination, therefore, has a relative compounded error of ± 2.2 percent. The
absolute error in the average heat recovery rate at 45 kW power setting (250 x 103 Btu/hr) then is ± 5.50 x
103Btu/hr.
This error in heat-recovery rate and the heat input error (0.45 percent) compound similarly to determine
the overall uncertainty in the thermal efficiency determination as follows:
ErrorinHeatRecovery Efficiency- V(0.022)2 +(0.0045)2 = 0.0224
(Equation. 10)
Average heat recovery rate (thermal) efficiency at full load then is 32.4 ± 0.73 percent, or a relative
compounded error of 2.24 percent. This compounded slightly exceeds the data quality objective for this
verification parameter (the absolute error meets the DQO however).
3.2.4. Total Efficiency
Total efficiency is the sum of the electrical power and heat-recovery efficiencies. For this test, total
efficiency is calculated as 19.7 ± 0.22 percent (± 1.10-percent relative error) plus 32.4 ± 0.73 percent (±
2.24-percent relative error). This is based on the determined errors in electrical and thermal efficiency at
the 45 kW power setting. The absolute errors compound as follows:
c,abs
VI 2
err^ +err2 (Equation. 11)
= A/0.222+0.732 =0.76
Relative error, is:
errc abs
err , = : (Equation. 12)
c,ret -r T / T 7- / v T. /
Value, +Value7
where:
errC;abs = compounded error, absolute
erri = error in first added value, absolute value
err2 = error in second added value, absolute value
errc rei = compounded error, relative
value i = first added value
value2 = second added value
3-9
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The total CHP efficiency at full load is 52.1 ± 0.76 percent, or 1.46 percent relative error. This
compounded slightly exceeds the data quality objective for this verification parameter (the absolute error
meets the DQO however).
3.2.5. Exhaust Stack Emission Measurements
EPA reference method requirements form the basis for the qualitative DQIs specified in the test plan and
listed in Tables 3-1 and 3-2. Each method specifies sampling and calibration procedures and data quality
checks. These specifications, when properly implemented, ensure the collection of high quality and
representative emissions data. The specific sampling and calibration procedures vary by method and
class of pollutants, and are summarized in Table 3-5. The table lists the method quality requirements, the
acceptable criteria, and the results for the test conducted here. It is generally accepted that conformance
to the reference method quality requirements demonstrates that the qualitative DQIs have been met.
All of the emissions testing and reference method quality control procedures were conducted by Cubix
Corporation either in the field during testing or in their calibration and analytical laboratories in Austin,
Texas. All of the field sampling procedures and calibrations were closely monitored by GHG Center
personnel. In addition, documentation of all sampling and analytical procedures, data collection, and
calibrations have been procured, reviewed, and filed by the GHG Center. Table 3-5 is followed by a brief
explanation of the QA/QC procedures implemented for each class of pollutant quantified during this
verification.
3.2.5.1. NOX, CO, CO2, SO2, TRS, and O2 Concentrations
Test personnel performed sampling system calibration error tests prior to each test run. All calibrations
employed a suite of three EPA Protocol No. 1 calibration gases (four for CO) that spanned the instrument
ranges. Appropriate calibration ranges were selected for each pollutant based on exhaust gas screening
(ranges are summarized in Table 3-2). The daily analyzer calibration error goal for each instrument was ±
2.0 percent of span. It was met for each analyzer during each day of testing.
Sampling system bias was evaluated for each parameter at the beginning of each test run using the zero
and mid-level calibration gases. System response to the zero and mid-level calibration gases also
provided a measure of drift and bias at the end of each test run. The maximum allowable sampling
system bias and drift values were ± 5 and ± 3 percent of span, respectively. These specifications were
met for each parameter and for each test run. Testers also performed a NOX converter efficiency test as
described in Section 3.5 of the test plan. The converter efficiency was 99.98 percent, which meets the 98-
percent goal specified in the method.
It should be noted that the CO analyzer was specified to be on a range of 0 to 1,000 ppm. The 4-point
instrument calibration was conducted at that range. However, due to the extremely high CO levels in the
exhaust gas, the range had to be increased to 0 to 10,000 ppm. A single calibration gas standard of 8,603
ppm was obtained to demonstrate instrument linearity at the higher range.
3-10
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Table 3-5. Summary of Emissions Testing Calibrations and QC Checks
Measurement
Variable
NOX, CO, CO2, SO2,
TRS, and O2
concentrations
CH4 concentrations
TPM emissions
NH3 concentrations
Exhaust gas
volumetric flow rate
Calibration or QC
Check
Analyzer calibration error
test
System bias checks
Calibration drift test
Triplicate injections
Calibration of GC with
gas standards by certified
laboratory
Pre and post test
sampling system leak
checks
Minimum sample volume
Percent isokinetic
sampling rate (I)
Analytical balance
calibration
Filter and reagent blanks
Dry gas meter calibration
Thermocouple calibration
Calibration of instrument
with NH3 standards
Dry gas meter calibration
Pilot tube dimensional
calibration / inspection
Thermocouple calibration
When Performed and
Frequency
Daily before testing
Before each test run
After each test run
Each test run
Immediately prior to
sample analyses and/or
at least once per day
Before and after each
test run
After each test run
After each test run
Once before analysis
Once during testing
after first test run
Once before and once
after testing
Once after testing
Immediately prior to
sample analyses and/or
at least once/day
Once before and once
after testing
Once before and once
after testing
Once after testing
Expected or
Allowable Result
± 2% of analyzer span
± 5% of analyzer span
± 3% of analyzer span
± 5% difference
± 5% for
each compound
Sampling system leak
rate < 0.02 cfm
Corrected Vol. > 60.0
dscf
90%
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3.2.5.3. Total Participate Matter and Exhaust Gas Volumetric Flow Rate
Reference Methods 1 through 5, used for determination of exhaust gas volumetric flow rate and total
particulate emissions, include numerous quality control and quality assurance procedures that are required
to ensure collection of representative data. The most important of these procedures are listed in Table 3-5
along with the results for these tests. These methods do not specify overall uncertainties, but it is
generally accepted that conformance to the control and quality assurance procedures will result in an
overall method uncertainty ranging from around 5 to 30 percent, depending on the mass of the particulate
catch, the quality of the sampling system, and the length of the sampling probe [15]. For these tests, TPM
catches were in the range of 10 to 20 mg, the sampling system surfaces contacting the exhaust gases were
constructed entirely of glass or Teflon, and the probe was less than 3-feet in length. In addition, testers
documented that all of the key method criteria were met. It is therefore expected that the overall error for
tests conducted here is ± 10 percent of reading. This exceeds the original goal of ± 5 percent, but this
deviation from the plan is not believed to impact results significantly because TPM emissions were very
low.
3.2.5.4. NH3 Concentrations
Ammonia samples were collected in the back-half of the total particulate sampling train and therefore all
of the sampling system criteria are the same as above. In the laboratory, analytical instrumentation was
calibrated using nine working standards. A calibration curve for the instrument was developed using this
nine-point calibration. The R2 for the calibration curve was 0.9997, indicating excellent analytical
linearity. Based on this, the same uncertainty used for the TPM determination (±10 percent) is assigned.
Again, this level of uncertainty exceeds the original goal of ± 5 percent, but as with the TPM emissions,
this deviation from the plan is not believed to impact results significantly because NH3 emissions were
also very low.
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