SRI/USEPA-GHG-VR-27
September 2003
Environmental Technology
Verification Report
Combined Heat and Power at a
Commercial Supermarket -
Capstone 60 kW Microturbine CHP System
Prepared by:
Greenhouse Gas Technology Center
Southern Research Institute
Under a Cooperative Agreement With
U.S. Environmental Protection Agency
and
Under Agreement With
IW5EHDA New York State Energy Research and Development Authority
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September 2003
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-27
September 2003
THE ENVIRONMENTAL TECHNOLOGY VERIFICATION PROGRAM
SERft
U.S. Environmental Protection Agency IUV5ERDA
SOUTHERN RESEARCH
INSTITUTE
ETV Joint Verification Statement
TECHNOLOGY TYPE: Natural-Gas-Fired Microturbine Combined With Heat
Recovery System
APPLICATION: Distributed Electrical Power and Heat Generation
TECHNOLOGY NAME: Capstone 60 Microturbine CHP System
COMPANY: Capstone Microturbine Corporation
ADDRESS: Chatsworth, CA
WEBSITE: www .microturbine. com
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. The GHG Center has collaborated with the New York State Energy
and Development Authority (NYSERDA) to evaluate the performance of a combined heat and power
system (CHP system) designed and installed by CDH Energy Corporation. The primary components of
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September 2003
the CHP system tested are a Capstone 60 MicroTurbine™ and a Unifin International heat exchanger.
This verification statement provides a summary of the test results for the CHP system.
TECHNOLOGY DESCRIPTION
Large- and medium-scale gas-fired turbines have been used to generate electricity since the 1950s.
Technical and manufacturing developments during the last decade have enabled the introduction of
microturbines with generation capacities ranging from 30 to 200 kW. The CHP system tested here is a
cogeneration installation that integrates microturbine technology with a heat-recovery system. The
following description of the CHP system tested is based on information provided by CDH Energy and the
equipment vendors and does not represent verified information.
Electric power is generated by a Capstone 60 microturbine with a nominal power output of 60 kW (59 °F,
sea level). The system operates on natural gas and consists of an air compressor, recuperator, combustor,
turbine, and a permanent magnet generator. Preheated air is mixed with fuel and this compressed fuel/air
mixture is burned in the combustor under constant pressure conditions. The resulting hot gas is allowed
to expand through the turbine section to perform work, rotating the turbine blades to turn a generator
which produces electricity. The need for a gearbox and associated moving parts is eliminated because of
the inverter-based electronics that enable the generator to operate at high speeds and frequencies. The
rotating components are mounted on a single shaft supported by patented air bearings that rotate at over
96,000 revolutions per minute (rpm) at full load. The exhaust gas exits the turbine and enters the
recuperator that pre-heats the air entering the combustor to improve the efficiency of the system. The
exhaust gas is then directed to the Unifin heat-recovery unit.
The Unifin is a fin-and-tube heat exchanger (Model MG2) suitable for up to 700 °F exhaust gas. A
nominal 25-percent mixture of propylene glycol (PG) in water is used as the heat-transfer media to
recover energy from the microturbine exhaust gas stream. The PG fluid is circulated at a rate of up to 50
gallons per minute (gpm). A digital controller monitors the PG fluid outlet temperature and, when the
temperature exceeds the user set point, a damper automatically opens and allows the hot exhaust gas to
bypass the heat exchanger and release the heat through the stack. The damper allows hot gas to circulate
through the heat exchanger when heat recovery is required (i.e., the PG fluid outlet temperature is less
than user setpoint). This design allows the system to protect the heat recovery components from the full
heat of the turbine exhaust while still maintaining full electrical generation from the microturbine.
The generator produces high-frequency alternating current which is rectified, inverted, and filtered by the
line power unit into conditioned 480-volts alternating current (VAC). The unit supplies an electrical
frequency of 60 hertz (Hz) and is supplied with a control system which allows for automatic and
unattended operation. An active filter in the generator is reported by the turbine manufacturer to provide
power that is free of spikes and unwanted harmonics. All operations, including startup, setting of
programmable interlocks, grid synchronization, operational setting, dispatch, and shutdown, can be
performed either manually or remotely using an internal power controller system. This CHP system also
incorporates a Copeland-Scroll Model SZN22C1A gas booster compressor with a nominal volume
capacity of 29 standard cubic feet per minute (scfm) and the capability of compressing natural gas from
inlet pressures of 0.25 to 15 pounds per square inch gauge (psig) to outlet pressures of 60 to 100 psig.
The verification of the Capstone 60 microturbine system was conducted at a 57,000-sq ft Waldbaums
Supermarket constructed in 2002. The store uses energy-efficient T4 light fixtures so the load in the sales
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September 2003
area is about 1.2 watts per square foot. The facility electric demand is never expected to drop below 200
kW in this store. The three-phase 480 volt power generated by the microturbine is wired directly into the
store's 480-volt main panel. This CHP unit was integrated with a 20,000-cfm Munters Drycool air-
handling unit previously installed at the Waldbaums. The Munters is the primary source of space heating,
air conditioning, and air-dehumidification at the store. Recovered heat from the Capstone 60 CHP
System is used to supplement the Munters' primary functions of heating the main sales areas of the store,
and air dehumidification. The CHP system can provide heat to either the PG coil in the supply air stream
that provides space heating in the winter or the PG coil that preheats the air entering the direct-fire burner
that regenerates the desiccant wheel.
VERIFICATION DESCRIPTION
Testing commenced on June 4, 2003, and was completed on June 20, 2003. The testing included a series
of controlled test periods in which the GHG Center intentionally modulated the unit to produce electricity
at nominal power output commands of 15, 30, 45, and 60 kW. Demand for space heating and dessicant
regeneration was low during the testing period due to the mild weather. The PG was, therefore, manually
directed to the Munter's space-heating coil during each of the controlled test periods. This was done to
maximize the heat demand on the CHP system and verify CHP performance under periods of high heat
demand. The controlled tests at the 30 and 60 kW power command points were also repeated with the
Unifm heat exchanger damper open (heat recovery bypass mode) to evaluate the impact of heat exchanger
back-pressure on microturbine performance. The controlled test periods were followed by 14 days of
extended monitoring to verify electric power production, heat recovery, power quality performance, and
efficiency during an extended period of normal site operations. The classes of verification parameters
evaluated were:
• Heat and Power Production Performance
• Emissions Performance (NOX, CO, THC, CO2, and CH4)
• Power Quality Performance
Evaluation of heat and power production performance includes 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 Gas Turbines (ASME PTC-22) and
tests consisted of direct measurements of fuel flow rate, fuel lower heating value (LHV), and power
output. Heat recovery rate and thermal efficiency were determined according to ANSI/ASHRAE test
methods and tests consisted of direct measurements of heat-transfer fluid flow rate, differential
temperatures, and specific heat of the heat transfer fluid. Ambient temperature, barometric pressure, and
relative humidity measurements were also collected to characterize the condition of the combustion air
used by the turbine.
The evaluation of emissions performance occurred simultaneously with efficiency testing conducted
during the controlled test period. Pollutant concentration and emission rate measurements for nitrogen
oxides (NOX), carbon monoxide (CO), total hydrocarbons (THC), carbon dioxide (CO2), and methane
(CFU) were conducted in the turbine exhaust stack. All test procedures used in the verification were U.S.
EPA reference methods recorded in the Code of Federal Register (CFR). Pollutant emissions are reported
in two sets of units - 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 turbine
power output and reported as pounds per kilowatt hour (Ib/kWh).
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September 2003
Annual NOX and CO2 emissions reductions for the CHP system at the test site are estimated by comparing
measured Ib/kWh emission rates with corresponding emission rates for the baseline power and heat-
production systems (i.e., systems that would be used if the CHP system were not present). The baseline
systems at this site include electricity supplied from the local utility grid and heat from the facility's
natural gas-fired burners. Baseline emissions for the electrical power were determined following Ozone
Transport Commission (OTC) guidelines. Baseline emissions from heat production are based on EPA
emission factors for commercial-scale gas-fired burners.
Electrical power quality parameters, including electrical frequency and voltage output, were also
measured during the 14-day extended test. Current and voltage total harmonic distortions (THD) and
power factors were also monitored to characterize the 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). EPA personnel conducted an on-site technical systems audit
during the testing program. The GHG Center staff conducted two performance evaluation audits and an
audit of data quality on at least 10 percent of the data generated during this verification. The GHG Center
field team leader and project manager have reviewed the data from the verification testing and have
concluded that the data have attained the data quality objectives that are specified in the Test and Quality
Assurance Plan.
VERIFICATION OF PERFORMANCE
Heat and Power Production Performance
• The average gross power output at full load was 59.6 kW at these test conditions (corresponding gross
electrical efficiency was about 28.4 percent). The gross power output would be available to potential
users not needing sources of significant parasitic load such as the gas compressor and glycol circulation
pump.
• Considering parasitic loads from the gas compressor and glycol circulation pump, the net power
delivered at full load averaged 54.9 kW. Net electrical efficiency during the controlled test periods
ranged from 26.2 percent at full load to 13.1 percent at the lowest load tested (25 percent of capacity).
Electrical efficiency was not impacted by changes in operation of the heat recovery system.
HEAT AND POWER PRODUCTION
Test Condition
Full load, heat
recovery
maximized
Electrical Power Generation
Gross
Power
Output
(kW.)
59.6
Gross
Efficiency
(%)
28.4
Net Power
Delivered
(kWe)
54.9
Net
Efficiency
(%)
26.2
Heat Recovery
Performance
Heat
Recovery
(103Btu/hr)
373.0
Thermal
Efficiency
(%)
52.2
Total
CHP
System
Efficiency
(%)
78.4
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September 2003
HEAT AND POWER PRODUCTION
Test Condition
75-percent load,
heat recovery
maximized
50-percent load,
heat recovery
maximized
25-percent load,
heat recovery
maximized
Full load, normal
operation
50-percent load,
normal operation
Electrical Power Generation
Gross
Power
Output
(kW.)
44.5
29.5
14.4
59.6
29.5
Gross
Efficiency
(%)
27.0
23.8
19.3
28.4
23.7
Net Power
Delivered
(kWe)
39.9
24.8
9.8
54.9
24.9
Net
Efficiency
(%)
24.2
20.0
13.1
26.2
20.0
Heat Recovery
Performance
Heat
Recovery
(103Btu/hr)
317.0
239.6
148.5
51.4
68.6
Thermal
Efficiency
(%)
56.4
56.7
58.0
7.2
16.2
Total
CHP
System
Efficiency
(%)
80.7
76.7
71.1
33.3
36.2
• Total CHP efficiency during the controlled test periods with operation configured to maximize heat
recovery ranged from 71.1 percent at 25-percent load to 80.7 percent at 75-percent load. CHP efficiency
was 33.3 percent at full load during normal heat recovery controlled tests because of low space heating
and dehumidification demand during testing.
• Electrical, thermal, and CHP efficiencies during the 14-day extended monitoring period averaged 25.7,
8.0, and 33.7 percent, respectively. Low space heating and dehumidification demand was evident
throughout the period.
Emissions Performance
• NOX emissions at full load were 0.00015 Ib/kWh and increased as power output decreased.
Changes in operation of the heat exchanger did not produce a significant impact on NOX
emissions.
• Emissions of CO, THC, and QL, were also lower at full load and increased slightly as power
output was reduced. Changes in operation of the heat exchanger did not produce a significant
impact on emissions of these pollutants.
• NOX emissions per unit electrical power output at full load were 0.00015 Ib/kWh, well below the
average levels reported for the regional grid (0.0024 Ib/kWh). The average CO2 emissions for the
regional grid are estimated at 1.53 Ib/kWh which is nearly identical to the emission rate for the
Capstone 60 (which had 1.54 lb/kWhe). These values, along with emission reductions attributed to
the CHP system heat recovery performance, yield an average annual emission reduction of 1,064 Ibs
(17 percent) for NOX and 328,478 Ibs (8 percent) for CO2.
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September 2003
CRITERIA POLLUTANT AND GREENHOUSE GAS EMISSIONS
Test Condition
Full load, heat
recovery
maximized
75-percent load,
heat recovery
maximized
50-percent load,
heat recovery
maximized
25-percent load,
heat recovery
maximized
Full load, normal
operation
50-percent load,
normal operation
(ppmvd at 15% O2)
NOX
3.13
3.30
4.26
6.56
3.05
4.50
CO
3.53
154
582
338
3.90
586
THC
1.06
70.3
1194
327
0.69
1154
CH4
<0.9
43.5
721
198
Not
tested
678
(lb/kWhe)
NOX
1.49 xlO"4
1.71 x 10"4
2.67 x 10"4
6.31xlQ-4
1.47xlO"4
2.83 x 1Q-4
CO
1.03 x 10"4
4.86 x 10"3
2.26 x 10"2
1.98xlO-2
1.14xlO-4
2.25 x 1Q-2
THC
1.77 x 10"5
1.27 x 10"3
2.61 x 10"2
1.09 x 1Q-2
1.14xlO-5
2.53 x 1Q-2
CH4
<1.58x
io-5
7.84 x
io-4
1.57 x
io-2
6.65 x
io-3
Not
tested
1.48 x
io-2
CO2
1.54
1.61
1.87
2.89
1.49
1.87
Power Quality Performance
• The CHP system maintained continuous synchronization with the utility grid throughout the 14-day test
period. Average electrical frequency was 60.000 Hz and average voltage output was 494.48 volts.
• The power factor remained relatively constant for all monitoring days with an average of 99.98 percent.
• The average current THD was 5.66 percent and the average voltage THD was 1.98 percent. The THD
threshold specified in IEEE 519 is ± 5 percent.
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
Combined Heat and Power at a Commercial Supermarket, Capstone 60 kW Microturbine (SRI 2002).
Detailed results of the verification are presented in the Final Report titled Environmental Technology
Verification Report for Combined Heat and Power at a Commercial Supermarket, Capstone 60 kW
Microturbine (SRI 2003). 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).
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SRI/USEPA-GHG-VR-27
September 2003
Signed by: Hugh W. McKinnon, 9-2003 Signed by: Stephen D. Piccot, 9-2003
Hugh W. McKinnon, M.D., M.P.H. Stephen D. Piccot
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-27
September 2003
Greenhouse Gas Technology Center
A U.S. EPA Sponsored Environmental Technology Verification ( Yftf ) Organization
Environmental Technology Verification Report
Combined Heat and Power at a Commercial Supermarket-
Capstone 60 kW Microturbine CHP System
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 826311-01-0
and NYSERDA Agreement 7009
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
NYSERDA Project Officer: Richard Drake
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September 2003
TABLE OF CONTENTS
Page
APPENDICES iii
LIST OF FIGURES iii
LIST OF TABLES iii
ACKNOWLEDGMENTS iv
ACRONYMS AND ABBREVIATIONS v
1.0 INTRODUCTION 1-1
1.1. BACKGROUND
1.2. CHP TECHNOLOGY DESCRIPTION.
1.3. TEST FACILITY DESCRIPTION
1.3.1. Integration of CHP System with Facility Operations
1.4. PERFORMANCE VERIFICATION OVERVIEW
1.4.1. Heat and Production Performance
-1
-2
-5
-6
-7
-9
1.4.2. Measurement Equipment 1-10
1.4.3. Power Quality Performance 1-12
1.4.4. Emissions Performance 1-14
1.4.5. Estimated Annual Emission Reductions for Waldbaums 1-15
2.0 VERIFICATION RESULTS 2-1
2.1. HEAT AND POWER PRODUCTION PERFORMANCE 2-2
2.1.1. Electrical Power Output, Heat Recovery Rate, and Efficiency During
Controlled Tests 2-3
2.1.2. Electrical and Thermal Energy Production and Efficiencies Over the
Extended Test 2-7
2.2. POWER QUALITY PERFORMANCE 2-9
2.2.1. Electrical Frequency 2-9
2.2.2. Voltage Output 2-9
2.2.3. Power Factor 2-10
2.2.4. Current and Voltage Total Harmonic Distortion 2-11
2.3. EMISSIONS PERFORMANCE 2-12
2.3.1. CHP System Stack Exhaust Emissions 2-12
2.3.2. Estimation of Annual Emission Reductions for Waldbaums 2-16
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-22 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 3-9
3.2.3. Heat Recovery Rate and Efficiency 3-10
3.2.4. Total Efficiency 3-11
3.2.5. Exhaust Stack Emission Measurements 3-11
4.0 TECHNICAL AND PERFORMANCE DATA SUPPLIED BY CDH ENERGY 4-1
5.0 REFERENCES 5-1
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Page
APPENDIX A
APPENDIX B
Figure 1-1
Figure 1-2
Figure 1-3
Figure 1-4
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
Figure 2-10
Figure 4-1
Figure 4-2
APPENDICES
Emissions Testing QA/QC Results A-l
Estimation of Regional Grid Emissions B-l
LIST OF FIGURES
Pas
The Waldbaums Capstone 60 Microturbine System 1-3
Capstone 60 Microturbine System Process Diagram 1-4
Waldbaums Supermarket in Hauppauge, New York 1-6
Schematic of Measurement System 1-11
Heat and Power Production During Controlled Test Periods 2-6
CHP System Efficiency During Controlled Test Periods 2-6
Heat and Power Production During the Extended Monitoring Period (1-hr avg) 2-7
Ambient Temperature Effects on Power Production 2-8
Ambient Temperature Effects on Electrical Efficiency During Extended Test Period.. 2-8
Capstone 60 Frequency During Extended Test Period 2-9
Capstone 60 Voltage During Extended Test Period 2-10
Capstone 60 Power Factor During Extended Test Period 2-11
Capstone 60 Voltage During Extended Test Period 2-12
Capstone 60 Emissions as Function of Power Output 2-15
Comparing Measured and Rated Efficiency for the Capstone C60 at Full Load 4-2
Comparing Measured and Rated Power Output for the Capstone C60 at Full Load .... 4-3
LIST OF TABLES
Pas
Table 1-1
Table 1-2
Table 1-3
Table 1-4
Table 1-5
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 2-9
Table 3-1
Table 3-2
Table 3-3
Table 3-4
Table 3-5
Table 3-6
Table 4-1
Capstone 60 Microturbine Specifications 1-5
Unifm MG2 Heat Exchanger Specifications 1-5
Controlled and Extended Test Periods 1-8
Summary of Emissions Testing Methods 1-14
Annual Electrical and Thermal Demand for the Hauppauge Waldbaums 1-16
Heat and Power Production Performance 2-4
Fuel Input and Heat Recovery Unit Operating Conditions 2-5
Electrical Frequency During Extended Period 2-9
Capstone 60 Voltage During Extended Period 2-10
Power Factors During Extended Period 2-11
Capstone 60 THD During Extended Period 2-11
CHP Emissions During Controlled Periods 2-14
Emissions Offsets From On-Site Electricity Production 2-17
Estimated Annual Emission Reductions using the CHP System 2-18
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 3-8
Results of Natural Gas Audit Sample Analysis 3-9
Additional QA/QC Checks for Emissions Testing 3-13
Comparing Measured and Rated Emissions for Capstone C60 at Full Load 4-4
in
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ACKNOWLEDGMENTS
The Greenhouse Gas Technology Center wishes to thank NYSERDA, especially Richard Drake and Dana
Levy, for reviewing and providing input on the testing strategy and this Verification Report. Thanks are
also extended to the Waldbaum's Supermarket (a subsidiary of A&P Foods) for hosting the verification.
Finally, special thanks to Hugh Henderson and Adam Walburger of CDH Energy Corporation for their
assistance in executing the verification testing.
IV
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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
DHW
DMM
DOE
DP
DQI
DQO
dscf/106Btu
EA
EIA
EPA
ETV
°C
OF
FERC
FID
fps
ft3
gal
GC
GHG Center
gpm
GU
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 feet
Corrective Action Report
quantification of methane
methane
combined heat and power
carbon monoxide
carbon dioxide
current transformer
data acquisition system
distributed generation
domestic hot water
digital multimeter
U.S. Department of Energy
differential pressure
data quality indicator
data quality objective
dry standard cubic feet per million British thermal units
Engineering Assistant
Energy Information Administration
Environmental Protection Agency
Environmental Technology Verification
degrees Celsius
degrees Fahrenheit
Federal Energy Regulatory Commission
flame ionization detector
feet per second
cubic feet
U.S. Imperial gallons
gas chromatograph
Greenhouse Gas Technology Center
gallons per minute
generating unit
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September 2003
(continued)
Hg
HHV
hr
Hz
1C
IEEE
IPCC
ISO
ISONE
kVA
kVAr
kW
kWh
kWhe
kWhth
kWh/yr
Ib
Ib/Btu
Ib/dscf
lb/ft3
Ib/hr
Ib/kWh
Ib/yr
LHV
LIPA
103Btu/hr
106Btu/hr
106cf
mol
N2
NDIR
NIST
NO
NO2
NOX
NSPS
NY ISO
NYSERDA
02
O3
ORD
OTC
ACRONYMS/ABBREVIATIONS
(continued)
Mercury (metal)
higher heating value
hour
hertz
internal combustion
Institute of Electrical and Electronics Engineers
Intergovernmental Panel on Climate Change
International Standards Organization and Independent System Operator
ISO New England
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
Long Island Power Authority
thousand British thermal units per hour
million British thermal units per hour
million cubic feet
molecular
nitrogen
nondispersive infrared
National Institute of Standards and Technology
nitrogen oxide
nitrogen dioxide
nitrogen oxides
New Source Performance Standards
New York ISO
New York State Energy Research and Development Authority
oxygen
ozone
Office of Research and Development
Ozone Transport Commission
VI
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(continued)
PEA
PG
PJM
ppmv
ppmvw
ppmvd
psia
psig
PT
QA/QC
QMP
Rel. Diff.
Report
RH
rms
rpm
RTD
scf
scfh
scfm
Southern
T&D
TEI
Test Plan
THCs
THD
TSA
U.S.
VAC
ACRONYMS/ABBREVIATIONS
(continued)
Performance Evaluation Audit
propylene glycol
Pennsylvania/New Jersey/Maryland
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
Quality Management Plan
relative difference
Environmental Technology Verification Report
relative humidity
root mean square
revolutions per minute
resistance temperature detector
standard cubic feet
standard cubic feet per hour
standard cubic feet per minute
Southern Research Institute
transmission and distribution
Thermo Environmental Instruments
Test and Quality Assurance Plan
total hydrocarbons
total harmonic distortion
technical systems audit
United States
volts alternating current
vn
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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 as a distributed
generation source. 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
(CHP) gneration).
The GHG Center and the New York State Energy Research and Development Authority (NYSERDA)
recently agreed to collaborate and share the cost of verifying several new DG technologies operating
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throughout the state of New York under NYSERDA-sponsored programs. This verification evaluated the
performance of a Capstone 60 kW Microturbine Combined Heat and Power System (CHP System)
installed and integrated by CDH Energy Corporation (CDH). The test unit is currently in use at the
Waldbaums Supermarket in Hauppauge, New York. The CHP System uses a natural gas-fired 60 kW
microturbine for electricity generation, and a heat recovery unit to provide space heating or desiccant
regeneration at the supermarket. Facility electrical and thermal demand exceeds the CHP capacity, so the
facility can operate the system continuously at full load. The system is interconnected to the electric
utility grid, but the facility does not anticipate exporting power for sale.
The GHG Center evaluated the performance of the CHP system by conducting field tests over a
seventeen-day verification period (June 4-20, 2003). These tests were planned and executed by the GHG
Center to independently verify the electricity generation and use rate, thermal energy recovery rate,
electrical power quality, energy efficiency, emissions, and greenhouse gas emission reductions for the
Waldbaums Supermarket. This report presents the results of these verification tests.
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 the
Combined Heat and Power at a Commercial Supermarket, Capstone 60 Microturbine System™ [10]. 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 NYSERDA, system integrators at the
supermarket (CDH Energy), 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 CHP system technology and test facility and outlines the
performance verification procedures that were followed. Section 2 presents test results, and Section 3
assesses the quality of the data obtained. Section 4, submitted by CDH Energy, presents additional
information regarding the CHP system. Information provided in Section 4 has not been independently
verified by the GHG Center.
1.2. CHP TECHNOLOGY DESCRIPTION
Natural gas-fired turbines have been used to generate electricity since the 1950s. Technical and
manufacturing developments in the last decade have enabled the introduction of microturbines, with
generation capacity ranging from 30 to 200 kW. Microturbines have evolved from automotive and truck
turbocharger technology and small jet-engine technology. A microturbine consists of a compressor,
combustor, power turbine, and generator. They have a small number of moving parts and their compact
size enables them to be located on sites with limited space. A waste heat-recovery system can be
integrated with a microturbine to achieve higher efficiencies for sites with thermal demands.
The microturbine system verified at Waldbaums Supermarket is shown in Figure 1-1. It consists of a
Capstone 60 MicroTurbine (developed by Capstone Turbine Corporation) and a heat-recovery system
(developed by Unifin International). The CHP system also includes a Copeland-Scroll natural gas
compressor which is needed to boost the delivered gas pressure from approximately 5 to 90 psig. The
compressed gas is regulated at 75 psig as required by the Capstone. Figure 1-2 illustrates a simplified
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process flow diagram of the microturbine CHP system at this site and a discussion of each component is
provided below.
Capstette-6€
Microturbine
Umfm Heat
Exchanger
Figure 1-1. The Waldbaum's Capstone 60 Microturbine System
Electric power is generated from a high-speed, single-shaft, recuperated, air-cooled turbine generator with
a nominal power output of 60 kW net (59 °F, sea level). Table 1-1 provides Capstone 60 microturbine
specifications. Table 1-2 summarizes the physical and electrical specifications for the Capstone 60,
which is designed to operate on natural gas and consists of an air compressor, recuperator, combustor,
turbine, and a permanent magnet generator. The recuperator is a heat exchanger that recovers some of the
heat from the exhaust stream and transfers it to the incoming compressed air stream. The preheated air is
then mixed with the fuel and this compressed fuel/air mixture is burned in the combustor under constant
pressure conditions. The resulting hot gas is allowed to expand through the turbine section to perform
work, rotating the turbine blades to turn a generator, which produces electricity. The need for a gearbox
and associated moving parts is eliminated because of the inverter-based electronics that enable the
generator to operate at high speeds and frequencies. The rotating components are mounted on a single
shaft - supported by patented air bearings - that rotates at over 96,000 revolutions per minute (rpm) at
full load. The exhaust gas exits the turbine and enters the recuperator which pre-heats the air entering the
combustor to improve the efficiency of the system. The exhaust gas then exits the recuperator into a
Unifm heat-recovery unit.
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CHP System
Exhaust
Microturbine Exhaust
Copeland-Scroll
Gas Compressor
(to 90 psig)
Natural Gas
Input (nominal 5 psig)
To Space
Heating Coil
To Desiccant
Regeneration Coil
Figure 1-2. Capstone Microturbine System Process Diagram
The permanent magnet generator produces high-frequency alternating current which is rectified, inverted,
and filtered by the line power unit into conditioned 480 volts alternating current (VAC). The unit
supplies an electrical frequency of 60 hertz (Hz) and is supplied with a control system which allows for
automatic and unattended operation. An active filter in the generator is reported by the turbine
manufacturer to provide cleaner power, free of spikes and unwanted harmonics. All operations including
startup, setting of programmable interlocks, grid synchronization, operational setting, dispatch, and
shutdown, can be performed manually or remotely using the internal power-controller system.
The gas booster compressor is a Copeland-Scroll Model SZN22C1A with a nominal volume capacity of
29 standard cubic feet per minute (scfm) and the capability of compressing natural gas from inlet
pressures ranging from 0.25 to 15 pounds per square inch gauge (psig) to outlet pressures of 60 to 100
psig. The compressor is boosting gas pressure from approximately 5 to 90 psig in this application. A
regulator is located downstream of the compressor to control and maintain gas pressure to the
microturbine at 75 psig. The compressor imposes a parasitic load of approximately 3.9 kW on the overall
CHP system generating capacity.
Figure 1-2 shows that waste heat from the microturbine exhaust, at approximately 580 °F, is recovered
using a heat recovery and control system developed by Unifin International and integrated by Capstone. It
is an aluminum fin-and-tube heat exchanger (Model MG2) suitable for up to 700 °F exhaust gas. A
nominal 25-percent mixture of PG in water (designated as "PG fluid" for the remainder of this document)
is used as the heat-transfer media to recover energy from the microturbine exhaust gas stream. The PG
fluid is circulated at a rate of up to 50 gallons per minute (gpm). A digital controller monitors the PG
fluid outlet temperature, and when the temperature exceeds user set point, a damper automatically opens
and allows the hot exhaust gas to bypass the heat exchanger and release the heat through the stack. The
damper allows hot gas to circulate through the heat exchanger when heat recovery is required (i.e., the PG
fluid outlet temperature is less than user setpoint). This design allows the system to protect the heat
recovery components from the full heat of the turbine exhaust while still maintaining full electrical
generation from the microturbine.
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Table 1-1. Capstone 60 Microturbine Specifications
(Source: Capstone Turbine Corporation)
Dimensions
Weight
Electrical Inputs
Electrical Outputs
Noise Level
Fuel Pressure
Required
Fuel Heat Content
Electrical
Performance at
Full Load (natural
gas)
Heat Recovery
Potential at Full
Load
Emissions
(full load)
Width
Depth
Height
Microturbine only
Power (startup)
Communications
Power at ISO conditions 60 °F at sea level
Typical reported by Capstone
w/o natural gas compressor
w/ natural gas compressor
Higher heating value
Heat input
Power output
Efficiency - with natural gas compressor
Heat rate
Exhaust gas temperature
Exhaust energy available for heat recovery
Nitrogen oxides (NOX)
Carbon monoxide (CO)
Total hydrocarbon (THCs)
30 in.
77 in.
83 in.
1,671 Ib
Utility grid
Ethernet IP or modem
60 kW, 400-480 VAC,
50/60 Hz, 3 -phase
70 dBA at 33 ft
75 psig
0.5 to 15 psig
970to2615Btu/scf
81 1,000 Btu/hr, Natural gas-HHV
60 kW ± 1 kW
28% ± 2%, ISO conditions, LHV basis
12,200 Btu/kWh, LHV basis
580 °F
541,000 Btu/hr, LHV basis
< 9 ppmv at 15% O2
<40ppmvatl5%O2
<9ppmvatl5%O2
Table 1-2. Unifin MG2 Heat Exchanger Specifications
(Source: Unifin International, Inc.)
Weight
Dimensions
Heat Exchanger Efficiency
Exhaust Design Temperature
Tubeside Design Temperature
Tubeside Design Pressure
Design Heat Input
Output
820 Ib
34.75"(W) x 48.5"(D) x 70. 1875"(H)
> 90% (at full load at water inlet temperature =
120 °F)
700 °F for C60
220 or 275 °F, closed-loop
150 psig
541,000 Btu/hr
375,000 Btu/hr at 180 °F return fluid temperature
1.3. TEST FACILITY DESCRIPTION
The verification of the Capstone 60 microturbine system was conducted at the Waldbaums' Supermarket
(constructed in 2002) and pictured in Figure 1-3. This new supermarket was originally a 35,000-sq. ft.
retail facility. It was gutted to the block walls, expanded, and totally rebuilt into a 57,000-sq. ft.
supermarket. It recently opened in July 2002. The store uses energy-efficient T4 light fixtures, so the
load in the sales area is about 1.2 watts per square foot. The facility electric demand is never expected to
drop below 200 kW in this store. The 480-volt power generated by the microturbine is wired directly into
the store's 480-volt main panel. This unit was integrated in July 2002 with a 20,000-cfm Munters
Drycool air-handling unit previously installed at Waldbaums in order to use the available heat from the
Capstone 60 kW microturbine CHP system. The Munters unit provides cooling and heating to the main
sales areas of the store. The unit also includes a desiccant section to provide dehumidification. The
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Munters air-handling unit was configured to be capable of using recovered heat when it is available or
reverting back to the conventional natural gas-fired burners otherwise.
Figure 1-3. Waldbaums Supermarket in Hauppauge, NY
1.3.1. Integration of CHP System with Facility Operations
The facility electric load remains above the 60 kW microturbine generating capacity at all times and the
unit normally operates "base-loaded" at full generating capacity. The unit is designed to shut down
during power outages. The local utility currently does not require any interconnect protections other than
those integrated into the Capstone 60 system. The heat demands of the facility will vary on a daily and
seasonal basis and, although well-matched on the average to the heat generated and recoverable from the
unit, will not generally represent a constant load or use the maximum available heat from the
microturbine. The specific design of the CHP system in this application is unique in using two different
heat-recovery pathways to optimize overall annual heat use at the facility.
The single large 20,000-cfm central air handler for the facility (the Munters unit) makes it easier to use
waste heat from the turbine to meet the space-heating loads. The space-heating loads are expected to be
significant in this application due to the year-round space cooling load imposed by the refrigerated
display cases. The need for heat to provide desiccant regeneration also adds significant heating loads in
the summer.
PG fluid from the Capstone Unifin heat-recovery unit provides heat to two hot coils that have been added
to the Munters air-handling unit: (1) a PG coil in the supply air stream that provides space heating in the
winter, and (2) a PG coil that preheats the air entering the direct-fire burner that regenerates the desiccant
wheel. This arrangement with the Unifin heat exchanger was selected because it provides the greatest
amount of year-round heat recovery which is required because of the large space-heating loads common
to this climate (Note: An alternate configuration was also considered that would have used turbine
exhaust directly for desiccant regeneration, but it was not implemented because it precluded the use of
heat recovery for space heating.) The Unifin heat exchanger recovers heat from the microturbine exhaust
that is used by the Munters unit to provide either space heating or desiccant regeneration. The PG fluid
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piping from the Unifm is directly connected to hot PG fluid coils in the Munters unit. The microturbine
skid, which includes the Capstone turbine, Unifm heat exchanger, and natural gas compressor module, is
installed on the roof adjacent to the Munters air-handling unit (approximately 35 feet apart).
1.4. PERFORMANCE VERIFICATION OVERVIEW
This verification test design was developed to evaluate only the performance of the CHP system—not the
overall building 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 15, 30, 45, and 60 kW. Demand for space heating and desiccant
regeneration was low during the testing period due to the mild weather. The PG was, therefore, manually
directed to the Munter's space-heating coil during each of the controlled test periods (the store was heated
for short periods of time). This was done in an attempt to maximize the heat demand on the CHP system
and demonstrate CHP performance under periods of high heat demand. These tests are identified herein
as controlled test periods with heat recovery maximized.
The Test Plan also specified that controlled tests at the 30 and 60 kW power command points be repeated
with the Unifm heat exchanger damper open (heat recovery bypass mode) to evaluate the impact of heat
exchanger back-pressure on microturbine performance. However, problems with the Unifm control panel
precluded the GHG Center from manually locking open the damper. Instead, these tests were conducted
under normal CHP and Munters system operations such that the Unifm damper was automatically opened
in response to the low heat demand of the store during the test periods. This allowed these tests to be
conducted with operations similar to those planned because the Unifm would go into heat-recovery mode
(that is, with the damper closed) only long enough to maintain PG temperatures above 170 °F under these
conditions. The heat exchanger damper was open for approximately 25 minutes and then closed to heat
recovery mode for the remainder of time during each of the 30-minute test replicates conducted under
these conditions. These tests are identified herein as controlled test periods under normal conditions.
The controlled test periods were followed by a period of extended monitoring to evaluate power and heat
production and power quality over a range of ambient conditions and store operations. The microturbine
was allowed to operate continuously at full load during the extended monitoring period.
The specific verification factors associated with the test are listed below. Brief discussions of each
verification factor and its method of determination are presented in Sections 1.4.1 through 1.4.5. Detailed
descriptions of testing and analysis methods are not provided here but can be found in the Test Plan.
Heat and Power Production Performance
• Electrical power output and heat recovery rate at full load
• Electrical, thermal, and total system efficiency at full load
• Combined heat and power efficiency (total efficiency)
Power Quality Performance
• Electrical frequency
• Voltage output
• Power factor
• Voltage and current total harmonic distortion
Emissions Performance
• Nitrogen oxides (NOX) concentrations and emission rates
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• Carbon monoxide (CO) concentrations and emission rates
• Total hydrocarbon (THC) concentrations and emission rates
• Carbon dioxide (CO2) and methane (CH/^ concentrations and emission rates
• Estimated greenhouse gas emission reductions
Each of the verification parameters listed were evaluated during the controlled or extended monitoring
periods as summarized in Table 1-3. This table also specifies the dates and time periods during which the
testing was conducted.
Table 1-3. Controlled and Extended Test Periods
Controlled Test Periods
Date
Time
Test Condition
Verification Parameters
Evaluated
06/04/03
06/04/03
06/05/03
06/05/03
06/05/03
06/05/03
13:05-14:55
Power command of 60 kW in maximum heat-recovery mode,
three 30-minute test runs
15:40-17:30
Power command of 60 kW in current (low) heat-recovery
mode, three 30-minute test runs
10:15-12:10
Power command of 45 kW in maximum heat-recovery mode,
three 30-minute test runs
12:35-14:25
Power command of 30 kW in maximum heat-recovery mode,
three 30-minute test runs
NOX, CO, THC, CH4, CO2
emissions, and electrical,
thermal, and total efficiency
14:45-16:35
Power command of 30 kW current (low) heat-recovery mode,
three 30-minute test runs
16:45-18:35
Power command of 15 kW in maximum heat-recovery mode,
three 30-minute test runs
06/06/03
07:40-09:30
Emissions profile test over range of power commands from 15
to 60 kW in 5 kW increments
NOX, CO, THC, CH4, CO2
emissions
Extended Test Periods
Start Date, Time End Date, Time
Verification Parameters Evaluated
06/06/03, 12:00
06/20/03, 12:00
Total electricity generated; total heat recovered; electrical, thermal, and total
efficiency; power quality; and emission offsets
Simultaneous monitoring for power output, heat recovery rate, fuel consumption, ambient meteorological
conditions, and exhaust emissions were performed during each of the controlled test periods. Manual
samples of natural gas and PG solution were collected to determine fuel lower heating value and specific
heat of the heat transfer fluid. 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.
Daily performance of the CHP system was characterized over the 14-day extended monitoring period
following the controlled test periods. The CHP system was operating 24 hours per day at maximum
electrical power output. The facility's heat demand was generally low due to the warm weather
conditions during this period. There was some demand for desiccant regeneration, so the heat recovery
performance measured during the period is representative for this facility during early summer conditions.
It is likely that seasonal changes in space heating and regeneration demand for this facility will have a
significant impact on the system's heat-recovery performance.
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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 are estimated using measured greenhouse gas emission rates, emissions estimates
for electricity produced at central station power plants, and emissions estimates for the Munters unit gas-
fired burners.
1.4.1. Heat and Production Performance
Electrical efficiency determination was based upon guidelines listed in ASME PTC-22 [5], and was
calculated using the average measured net power output, fuel flow rate, and fuel lower heating value
(LHV) during each 30-minute test period. The CHP system has two primary parasitic loads at this
facility: (1) the gas-pressure booster compressor, and (2) the PG fluid circulation pump. This verification
includes measurement of these two parasitic loads to report the net system efficiency. For potential users
with access to has high-pressure gas and/or PG circulation facilities, the gross power output and electrical
efficiencies are also reported here.
The electrical power output (in kW) was measured continuously throughout the verification period with a
7600 ION Power Meter (Power Measurements Ltd.). A second power meter (7500 ION) was used to
simultaneously monitor parasitic power consumption by the gas compressor. The power consumed by the
PG circulation pump was not independently monitored by the GHG Center, but is continuously logged by
site operators at one-minute intervals. The corresponding one-minute data logged by the operators were
used to determine pump draw. The accuracy of the pump draw data was not verified but is stated by the
manufacturer to be within ± 1 percent of reading. The reported parasitic load, at approximately 0.75 kW
during all test periods, represents a small portion of total CHP system heat and power production.
Therefore, a true assessment of watt-meter accuracy is not expected to impose a significant impact on the
net efficiency determination.
Fuel input was measured with an in-line orifice-type flow meter (Rosemount, Inc.). Fuel gas sampling
and energy content analysis (via gas chromatograph) was conducted according to ASTM procedures to
determine the lower heating value of natural gas. Ambient temperature, relative humidity, and barometric
pressure were measured near the turbine air inlet to support the determination of electrical conversion
efficiency as required in PTC-22. Electricity conversion efficiency was computed by dividing the
average electrical energy output by the average energy input using Equation 1.
34U.UkW ,_ 1X
77= (Eqn. 1)
HI
where:
*7 = efficiency
kW = average net electrical power output measured over the 30-minute interval (kW),
(Capstone 60 power output minus power consumed by gas compressor and PG
circulation pump)
HI = average heat input using LHV over the test interval (Btu/hr); determined by
multiplying the average mass flow rate of natural gas 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
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Heat recovery rate was measured simultaneous with electrical power measurements using an in-line PG
flow meter (Onicon Model F-1110) and PG supply and return temperatures (Controlotron Model
1010EP). The meters enabled one-minute averages of differential heat exchanger temperatures and PG
mixture flow rates to be monitored. Manual samples of the PG solution were collected to determine PG
concentration, fluid density, and specific heat such that heat recovery rates could be calculated at actual
conditions per ANSI/ASHRAE Standard 125 [4].
Heat Recovery Rate (Btu/min) = Vp Cp (T1-T2) (Eqn. 2)
where:
V = total volume of liquid passing through the heat meter flow sensor during a minute (ft3)
p = density of PG solution (lb/ft3), evaluated at the avg. temp. (T2 plus Tl)/2
Cp = specific heat of PG 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:
r|T = 60*Qavg/HI (Eqn. 3)
where:
r|T = thermal efficiency
Qavg = average heat recovered (Btu/min)
HI = average heat input using LHV (Btu/hr); determined by multiplying the average mass
flow rate of natural gas to the system (converted to scfh) times the gas LHV (Btu/scf)
1.4.2. Measurement Equipment
Figure 1-4 illustrates the location of measurement instruments that were used in the verification.
The ION electrical power meters continuously monitored the kilowatts of power generated by the
Capstone 60 and consumed by the compressor at a rate of approximately one reading every 8 to 12
milliseconds. These data are averaged every minute using the GHG Center's data acquisition system
(DAS). The generator meter was located in the main switchbox connecting the CHP to the host site and
represented power delivered to Waldbaums. The real-time data collected by the meters were downloaded
and stored on a data acquisition computer using Power Measurements' PEGASYS software. 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 for the extended test period over the
duration of the verification period to calculate total electrical energy generated in units of kilowatt hours
(kWh).
The mass flow rate of the fuel was measured using an integral orifice meter (Rosemount Model
3095/1195). The orifice meter contained a 0.512-inch orifice plate to enable flow measurements at the
ranges expected during testing (10 to 15 scfm natural gas). The Rosemount orifice meter includes gas
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pressure and temperature sensors for flow rate compensation to provide mass flow output at standard
conditions (60 °F, 14.696 psia). Note that the Rosemount was located upstream of the gas compressor,
and, therefore, the measured gas pressures and temperatures were not indicative of fuel conditions
entering the microturbine. Gas pressure into the microturbine were not independently verified, but
indicated by a pressure gauge to be 75 psig. The meter was configured to continuously monitor the
average flow rate at one-minute intervals. The meter components (orifice plate and differential pressure
sensors) were calibrated prior to testing using NIST-traceable instruments. Additional QA/QC checks for
this meter were performed routinely in the field, including reasonableness and zero checks.
Natural Gas
Supply
Air Intake
Exhaust Gas
To Atmosphere
>
— x-
r
Gas
Compressor
PG Supply
PG Return
AC Power
Measurement Locations
(A) Fuel Gas Flow and Pressure '
CB) Gas Samples for LHV
(c) Fuel Gas Temperature
/O, Power Production
And Power Quality
~^\ Power Consumed
By Compressor
J) PG Flow Rate
"q)PG Supply
Temperature
s PG Return
Temperature
) Emissions Testing
\ Ambient Temperature,
' Pressure, and Humidity
Figure 1-4. Schematic of Measurement System
Natural gas samples were collected and analyzed to determine gas composition and heating value. A total
of six samples were collected—four during the control test periods and another two during the extended
monitoring. The collected 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 [7]. The compositional data were then
used in conjunction with ASTM Specification D3588 to calculate LFfV and the relative density of the gas
[8]. Duplicate analyses were performed by the laboratory on two of the samples to determine the
repeatability of the LFfV results.
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A Controlotron Model 1010EP1 energy meter was used to monitor PG 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 fluid flow rate
component failed intermittently during some of the field testing, so the meter was used only to monitor
PG temperatures and to confirm the accuracy of a replacement meter used to monitor PG flow rates. An
Onicon Model F-l 110 turbine meter was used to continuously monitor PG fluid flow rate. The meter has
an overall rated accuracy of ± 0.5 percent of reading and provides a continuous 4-20 mA output signal
over a range of 0 to 80 gpm. The meter was installed in the 2-inch Type-L copper PG supply line by
CDH Energy.
The PG flow rate and supply and return temperature data were logged as one-minute averages throughout
all test periods and used in Equation 2 to determine CHP system recovery rates. The two other variables
in Equation 2—fluid density and specific heat—were determined by collecting PG samples during the test
periods and submitting the samples to Energy Laboratories of Billings, MT, for compositional analyses.
The PG samples were collected from a fluid discharge spout located on the hot side of the heat-recovery
unit using 250-mL capacity sample containers. A total of six PG samples were collected, including one
per day during the controlled test periods, and four during the extended monitoring period. Each sample
collection event was recorded on field logs and shipped to the laboratory along with completed chain-of-
custody forms. Samples were analyzed at the laboratory for PG concentration and fluid density using gas
chromatography with a flame ionization detector (GC/FID). Specific heat of the PG solution was selected
using published PG properties data [6] using the measured concentrations.
1.4.3. Power Quality Performance
There are a number of issues of concern when an electrical generator is connected in parallel and operated
simultaneously with the utility grid. The voltage and frequency generated by the power system must be
aligned with the power grid. The units must detect grid voltage and frequency while in grid parallel mode
to ensure proper synchronization before actual grid connection occurs. The Capstone 60 system
electronics contain circuitry to detect and react to abnormal conditions that, if exceeded, cause the unit to
automatically disconnect from the grid. These out-of-tolerance operating conditions include
overvoltages, undervoltages, and over/under frequency. With stakeholder input, the GHG Center has
defined grid voltage tolerance as the nominal voltage ±10 percent for previous verifications. Frequency
tolerance is 60 ± 0.6 Hz (1.0 percent).
Another issue is the generator's effects on electrical frequency, power factor, and total harmonic
distortion (THD)—they cannot be completely isolated from the grid. The quality of power delivered
actually represents an aggregate of disturbances already present in the utility grid. An example is that
local CHP power with low THD will tend to dampen grid power with high THD in the test facility's
wiring network. This effect will drop off with distance from the CHP generator.
The GHG Center and its stakeholders developed the following power quality evaluation approach to
account for these issues. Two documents [1,2] 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
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The 7600 ION power meter used for power output determinations was used to perform these
measurements as described below and detailed in the Test Plan. The factory calibrated the ION power
meter to ANSI C12.20 CAO.2 standards prior to field installation. Electricity supplied in the U.S. and
Canada is typically 60 Hz AC. 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 480 volts (AC). The electric power industry accepts that
voltage output can vary within ±10 percent of the standard voltage (480 volts) without causing significant
disturbances to the operation of most end-use equipment [3]. 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. True rms voltage
readings provide the most accurate representation of AC voltages. 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. The ION power meter applies Fourier Analysis algorithms to quantify
THD. Fourier showed that any wave form can be analyzed as one sum of pure sine waves with different
frequencies and that each contributing sine wave is an integer multiple (or harmonic) of the lowest (or
fundamental) frequency. The fundamental is 60 Hz for electrical power in the U.S. The 2nd harmonic is
120 Hz, the 3rd is 180 Hz, and so on. Certain harmonics, such as the 5th or 12th, can be strongly affected
by the types of devices (that is, capacitors, motor control thyristors, inverters) connected to the
distribution network.
The magnitude of the distortion can vary for each harmonic. Each harmonic's magnitude is typically
represented as a percentage of the rms voltage of the fundamental. The aggregate effect of all harmonics
is called THD. THD is the sum of the rms voltage of all harmonics divided by the rms voltage of the
fundamental, converted to a percentage. 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 [2].
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 and, similar to voltage THD, can be
quantified by Fourier Analysis. 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. The standard's
recommendations for a small CHP unit connected to a large-capacity grid, for example, are more
forgiving than those for a large CHP unit connected to a small-capacity 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
recommendation. The ION power meter, as with voltage THD, continuously measured current THD for
each phase and reported the average.
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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.
1.4.4. Emissions Performance
Pollutant concentration and emission rate measurements for NOX, CO, THCs, CH^, and CO2 were
conducted on the turbine exhaust stack during all of the controlled test periods. Emissions testing
coincided with the efficiency determinations described earlier. All of the test procedures used are 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) [12].
Table 1-4 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 1-4. Summary of Emissions Testing Methods
Exhaust Stack
Pollutant
NOX
CO
THC
CH4
CO2
02
EPA Reference
Method
20
10
25A
18
3A
3A
Analyzer Type
TEI Model 42LS (chemiluminescense)
TEI Model 48 (NDIR)
TEI Model 51 (FID)
Hewlett-Packard 5890 GC/FID
Servomex Model 1440 (NDIR)
Servomex Model 1440 (electrochemical)
Instrument Range
0 - 25 ppm
0-25 ppm at high load, 0 -
1,000 ppm at reduced loads
0-18 ppm at high load, 0 -
500 ppm at reduced loads
0 - 500 ppm
0 - 10%
0 - 25%
Sampling was conducted during each test for approximately 30 minutes at a single point near the center of
the 10-inch diameter stack. Results of the instrumental testing are reported in units of parts per million
volume dry (ppmvd) and ppmvd corrected to 15-percent O2. The emissions testing was conducted by
ENSR International of East Syracuse, NY, 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.
EPA Method 19 was followed to convert measured pollutant concentrations into emission rates in units of
pounds per hour (Ib/hr). The fundamental principle of Method 19 is based upon F-factors. F-factors are
the ratio of combustion gas volume to the heat content of the fuel and are calculated as a volume/heat
input value, (e.g., standard cubic feet per million Btu). This method specified all calculations required to
compute the F-factors and provides guidelines for their use. The published F-factor of 8,710 dry standard
cubic feet per million Btu (dscf/106Btu) was used to determine emission rates for each controlled test
period. Pollutant concentrations were converted from a ppmvd basis to Ib/dscf. The emission rates were
then calculated using the measured heat input to the turbine [106Btu/hr based on the higher heating value
(HHV) of the gas] and stack gas O2 concentration (dry basis) in terms of Ib/hr as follows:
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Mass Emission Rate (Ib/hr) = HI * Concentration * F-factor * [20.9 / (20.9-% O2J] (Eqn. 4)
where:
HI = average measured heat input, HHV based (106Btu/hr)
Concentration = measured pollutant concentration (Ib/dscf)
F-factor = calculated exhaust gas flow rate (dscf/106Btu)
O2,d = measured O2 level in exhaust stack, dry basis (%)
20.9 = oxygen concentration in air I
The mass emission rates as Ib/hr were then normalized to electrical power output by dividing the mass
rate by the average power output measured during each controlled test and are reported as pounds per
kilowatt-hour electrical (lb/kWhe).
1.4.5. Estimated Annual Emission Reductions for Waldbaums
All of the Waldbaums' electrical power and heat demand is met by the local utility, LIPA, and the gas-
fired Munters unit when on-site generation of electricity and heat with the CHP is unavailable. Electricity
generation from central power stations and heat production from the Munters' gas burners then defines the
baseline power and heat scenario for this facility. Emissions of NOX and CO2 generated by these systems
represent the baseline emissions in the absence of the CHP system. Some of the power and heat demand
of the facility is met through on-site generation with the CHP system operating. Less power is purchased
from the utility grid under this scenario and less heat is generated by the gas-fired burners. A reduction in
emissions is realized under the CHP system scenario if CHP emissions of CO2 and NOX are lower than
the emissions associated with the generation of energy displaced from the baseline scenario.
Emissions from the CHP scenario for this verification are compared with the baseline scenario to estimate
annual NOX and CO2 emission levels and reductions (Ib/yr). Reliable emission factors for electric utility
grid and burners are available for both gases. Emission reductions were computed as follows:
Annual Emission Reductions (Ib/yr) = [Baseline Scenario Emissions] - [CHP Scenario Emissions]
Annual Emission Reductions (%) = Annual Emission Reductions (Ib/yr) /[Baseline Scenario Emissions]* 100
The following 4 steps describe the methodology used.
Step 1 - Determination of Waldbaum's Annual Electrical and Thermal Energy Profiles
The first step in estimating emission reductions was to estimate the supermarket's annual electrical
(kWhe) and thermal energy demand (kWhth) for a typical calendar year. System integrators (CDH
Energy Systems) are monitoring these data as part of a long-term demonstration of CHP performance for
NYSERDA [14]. The data span the first year of the supermarket's operation beginning in August 2002
and ending in June 2003. Demand data for the month of July are projected. The monthly electrical
demand (power consumption) and Munters' air-handling system gas use (heat demand) were made
available to the GHG Center for this analysis and are summarized in Table 1-5.
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Table 1-5. Annual Electrical and Thermal Demand for the Hauppauge Waldbaums
(Provided by CDH Energy Corporation)
Month
August 2002
September 2002
October 2002
November 2002
December 2002
January 2003
February 2003
March 2003
April 2003
May 2003
June 2003
July 2003
Totals
Electrical Demand
(kWhe)
239,441
225,634
194,258
166,075
164,062
167,012
152,592
172,600
164,823
187,295
204,690
222,066
2,260,548
Heat Demand (kWhth)
Space Heating
0
0
21,684
75,973
113,774
143,898
123,463
89,261
70,370
45,458
14,160
0
698,045
Desiccant
Regeneration
53,398
52,401
21,257
4,167
1,671
0
0
932
0
1,292
12,353
32,883
180,354
The utility grid and Munters unit provide all power and heat necessary to meet these demand values under
the baseline scenario. The average electrical generating rate measured during the extended test period is
used to estimate electrical offsets (55.08 kW) for the CHP scenario. Estimation of heat offsets for the
CHP scenario is beyond the scope of this verification. Therefore, heat offsets are estimated using
projected CHP heat recovery rates developed by CDH during system design (see Test Plan Section 2.5.3).
The total annual projected useable heat from the CHP system is 394,513 kWh for space heating and
95,257 kWh for desiccant regeneration.
Step 2 - Emissions Estimate for the CHP
Emissions associated with this system were estimated using the energy production data for the CHP as
follows:
ECHP = kWhe CHP *
(Eqn. 5)
where:
ECHP = CHP emissions (Ib/yr)
kWhe,cHp = Annual electrical energy generated by CHP (kWh/yr)
= CHP emission rate (Ib/kWh)
The CO2 and NOX emission rates defined above are equivalent to the average full load emission rate
determined during the verification test (see Section 2).
Step 3 - Emissions Estimate for the Utility Grid
Emissions associated with electricity generation at central power stations is defined by the following
equation:
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rid * 1.078* ERGnd (Eqn. 6)
where:
Eorid = grid emissions (Ib/yr)
kWhe Gnd = electricity supplied by the grid (kWh)
1.078 = transmission and distribution system line losses (%)
ER^ = NY ISO-displaced emission rate (lb/kWhe)
The kWhe Gnd variable shown above represents the estimated electricity supplied by the utility grid under
either the baseline or CHP scenario. These values are increased by a factor of 1.078 to account for line
losses between central power stations and the end user.
Defining the grid emission rate (ERond) is complex and the methodol for estimating this parameter is
continuously evolving. The discussion presented in Appendix B-l provides a brief background on the
concept of displaced emissions and presents the strategy employed by the GHG Center to assign ERond
for this verification.
Step 4 - Emissions Estimate For the Gas Burners
Combustion of the carbon in natural gas will form CO2. The resulting CO2 emission rate for each of the
Munters' gas burners is then calculated as follows:
44 1412 1 1
ERBurnerC02 = — * (CC) * (FO) * '— * (Eqn. 7)
12 1,000,000 (Ef/Burner/100)
where:
ERBumerco2 = burner CO2 emission rate (Ib/kWhth)
44 = molecular weight of CO2 (Ib/lb-mol)
12 = molecular weight of carbon (Ib/lb-mol)
CC = measured fuel carbon content (35.04 lb/106Btu)
FO = 0.995; fraction of natural gas carbon content oxidized during
combustion
3412.1 =lkWth/Btu
1,000,000 = 1 106Btu/Btu
Eff Burner = Combustion efficiency of gas burners (69.5% for the space heating coil, 95%
for the desiccant regeneration burner)
The carbon content of natural gas sampled at the test site by the GHG Center is used to determine the CO2
emission rates for the space heating and regeneration burners. These values are 0.628 and 0.459
Ib/kWhth, respectively. These emission rates assume that the burner efficiency is the same at all heat
output levels; that is, the units are not derated for part-load operating conditions. Efficiency profiles at
various heat output levels were not available for this unit to allow such corrections to be made. NOX
emission factors for gas-fired burners were obtained from AP-42 [13]. Burners such as those used in the
Munters unit are categorized as similar to commercial boilers under 100 106Btu/hr heat input. The NOX
emission factor for such units is listed as 100 lb/106 scf of natural gas. The average measured LHV for
the natural gas used at the host facility was approximately 903 Btu/scf. This means that 106 scf of natural
gas will supply approximately 903 106Btu of heat to the burners. The resulting NOX emission rate is
expected to be approximately 100/903, or 0.1107 lb/106Btu (or 0.000378 Ib/kWh).
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2.0 VERIFICATION RESULTS
The verification period started on June 4, 2003, and continued through June 20, 2003. The controlled
tests were conducted on June 4 and 5, and were followed by an extended fourteen-day period of
continuous monitoring to examine heat and power output, power quality, efficiency, and emission
reductions.
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 (for example, gas flow, gas pressure, gas temperature, power
output and quality, heat recovery rate, and ambient conditions)
• Fuel gas compositional data
• Emissions testing data
• PG compositional analyses
• 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-22 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. Factory 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 and PG 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 days listed above include periods when the unit was operating normally. The GHG Center has made
every attempt to obtain a reasonable set of 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 (especially
the severe winter weather conditions that can be experienced at this site).
Test results are presented in the following subsections:
Section 2.1 - Heat and Power Production Performance
(short-term controlled testing 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 quality of power generated by the CHP system is generally high and that the
unit is capable of operating in parallel with the utility grid. The unit produced between 48 and 56 kW of
net electrical power depending on ambient temperature (51 to 84 °F) during the extended monitoring
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September 2003
period. The highest heat recovery rate measured during normal operations during the extended
monitoring period was approximately 318,700 Btu/hr under normal site operation (approximately 370,700
Btu/hr was the maximum heat recovery rate measured during the controlled test periods with heat
recovery manually maximized). Electrical efficiency averaged 26.2 percent. Thermal efficiency
averaged 51.6 percent (7.1 percent under normal heat-recovery operations) at full load with forced heat
recovery. Corresponding total CHP system efficiency at full load was 77.8 percent (33.3 percent under
normal heat recovery operations). NOX emissions at full load were 4 ppmvd or less (corrected to 15-
percent O2). NOX and CO2 emission reductions are estimated to be at least 17 and 8 percent, respectively.
In support of this verification, QA staff from EPA-ORD's Technical Services Branch conducted an on-site
Technical Systems Audit (TSA) of the GHG Center's testing activities and procedures. Based on the
verification approaches and testing procedures specified in the Test Plan, the overall conclusion of the
audit was that the GHG Center performed well during this verification. Certain deviations from planned
activities and other items of concern were documented in the TSA report, and each is addressed in this
report. The primary items noted are listed below along with the location in this report where each item is
addressed (in parentheses).
• How the "heat exchanger damper full open" test condition was conducted (Section 1.4).
• The determination of the parasitic load associated with the glycol pump and its consideration for
the overall heat-recovery efficiency of the CHP system (Section 1.4.1).
• The actual gas pressure of the fuel gas entering the Capstone 60 (Section 1.4.2).
• The absence of a true flow-through calibration of the fuel gas meter system (Section 3.2.2.3).
• Calibration of the Vaisala ambient temperature and relative humidity sensor (Section 3.2.2.2).
• The circumstances surrounding the expansion of the calibration ranges for the CO and THC
analyzers (Section 3.2.5).
• Substitution of the faulty Controlotron glycol flow meter with the Onicon turbine meter (Sections
1.4.2 and 3.2.3).
• The impact that questionable insulation around the surface-mounted RTDs may have imposed on
the glycol delta-temperature readings (Section 3.2.3).
• The final condition of the Tedlar bags samples shipped to the analytical laboratory for
determination of methane in exhaust gases (Section 3.2.5).
In addition to the TSA, the GHG Center conducted two performance evaluation audits (PEAs) and 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. The data quality
assessment is then used to demonstrate whether the data quality objectives (DQOs) introduced in the Test
Plan were met for this verification.
2.1. HEAT AND POWER PRODUCTION PERFORMANCE
The heat and power production performance evaluation included electrical power output, heat recovery,
and efficiency determination 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.
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2.1.1. 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 54 to 71 °F, relative humidity ranged from 62 to 97 percent,
and barometric pressure was between 14.47 and 14.74 psia during the controlled testing periods. The
conditions encountered during testing were similar to standard conditions defined by the International
Standards Organization (59 °F, 60 percent PvH, and 14.696 psia). The results shown in Table 2-1 and the
discussion that follows are representative of conditions encountered during testing and are not intended to
indicate performance at other operating conditions such as cooler temperatures and different elevations.
Supporting natural gas fuel input characteristics and heat recovery unit operation data corresponding to
the test results are summarized in Table 2-2.
The average net electrical power delivered to the supermarket was 54.9 kWe at full load. The average
electrical efficiency corresponding to these measurements was 26.2 percent. The average gross power
output at full load was 59.6 kW at these test conditions (corresponding gross electrical efficiency was
about 28.4 percent). The gross power output would be available to potential users not needing sources of
significant parasitic load such as the gas compressor and glycol circulation pump. Electric power
generation heat rate, which is an industry-accepted term to characterize the ratio of heat input to electrical
power output, averaged 13,025 Btu/kWhe at full power.
The average heat-recovery rate at full power with heat demand maximized was 373.0 103Btu/hr, or 109.3
kWth/hr, and thermal efficiency was 52.2 percent. Results of three runs indicated that the total efficiency
(electrical and thermal combined) was 78.4 percent at this condition. The net heat rate, which includes
energy from heat recovery, was 4,354 Btu/kWhtot.
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Table 2-1. Heat and Power Production Performance
Test
ID
Runl
Run 2
Run 3
Avg.
Run 4
Run 5
Run 6
Avg.
Run?
Run8
Run 9
Avg.
Run 10
Run 11
Run 12
Avg.
Run 13
Run 14
Run 15
Avg.
Run 16
Run 17
Run 18
Avg.
Test
Condition
100% Load
-Heat
recovery
maximized
100% Load
- Normal
75% Load -
Heat
recovery
maximized
50% Load -
Heat
recovery
maximized
50% Load -
Normal
25% Load -
Heat
recovery
maximized
Heat Input
103Btu/hr)
715.6
715.2
714.6
715.1
716.0
716.7
717.3
716.7
558.8
562.9
563.6
561.8
423.0
423.0
422.3
422.8
423.7
425.0
424.9
424.5
254.5
258.0
255.4
256.0
Electrical Power Generation Performance
Net Power
Delivered a
(kWe)
54.94
54.92
54.91
54.93
54.91
54.92
54.93
54.92
39.87
39.88
39.89
39.88
24.84
24.83
24.83
24.83
24.85
24.85
24.86
24.85
9.80
9.80
9.79
9.80
Net
Efficiency
(%)
26.2
26.2
26.2
26.2
26.2
26.2
26.1
26.2
24.4
24.2
24.2
24.2
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
13.1
13.0
13.1
13.1
Gross Power
Output
(kWe)
59.59
59.56
59.56
59.57
59.54
59.55
59.56
59.55
44.52
44.52
44.53
44.52
29.49
29.49
29.48
29.49
29.49
29.49
29.49
29.49
14.46
14.46
14.46
14.46
Gross
Efficiency
(%)
28.4
28.4
28.4
28.4
28.4
28.4
28.3
28.4
27.2
27.0
27.0
27.0
23.8
23.8
23.8
23.8
23.8
23.7
23.7
23.7
19.4
19.1
19.3
19.3
Heat Recovery
Performance
Heat
Recovery
Rateb
(103Btu/hr)
370.0
374.6
374.4
373.0
62.8
39.8
51.4
51.4
318.3
315.2
317.6
317.0
239.6
239.7
239.4
239.6
79.9
63.7
62.8
68.6
154.3
145.2
146.1
148.5
Thermal
Efficiency
(%)
51.7
52.4
52.4
52.2
8.8
5.6
7.2
7.2
57.0
56.0
56.4
56.4
56.7
56.7
56.7
56.7
18.7
15.0
14.8
16.2
60.6
56.3
57.2
58.0
Total CHP
System
Efficiency
(%)
77.9
78.6
78.6
78.4
34.9
31.7
33.3
33.3
81.3
80.2
80.5
80.7
76.7
76.7
76.8
76.7
38.7
35.0
34.7
36.2
73.8
69.2
70.3
71.1
Ambient Conditions
c
Temp
(°F)
55.5
54.7
54.5
54.9
54.3
54.7
54.9
54.6
58.1
60.4
62.9
60.4
63.0
62.3
62.2
62.5
64.0
66.8
70.6
67.1
70.7
67.0
66.8
68.1
RH (%)
97
97
96
97
97
96
97
97
92
88
83
88
81
83
84
83
79
72
62
71
63
75
73
70
a Represents actual power available for consumption at the test site (power generated less parasitic loads of gas compressor and PG circulation pump).
b Divide by 3412. 14 to convert to equivalent kilowatts (kWfh).
0 Barometric pressure remained relatively consistent throughout the test runs (14.47 to 14.74 psia).
2-4
-------
SRI/USEPA-GHG-VR-27
September 2003
Table 2-2. Fuel Input and Heat Recovery Unit Operating Conditions
Runl
Run 2
Run 3
Avg.
Run 4
Run 5
Run 6
Avg.
Run 7
Run8
Run 9
Avg.
Run 10
Run 11
Run 12
Avg.
Run 13
Run 14
Run 15
Avg.
Run 16
Run 17
Run 18
Avg.
Test Condition
%of
Rated
Power
100
100
75
50
50
25
Site
Operations
Heat
recovery
maximized
Normal
Heat
recovery
maximized
Heat
recovery
maximized
Normal
Heat
recovery
maximized
Natural Gas Fuel Input
Gas
Flow
Rate
(scfm)
13.2
13.2
13.2
13.2
13.2
13.2
13.3
13.2
10.3
10.4
10.4
10.4
7.81
7.81
7.79
7.80
7.82
7.84
7.84
7.84
4.70
4.76
4.71
4.72
LHVa
(Btu/ft3)
902.4
—
~
—
~
901.9
~
902.2
902.3
—
~
~
~
~
~
~
~
~
~
903.7
903.0
Gas
Pressure
(psig)
5.06
5.09
5.08
5.08
5.09
5.11
5.11
5.10
5.12
5.15
5.10
5.12
5.12
5.14
5.16
5.14
5.17
5.20
5.15
5.17
5.10
5.07
5.15
1.89
Gas
Temp
no
58.3
57.8
57.9
58.0
56.6
56.9
57.5
57.0
63.8
69.3
72.9
68.7
72.1
69.8
70.0
70.6
72.4
77.5
84.9
78.3
84.5
75.6
73.8
78.0
PG Fluid Conditions
PG
Comp.b
volume)
25.5
25.0
Fluid
Flow
Rate
(gpm)
50.6
50.6
50.5
50.5
44.6
44.4
44.9
44.6
50.4
50.6
50.6
50.5
50.3
50.4
50.3
50.3
44.9
44.9
44.6
44.8
50.2
50.2
50.2
50.2
Outlet
Temp.
(TO
137.7
137.3
137.2
137.4
174.7
175.3
176.6
175.5
128.3
127.9
129.5
128.6
116.3
115.7
115.5
115.8
177.3
178.1
179.8
178.4
107.8
103.9
103.4
105.0
Inlet
Temp.
no
122.5
121.9
121.8
122.1
171.2
173.4
174.2
172.9
115.2
115.0
116.4
115.5
106.4
105.8
105.7
106.0
173.7
175.1
176.9
175.2
101.4
97.9
97.3
98.9
Temp.
Diff.
no
15.2
15.4
15.4
15.3
2.9
1.9
2.4
2.4
13.1
13.0
13.0
13.0
9.9
9.9
9.9
9.9
3.7
3.0
2.9
3.2
6.4
6.0
6.1
6.2
a Represents results of gas samples collected during each day (average of two samples taken during runs 1-6, and two samples from runs 7-18).
b Represents results of PG samples collected once each day.
The average full-power heat-recovery rate during normal site operations (low heat demand under these
test conditions) was 51.4 103Btu/hr, or 15.1 kWth/hr, and thermal efficiency was 7.2 percent. Results of
three runs showed that the total efficiency was 33.3 percent. Net heat rate, which includes energy from
heat recovery, was 10,236 Btu/kWhtot under normal operations.
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, remains high throughout the
range of operation with the heat recovery operations maximized and increases slightly as electrical power
2-5
-------
SRI/USEPA-GHG-VR-27
September 2003
output is reduced. These trends are illustrated in Figures 2-1 and 2-2 which display the power and heat
production and CHP system efficiency for each of the controlled test conditions.
100
3
Q.
s.
Net Power Delivered
Gross Power Output
Heat Recovery Rate
10
60 kW setting, : 45 kW setting, 30 kW setting, ' 15 kW setting,
i-ia^t rcv>r»«»ru i-ia^t rar>nwaru Heat recovery Heat recovery
Heat recovery
maximized
Heat recovery
maximized
maximized maximized
60 kW setting,
Heat recovery
normal
30 kW setting,
Heat recovery
normal
Figure 2-1. Heat and Power Production During Controlled Test Periods
80 -
70
S?
X 60 -
o
c
Ol
° 50 -
HI
40
W 30
20 -
10
0 -
j^f^^JH^j ,^\ ...
••"•nf"""*
Net CHP Efficienc
— j „ .
V*H<**t+&***+l*t
|
fL
^— ^r*«*-
—
| \N»+f**
Thermal Efficiency !
_^
jr
Net Electrical^^
Efficiency
60 kW setting,
Heat recovery
maximized
I 45 kW setting,
Heat recovery
maximized
Gross Electrical
•^ Efficiency
30 kW setting,
Heat recovery
maximized
•
t
y
! "Ml
i
Uu
it
V
t
HJK
i^v
•V
*
1 15 kW setting, 60 kW setting, ' 30 kW setting,
Heat recovery Heat recovery Heat recovery
maximized normal normal
Figure 2-2. CHP System Efficiency During Controlled Test Periods
2-6
-------
SRI/USEPA-GHG-VR-27
September 2003
2.1.2. Electrical and Thermal Energy Production and Efficiencies Over the Extended Test
Figure 2-3 presents a time series plot of power production and heat recovery during the 14-day extended
verification period. The system was operating 24 hours per day and was producing as much electrical
power as possible depending on ambient conditions. Heat recovery rates were dictated by store demand.
The warm temperatures caused generally low heat demand for the unit during the period. A total of
18,447 kWhe electricity and 5,730 kWhth of thermal energy were generated over an operating period of
336 hours. All of the electricity and heat generated were used by the facility. Electrical, thermal, and
total system efficiencies during the extended period averaged 25.7, 8.0, and 33.7 percent, respectively,
and were consistent with the efficiencies measured during the controlled test period.
The average power generated over the extended period was 55.1 kWe and the average heat recovery rate
was 17.1 kWth (58.2 103Btu/hr). The power output trace shows several depressions where output dropped
below 54 kW to as low as 50 kW. Review of the data indicate that each of these decreases occurred
during afternoon hours when ambient temperatures were above 70 °F. The effect of ambient temperature
on power output is further illustrated in Figure 2-4. The figure clearly shows that power output decreases
as the ambient temperature (intake air) rises above 60 °F. This trend is consistent with industry
knowledge of turbine performance (i.e., electrical power output generally decreases with increasing
temperatures).
S8
56 -
54
££ ^9
'D
•& 5Q
0
<5 48
o
°- 46
44
49
40 4
•
Power Output (kW)
•* * ' : : -:\ • ' ;* • • '"-*
• • •>. . : •„ •-
• . -' : • • / . • '
. • : .'••/• H
- • . .: -.- •
. • • • / • • - •:
• _ ._•"•_ *•
b • %_ • •
• • • ^ .
•.••.•'.- jT
.-• '*
-' -"'. '
" Heat Reaovery Rate (103Btu/hr) ' . ' , ^_ • •
^a . ^^ • .. • • *^^""^~ ^'
- 200 -c-
.c
B
*j
OQ
CO
O
150 ^>
13
>.
0)
100 >
IUU g
o
4^
(0
-50 i
I n
Extended Monitoring Period (14 days)
Figure 2-3. Heat and Power Production During the Extended Monitoring Period (1-hour averages)
2-7
-------
59
SRI/USEPA-GHG-VR-27
September 2003
55
60 65 70 75
Ambient Temperature (°F)
80
85
Figure 2-4. Ambient Temperature Effects on Power Production During Extended Test Period
Figure 2-5 plots electrical efficiency over the extended monitoring period as a function of ambient
temperature and shows a linear relationship. Electrical efficiency ranged from 23.8 to 27.0 percent across
the temperature range of 50.5 to 83.7 °F. Thermal and total system efficiencies are better illustrated
during the control test periods in Figure 2-2 since heat demand was low throughout the period.
20
55
60
65 70 75
Ambient Temperature (°F)
80
85
Figure 2-5. Ambient Temperature Effects on Electrical Efficiency During Extended Test Period
2-S
-------
SRI/USEPA-GHG-VR-27
September 2003
2.2. POWER QUALITY PERFORMANCE
2.2.1. 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 illustrated in Figure 2-6 and summarized in Table 2-3. The average
electrical frequency measured was 60.000 Hz and the standard deviation was 0.014 Hz.
60.08
60.06
60.04
60.02
= 60.00
0)
3
gf 59.98
59.96
59.94
59.92
I ' W
H 1 1 h
H 1 h
Extended Monitoring Period (14 days)
Figure 2-6. Capstone 60 Frequency During Extended Test Period
Table 2-3. Electrical Frequency During Extended Period
Parameter
Average Frequency
Minimum Frequency
Maximum Frequency
Standard Deviation
Frequency (Hz)
60.000
59.946
60.057
0.014
2.2.2. Voltage Output
It is typically accepted that voltage output can vary within ± 10 percent of the standard voltage (480 volts)
without causing significant disturbances to the operation of most end-use equipment (ANSI 1996). The
7600 ION electric meter was configured to measure 0 to 600 VAC. The turbine was grid-connected and
operated as a voltage-folio wing current source. The voltage levels measured are, therefore, more
indicative of the grid voltage levels that the Capstone tried to respond to.
2-9
-------
SRI/USEPA-GHG-VR-27
September 2003
Figure 2-7 plots one-minute average voltage readings and Table 2-4 summarizes the statistical data for the
voltages measured on the turbine throughout the verification period. The voltage levels were well within
the normal accepted range of ± 10 percent.
520
515
Extended Monitoring Period (14 days)
Figure 2-7. Capstone 60 Voltage During Extended Test Period
Table 2-4. Capstone 60 Voltage During Extended Period
Parameter
Average Voltage
Minimum Voltage
Maximum Voltage
Standard Deviation
Volts
499.48
491.38
506.46
2.65
2.2.3. Power Factor
Figure 2-8 plots one-minute average power factor readings and Table 2-5 summarizes the statistical data
for power factors measured on the turbine throughout the verification period. Test results show that the
power factor was very stable throughout the period.
2-10
-------
SRI/USEPA-GHG-VR-27
September 2003
100.00
O
Q_
99.94
99.92
99.90
Extended Monitoring Period (14 days)
Figure 2-8. Capstone 60 Power Factor During Extended Test Period
Table 2-5. Power Factors During Extended Period
Parameter
Average Power Factor
Minimum Power Factor
Maximum Power Factor
Standard Deviation
%
99.98
99.96
99.99
0.006
2.2.4. Current and Voltage Total Harmonic Distortion
The turbine total harmonic distortion, up to the 63rd harmonic, was recorded for current and voltage
output using the 7600 ION. The average current and voltage THD were measured to be 5.66 percent and
1.98 percent, respectively (Table 2-6). Figure 2-9 plots the current and voltage THD throughout the 14-
day extended verification period. Results indicate that the average current THD exceeds the IEEE 519
specification of ± 5 percent. Figure 2-9 also shows numerous occurrences of current THD in excess of 7
percent.
Table 2-6. Capstone 60 THD During Extended Period
Parameter
Average
Minimum
Maximum
Standard Deviation
Current THD (%)
5.66
2.35
12.11
1.24
Voltage THD (%)
1.98
1.29
2.83
0.31
2-11
-------
SRI/USEPA-GHG-VR-27
September 2003
Q
I
Current THD
\
• .-- »•••• •• *
* .fr T , • .•
^^
Voltage THD
-I---I---I----1--1 --1---1- -4-- 4---!-- -I
Extended Monitoring Period (14 days)
Figure 2-9. Capstone 60 Current and Voltage THD During Extended Test Period
2.3. EMISSIONS PERFORMANCE
2.3.1. CHP System Stack Exhaust Emissions
CHP System emissions testing was conducted to determine emission rates for NOX, criteria pollutants
(CO and THC), and greenhouse gases (CO2 and CH/t). Stack emission measurements were conducted
during each of the controlled test periods summarized in Table 1-3. Three replicate test runs were
conducted at each operating condition each approximately 30 minutes in duration. All testing was
conducted in accordance with the EPA reference methods listed in Table 1-4. The CHP system was
maintained in a stable mode of operation during each test run using PTC-22 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, and THC. Emissions of CO2 are reported in units of volume percent.
These concentration and volume percent data were converted to mass emission rates using computed
exhaust stack flow rates following EPA Method 19 procedures 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 and
sampling system bias and drift checks. Results of the QA/QC checks are discussed in Section 3. The
2-12
-------
SRI/USEPA-GHG-VR-27
September 2003
results show that DQOs for all gas species met the reference method requirements. A complete summary
of emissions testing equipment calibration data is presented in Appendix A. Table 2-7 summarizes the
emission rates measured during each run and the overall average emissions for each set of tests.
NOX concentrations (corrected to 15-percent O2) averaged 3.09 ppmvd at full load, and increased to 6.56
ppmvd at the lowest load tested (setting of 15 kW). The overall average NOX emission rate at full load,
normalized to power output, was 0.000148 lb/kWhe. The data in Table 2-7 also show that changes in
operation of the heat-recovery unit did not significantly impact emissions of NOX or any of the other
pollutants evaluated. The benefits of lower NOX emissions from the CHP system are further enhanced
when exhaust heat is recovered and used. Annual published data by EIA reveal that the measured CHP
system emission rate is well below 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. The
emission reductions are further increased when transmission and distribution system losses are accounted
for.
2-13
-------
SRI/USEPA-GHG-VR-27
September 2003
Table 2-7. Canst
Run 1
Run 2
Run 3
AVG
Run 7
Run 8
Run 9
AVG
Run 10
Run 11
Run 12
AVG
Run 16
Run 17
Run 18
AVG
Run 4
Run 5
Run 6
AVG
Run 13
Run 14
Run 15
AVG
Site
Operations
Heat recovery maximized using continuous space heating
Low heat demand, heat exchanger
damper primarily open
8 ?
l|l 3
S. o a |
UJ Q. O O.
54.9
54.9
54.9
54.9
39.9
39.9
39.9
39.9
24.8
24.8
24.8
24.8
9.8
9.8
9.8
9.8
54.9
54.9
54.9
54.9
24.9
24.9
24.9
24.9
Exhaust
0, (%)
17.8
17.8
17.8
17.8
18.1
18.1
18.0
18.1
18.4
18.4
18.3
18.3
18.8
18.8
18.9
18.8
17.7
17.7
17.7
17.7
18.3
18.4
18.4
18.3
CO Emissions
(ppm at
15% 0,)
4.45
3.82
2.31
3.53
157
161
143
154
596
601
579
592
318
345
352
338
3.52
3.27
4.91
3.90
572
596
591
586
Ib/hr
7.14E-03
6.12E-03
3.70E-03
5.65E-03
0.197
0.205
0.180
0.194
0.565
0.570
0.548
0.561
1.81E-01
1.99E-01
2.01 E-01
1.94E-01
5.64E-03
5.25E-03
7.89E-03
6.26E-03
0.543
0.568
0.563
0.558
Ib/kWh .
1.30E-04
1.12E-04
6.74E-05
1.03E-04
4.93E-03
5.13E-03
4.51 E-03
4.86E-03
2.28E-02
2.30E-02
2.21 E-02
2.26E-02
1.85E-02
2.03E-02
2.06E-02
1.98E-02
1.03E-04
9.56E-05
1.44E-04
1.14E-04
2.19E-02
2.29E-02
2.26E-02
2.25E-02
one 60 CHP Svstem Emissions Durine Controlled Test Periods
NOX Emissions
(ppm at
15% 0,)
3.14
3.12
3.14
3.13
3.34
3.25
3.32
3.30
4.27
4.31
4.19
4.26
6.63
6.41
6.63
6.56
3.05
3.01
3.10
3.05
4.27
4.54
4.70
4.50
Ib/hr
8.26E-03
8. 12 E-03
8. 11 E-03
8.16E-03
6.89E-03
6.74E-03
6.89E-03
6.84E-03
6.66E-03
6.71 E-03
6.52 E-03
6.63E-03
6.21 E-03
6.09E-03
6.23E-03
6.18E-03
8.05E-03
7.96E-03
8.19E-03
8.07E-03
6.66E-03
7. 11 E-03
7.36E-03
7.04E-03
Ib/kWh .
1.50E-04
1.48E-04
1.48E-04
1.49E-04
1.73E-04
1.69E-04
1.73E-04
1.71E-04
2.69E-04
2.71 E-04
2.63E-04
2.67E-04
6.34E-04
6.22 E-04
6.36E-04
6.31 E-04
1.47E-04
1.45E-04
1.49E-04
1.47 E-04
2.68E-04
2.86E-04
2.96E-04
2.83E-04
THC Emissions
(ppm at
15% 0,)
1.20
1.19
0.789
1.06
75.8
74.7
60.5
70.3
1206
1229
1147
1194
288
345
347
327
0.782
0.712
0.560
0.685
1162
1155
1146
1154
Ib/hr
1.10E-03
1.09E-03
7.22 E-04
9.72E-04
5.42 E-02
5.39E-02
4.36E-02
5.06E-02
0.653
0.665
0.620
0.646
9.38E-02
1.14E-01
1.14E-01
1.07E-01
7.17E-04
6.54E-04
5.14E-04
6.28E-04
0.631
0.628
0.624
0.628
Ib/kWh .
2.01 E-05
1 .99E-05
1.32E-05
1.77E-05
1 .36E-03
1 .35E-03
1 .09E-03
1.27E-03
2.63E-02
2.68E-02
2.50E-02
2.61 E-02
9.58E-03
1.16E-02
1.16E-02
1.09E-02
1 .31 E-05
1.19E-05
9.37E-06
1.14E-05
2.54E-02
2.53E-02
2.51 E-02
2.53E-02
ChU Emissions
(ppm at
15%0,)
<0.955
<0.946
<0.939
<0.947
45.7
45.9
38.9
43.5
767
nd
676
721
nd
213
183
198
nd
nd
nd
nd
670
729
635
678
Ib/hr
<8.75E-04
<8.66E-04
<8.60E-04
<8.67E-04
3.27E-02
3. 31 E-02
2. 81 E-02
3.13E-02
0.415
nd
0.365
0.390
nd
7.04E-02
5.99E-02
6.51 E-02
nd
nd
nd
nd
0.364
0.397
0.345
0.369
Ib/kWh .
<1.59E-05
<1.58E-05
<1.57E-05
<1.58E-05
<8.20E-04
<8.28E-04
<7.04E-04
7.84E-04
<1.67E-02
nd
<1.47E-02
1.57E-02
nd
7.18E-03
6. 11 E-03
6.65E-03
nd
nd
nd
nd
1 .46E-02
1 .60E-02
1 .39E-02
1.48E-02
CO2 Emissions
%
1.76
1.78
1.78
1.77
1.55
1.56
1.58
1.56
1.36
1.35
1.34
1.35
1.11
1.10
1.11
1.11
1.77
1.74
1.74
1.75
1.33
1.34
1.35
1.34
Ib/hr
84.7
84.8
84.2
84.6
63.4
64.5
64.3
64.1
47.1
47.1
44.9
46.4
27.8
28.2
29.0
28.4
83.1
80.3
82.1
81.8
44.4
47.2
47.5
46.3
Ib/kWh .
1.54
1.55
1.53
1.54
1.59
1.62
1.61
1.61
1.90
1.90
1.81
1.87
2.84
2.88
2.96
2.89
1.51
1.46
1.50
1.49
1.79
1.90
1.91
1.87
nd: No data for these tests. Bag samples from Runs 1 1 and 16 were deflated upon arrival at laboratory. No samples were collected during Runs 4 through 5 because the real time THC concentrations were
less than 1 ppm.
2-14
-------
SRI/USEPA-GHG-VR-27
September 2003
Emissions of CO, THC, and QrU were all dramatically impacted by changes in power output. Table 2-7
shows that emissions of each pollutant were low at full load, but increased greatly as power output was
reduced. Emissions peaked at 50 percent of load (30 kW) and then decreased again at the lowest set-
point. The variation in emissions as power output changed was further illustrated during the emissions
profile test conducted at the conclusion of the controlled test periods. Results of the NOX, CO, and THC
emissions measured during the profile test are shown in Figure 2-10.
o
60 55 50 45 40 35 30 25
Power Output (kW)
20 15
•a
Q.
o
o
O
Figure 2-10. Capstone 60 Emissions as Function of Power Output
The profile test showed that emissions of each pollutant were variable and generally increased as power
output decreased. Emissions of CO and THC showed an inverse relationship to NOX emissions which is
typical with most combustion sources.
Concentrations of CO2 in the CHP system exhaust gas averaged 1.76 percent at full load and decreased as
power output was reduced to a low of 1.11 percent. These concentrations correspond to average CO2
emission rates of 1.54 lb/kWhe and 2.89 lb/kWhe, respectively. The CHP system CO2 emission rate at
full load is well below the average rate for coal-fired power plants in the U.S. (2.26 Ib/kWh) and slightly
higher than natural gas-fired power plants (1.41 Ib/kWh). Emissions of CO2 were also not significantly
affected by changes in operation of the heat-recovery unit.
2-15
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SRI/USEPA-GHG-VR-27
September 2003
2.3.2. Estimation of Annual Emission Reductions for Waldbaums
The electricity and heat generated by the CHP system will offset electricity supplied by the utility grid
and heat supplied by the Munters' gas-fired burners. Section 1.4.5 states that annual emission reductions
are estimated for the Waldbaums with two key assumptions: (1) all energy (power and heat) produced by
the CHP system is consumed on site and, (2) the unit will have a 98-percent availability rate.
Table 2-8 summarizes estimated NOX and CO2 emissions and emission reductions from on-site electricity
production. The table shows that electricity production under the CHP scenario results in annual NOX
emission reductions of 879 Ibs. The reductions are favorable for both ozone and non-ozone season
periods because the emission rate for the NY ISO is significantly higher than the emission rate for the
CHP. The CO2 emission rate for the NY ISO is similar to the emission rate for the CHP. CO2 emission
reductions are estimated to be small on a percentage basis (about 1 percent), but significant as an absolute
value. About 37,000 Ibs CO2 may be reduced annually.
CHP emission rates for on-site heat production are assigned as zero because emissions are accounted for
in electricity generation. In other words, the heat recovered is otherwise waste heat and no emissions are
associated with this process. Section 1.4.5 shows that approximately 394,513 kWh of energy from the
space-heating burner and 95,257 kWh of energy from the regeneration burner are eliminated. An annual
NOX reduction of 185 Ibs is estimated using the burner NOX emission factor of 0.000378 Ib/kWhth. An
annual CO2 emission reduction of 291,477s Ib may be realized through heat recovery and use using the
CO2 emission factors of 0.628 and 0.459 Ib/kWh for the two different burners.
Table 2-9 summarizes the annual emissions and emission reductions for both electrical and thermal
energy production systems. It is estimated that 17-percent reductions in NOX emissions may occur with
the CHP system compared to the baseline scenario. The highest reduction is due to the displacement of
emissions from the electric utility. An annual CO2 emission reduction of 8 percent may occur. Over 88
percent of these reductions (291,477 Ibs) are due to the displacement of emissions from on-site heat
recovery. In conclusion, DG systems operated in combined power and heat recovery mode results in the
most reductions in greenhouse gas emissions.
2-16
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SRI/USEPA-GHG-VR-27
September 2003
Table 2-8. Emissions Offsets From On-Site Electricity Production
NY ISO Emission Rates (lb/kWhe)
ozone wkday
ozone night/wkend
non-ozone wkday
non-ozone night/wkend
CHP System Emission Rates (lb/kWhe)
full load
NOX
0.0021
0.0028
0.0021
0.0028
NOX
0.000148
CO2
1.37
1.67
1.46
1.61
C02
1.52
Emission Reduction Estimates From Electricity Production
NOX
ozone season wkday
ozone season night/wkend
non-ozone season wkday
non-ozone season night/wkend
Annual Total
C02
ozone season wkday
ozone season night/wkend
non-ozone season wkday
non-ozone season night/wkend
Annual Total
Baseline Scenario
Electricity
From Grid
(kWhe)
512,033
567,093
565,006
616,416
2,260,548
512,033
567,093
565,006
616,416
2,260,548
Grid
Emissions
(Ibs)
1,159
1,712
1,279
1,861
6,011
756,201
1,020,915
889,252
1,069,839
3,736,207
CHP Scenario
Energy From CHP
Electricity
From CHP
(kWhe)
94,138
59,160
131,275
80,752
365,326
94,138
59,160
131,275
80,752
365,326
CHP
Emissions
(Ibs)
14
9
19
12
54
143,090
89,924
199,539
122,743
555,295
Makeup Energy
Electricity
From Grid
(kWhe)
417,894
507,933
433,731
535,664
1,895,222
417,894
507,933
433,731
535,664
1,895,222
Grid
Emissions
(Ibs)
946
1,533
982
1,617
5,078
617,172
914,411
682,641
929,687
3,143,911
Total
Emissions
(Ibs)
960
1,542
1,001
1,629
5,132
760,262
1,004,335
882,179
1,052,430
3,699,206
Emission
Reductions
(Ibs)
199
170
278
232
879
(4,061)
16,580
7,073
17,408
37,001
2-17
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SRI/USEPA-GHG-VR-27
September 2003
Table 2-9. Estimated Annual Emission Reductions using the CHP System at Waldbaums
Annual Total NOx Emissions
Annual Total CO2 Emissions
Baseline Scenario
Electricity
From Grid
fibs}
6,011
3,736,207
Heat from
Burners
fibs}
332
521,155
Total
Baseline
fibs}
6,343
4,257,362
CHP System Scenario
Enerev From CHP
Electricity
From CHP
fibs}
54
555,295
Heat/DHW
From CHP
fibs}
Makeup Energv
Electricity
From Grid
fibs}
5,078
3,143,911
Heat from
Burners
fibs}
147
229,678
Total CHP
Case
fibs}
5,279
3,928,884
Estimated
Reductions
fibs} f%}
1,064
328,478
17
8
2-18
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SRI/USEPA-GHG-VR-27
September 2003
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 and they are summarized in the Test Plan. 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%/0.90kW
±1.81%/0.51%c
±2.50% /8.75103Btu/hrc
±2.24%/1.07%c
±2.04%/1.38%c
±1.0%/0.56kW
±1.43%/0.37%c
±0.55/2.05 103Btu/hrc
±1.16%/0.61%c
±0.9%/0.71%c
Power Quality Performance
Electrical frequency (Hz)
Voltage
Power factor (%)
Voltage and current total harmonic distortion (THD)
(%)
±0.01% 70.006 Hz
1.01/1.21 Vc
±0.50%/0.50%
±1.00% 70.05%
± 0.01% / 0.006 Hz
1.01/4. 99 Vc
±0.50%/0.50%
±1.00%/0.05%
Emissions Performance
NOX concentration accuracy
CO concentration accuracy
O2 and CO2 concentration accuracy
THC and CH4 concentration accuracy
CO, NOX, and CO2 emission rates (Ib/kWh)
THC and CH4 emission rates (Ib/kWh)
±2.0%ofspand
±2.0%ofspand
±2.0%ofspand
±5.0%ofspand
± 5.59%c
±7.22%c
± 0.9% of span / 0.23 ppmvd
± 0.6% of span / 0. 1 5 ppmvd at full
load, ± 0.9% of span / 9.0 ppmvd at
reduced loads
±l.l%ofspan/0.1%C02
±0.6% of span/ 0.2% O2
± 2.4% of span/ 0.43 ppmvd at full
load, 12.0 ppmvd at reduced loads
±1.66%c
±2.69%c
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).
Determined by evaluating sampling system bias.
3-1
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SRI/USEPA-GHG-VR-27
September 2003
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
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.
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 the
six different load conditions. This completeness goal was achieved.
Completeness goals for the extended tests were to obtain 90 percent of 14 days of power quality, power
output, fuel input, and ambient measurements. This goal was exceeded—14 complete days of valid data
were collected (a total of 10 minutes of data were invalidated when the microturbine shut down
momentarily). These data were useful in establishing trends in power and heat performance capability at
varying ambient temperatures as discussed in Section 2.
Table 3-2 also includes accuracy goals for measurement instruments. Actual measurement accuracy
achieved are also reported based on instrument calibrations conducted by manufacturers, field
calibrations, reasonableness checks, and/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
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SRI/USEPA-GHG-VR-27
September 2003
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
Compressor
power draw
Inlet
Temperature
Outlet
Temperature
PG Flow
PG
Concentration
and Specific
Heat
Ambient
Temperature
Ambient
Pressure
Relative
Humidity
Instrument
Type/
Manufacturer
Electric Meter/
Power
Measurements
7600 ION
7500 ION
Controlotron
Model 1010EP
Onicon Model F-
1110 turbine
meter
GC/FID
RTD/Vaisala
Model HMD
60YO
Setra Model
280E
Vaisala Model
HMD 60 YO
Instrument
Range
0 to 100 kW
0 to 600 V
49 to 61 Hz
0 to 100A
0 to 100%
0 to 100%
0 to 100%
0 to 100 kW
37 to 356 °F
37 to 356 °F
1 to 80 gpm
PGConc: 0 to
100%
-50 to 150 °F
13.80 to 14.50
psia
0 to 100% RH
Range
Observed in
Field
14.4 to 59.9 kW
491 to 506V
59.95 to 60.06 Hz
40 to 71 A
1.3 to 2. 8%
2.4 to 12.1%
99.96 to 99.99%
3.9to4.1kW
97 to 198 °F
103 to 199 °F
40 to 55 gpm
PGConc: 25-26
%
51 to 84 °F
14.47 to 14.74
psia
31to98%RH
Accuracy a
Goal
± 1.50% reading*
± 1.01% reading
± 0.01% reading
± 1.01% reading
± 1% FSC
± 1% FS
± 0.5% reading
± 1.50% reading*
Temps must be ±
1.5°Fofref.
Thermocouples
± 1.0% reading
PG Cone: ± 3%
relative error
± 0.2 °F
± 0.1% FS
± 2%
Actual
± 1.50% reading"
± 1.01% reading
± 0.01% reading
± 1.01% reading
± 1% FS
± 1% FS
± 0.5% reading
± 1.50% reading*
± 0.4 °F for outlet,
± 0.5 °F for inlet
± 0.1% reading
PGConc: ±3.6%
relative (1.7%
absolute)
± 0.2 °F
± 0.05% FS
± 0.2%
How Verified /
Determined
Instrument calibration
from manufacturer
prior to testing
Independent check
with calibrated
thermocouple
Instrument calibration
from manufacturer
prior to testing
Independent check
with one blind sample
Instrument calibration
from manufacturer
prior to testing
Completeness
Goal
Controlled
tests: three
valid runs per
load meeting
PTC 22
criteria.
Extended
test: 90 % of
one- minute
readings for
14 days.
Actual
Controlled
tests: six
valid runs at
each load.
Extended
test: 99.9 %
of one-
minute
readings for
14 days.
(continued)
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SRI/USEPA-GHG-VR-27
September 2003
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
THC and CH4
levels
CO2 Levels
O2 Levels
Instrument Type /
Manufacturer
Mass Flow Meter /
Rosemount 3095 w/
1195 orifice
Rosemount Model
3095
RTD / Rosemount
Series 68
Gas Chromatograph
/HP 5890 11
Chemiluminescent/
TEI Model 42
NDIR / TEI Model
48
FID / TEI Model
51, HP 5890 for
CH4
NDIR / IR Model
703
NDIR / IR Model
2200
Instrument
Range
0 to 20 scfm
0 to 100 psia
-58 to 752 °F
0 to 100% CH4
0 to 25 ppmvd
0 to 25 ppmvd
full load, 0 to
1,000 ppmvd
reduced loads
Oto 18ppmvfull
load, 0 to 500
ppmvd reduced
loads
0 to 10%
0 to 25%
Measurement
Range
Observed
0 to 15 scfm
18 to 20 psia
50 to 100 °F
95 to 96% CH4
901to906Btu/ft3
1 to 3 ppmvd
1 to 3 ppmvd full
load, 70 to 257
ppmvd reduced
loads
0 to 2 ppmv full
load, 29 to 525
ppmvd reduced
loads
1.1 to 1.8%
17 to 19%
Accuracy
Goal
1.0% of
reading
± 0.75% FS
±0.10%
reading
±3.0%
accuracy, ±
0.2%
repeatability
0.1%
repeatability
± 2% FS or
± 2% FS or
± 5% FS or
± 2% FS or
± 2% FS or
Actual
± 1.0% of
reading
± 0.75% FS
± 0.09% reading
± 0.5% accuracy,
± 0.2%
repeatability
± 0.04%
repeatability
< 0.9% FS d
< 0.9% FS d
< 0.6% FS d
THC, ±2. 4%
CH4
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SRI/USEPA-GHG-VR-27
September 2003
3.2.1. Power Output
Instrumentation used to measure power was introduced in Section 1.0 and included a Power
Measurements Model 7600 ION. The data quality objective for power output is ± 1.5 percent of reading,
which is lower than the typical uncertainty set forth in PTC-22 of ± 1.8 percent. The power output DQO
was also applied to the ION 7500 power meter used to monitor gas compressor power consumption. The
Test Plan specified factory calibration of the ION meters 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 meters were factory calibrated by Power Measurements within one year of being used at the test site
(July 2002 for the 7600 ION and April 2003 for the 7500 ION). 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 and potential transformers, met the ± 1.5-
percent DQO. 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 ± 0.56 kW.
Additional QC checks were performed on the 7600 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 7600 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 7600 ION was installed and operating properly during the
verification test. The ± 1.50-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
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SRI/USEPA-GHG-VR-27
September 2003
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
Sensor diagnostics
Calibration with gas
standards by laboratory
Independent
performance check with
blind audit sample
Meter zero check
Independent
performance check of
temperature readings
When
Performed/Frequency
Beginning and end of test
Throughout test
Beginning and end of test
Prior to analysis of each
lot of samples submitted
One time during test
period
Prior to testing
Beginning of test period
Expected or Allowable
Result
Voltage and current checks
within ± 1% reading
Readings should be between
47 and 57 kW net power
output at full load
Pass
± 1 .0% for each gas
constituent
± 3.0% for each major gas
constituent
Reported heat recovery
< 0.1 gpm
Difference in temperature
readings should be < 1.5 °F
Results Achieved
± 0.03% voltage
± 0.0% current
Readings were 49 to 56 kW
Passed all diagnostic
checks
Results satisfactory, see
Section 3. 2. 2. 4
-0.06 gpm recorded
Temperature readings
within 0.4 °F of reference.
3.2.2. Electrical Efficiency
The DQO for electrical efficiency was to achieve an uncertainty of ± 1.8 percent at full electrical load or
less. This is consistent with the typical uncertainty levels set forth in PTC-22 of 1.7 percent. 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 and, in some cases, they
were exceeded. 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 7600 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 56 kW and the measurement error is
determined to be ± 0.56 kW.
3-6
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SRI/USEPA-GHG-VR-27
September 2003
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 orifice plate and the differential pressure sensors with a
NIST-traceable standard and through performing reasonableness checks in the field. The manufacturer
certifies an accuracy of ± 1 percent of reading if the pressure sensors and orifice bore specifications are
met. The specifications were satisfied in this case, and the ±1 percent of reading DQI was met. The
average flow rate at full load was 13.2 scfm and the measurement error is then determined to be ± 0.13
scfm. Complete documentation of data quality results for fuel flow rate is provided in Section 3.2.2.3.
The Test Plan specified using the results of duplicate analyses on at least two samples to reconcile the
accuracy of LHV determination. Duplicate analyses were conducted on two samples collected during the
load tests and a blind audit sample. The average LHV repeatability for the three duplicate analyses was
0.09 percent. As such, the LHV goal of ± 0.2 percent was met.
Results of the blind audit sample analysis indicated that methane results were within 0.51-percent relative
error of the certified concentration. The percent difference between the original and duplicate methane
analyses for the audit was ± 0.19 percent (Section 3.2.2.4). The average LHV during testing was verified
to be 903 Btu/ft3 and the measurement error corresponding to this heating value is ± 1.8 Btu/ft3. The heat
input compounded error then is:
Error in Heat Input = ^(flowmetererror) +(LHVerror) (Eqn. 8)
(0.002^ = 0.0102
The measurement error amounts to approximately ±730 Btu/hr, or 1.02 percent relative error at the
average measured heat input of 715.9 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 ± 1.02
percent relative. Therefore, compounded relative error for the electrical efficiency determination is:
Error in Elec. Power Efficiency = ^(powermetererror) + (heatinputerror) (Eqn. 9)
(0.0102)2 = 0.0143
Electrical efficiency for the controlled test periods at full load was 26.2 ± 0.37 percent, or a relative
compounded error of 1.43 percent.
3.2.2.1. PTC-22 Requirements for Electrical Efficiency Determination
PTC-22 guidelines state that efficiency determinations were to be performed within time intervals in
which maximum variability in key operational parameters did not exceed specified levels. This time
interval could be as brief as 4 minutes or as long as 30 minutes. Table 3-4 summarizes the maximum
permissible variations observed in power output, power factor, fuel flow rate, barometric pressure, and
ambient temperature during each test run. The table shows that the requirements for all parameters were
met for all test runs. Thus the PTC-22 requirements were met and the efficiency determinations are
representative of stable operating conditions.
3-7
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SRI/USEPA-GHG-VR-27
September 2003
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
Run 10
Run 11
Run 12
Run 13
Run 14
Run 15
Run 16
Run 17
Run 18
Maximum Observed Variation" in Measured Parameters
Power
Output (%)
±2
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.2
0.1
0.1
0.2
0.2
0.2
0.2
Power Factor
(%)
±2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Fuel Flow
Rate (%)
±2
0.6
0.6
0.7
0.7
0.7
0.6
0.7
0.8
0.7
0.7
1.1
1.1
0.9
0.8
0.9
1.0
1.1
1.5
Inlet Air
Press. (%)
±0.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.1
0.0
0.0
Inlet Air
Temp. (°F)
±4
0.4
0.4
0.2
0.2
0.4
0.1
0.5
1.1
1.4
0.8
0.2
0.9
1.9
2.1
1.2
3.0
0.9
1.1
a Maximum (Average of Test Run - Observed Value) / Average of Test Run * 1 00
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 pre-test
temperature and relative humidity sensor calibration had expired two months prior to the testing, so a
post-test calibration of the instrument was also performed. Both pre- and post-test factory calibrations
verified that the ± 2 °F accuracy goal for temperature and ± 2 percent accuracy goal for relative humidity
were met.
3.2.2.3. Fuel Flow Rate
The Test Plan specified the use of an integral orifice meter (Rosemount Model 3095) to measure the flow
of natural gas supplied to the CHP system. The two major components of the integral orifice meter (the
differential-pressure sensor and the orifice plate bore) were factory-calibrated prior to installation in the
field. Calibration records were reviewed to ensure that the ± 1.0-percent instrument accuracy goal was
satisfied. QC checks (sensor diagnostics) listed in Table 3-4 were conducted to ensure proper function in
the field.
Sensor diagnostic checks consisted of zero-flow verification by isolating the meter from the flow,
equalizing the pressure across the differential pressure (DP) sensors, and reading the pressure differential
and flow rate. The sensor output must read zero flow during these checks. Transmitter analog output
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September 2003
checks—known as the loop test—consist of checking a current of known amount from the sensor against
a Fluke multimeter to ensure that 4 mA and 20 mA signals are produced. These results were found to be
within ± 0.01 mA. Reasonableness checks revealed that measured flow rates were within the range
specified by the CHP Operator's Manual.
The Test Plan also specified that gas flow rates recorded by the Rosemount meter would be compared to
the site's rotary positive-displacement meter. Problems with the function of the facility meter prevented
this additional QC check. The site meter had very poor index resolution and was not pressure-
compensated. Therefore, a true flow-through comparison between meters was not conducted. The same
Rosemount meter (meter components include precision bore spool, orifice plate and housing, pressure
sensors, temperature sensor, and transmitter) was calibrated during a previous verification on a similar
microturbine in August 2002. During this test, a true flow-through comparison with a calibrated
displacement-type meter was performed [11]. The two meters were confirmed to agree be within ± 0.3
percent over the same range of gas flows as those experienced during this verification.
3.2.2.4. Fuel Lower Heating Value
Fuel gas samples were collected twice per day during the controlled test periods. Two additional samples
were collected during the extended monitoring period. Full documentation of 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 (ASTM 2001a) and D3588 (ASTM 2001b), 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 LHV duplicate analyses results. Both DQIs were met with
the methane accuracy at ± 0.51 percent and the LHV repeatability at ± 0.09 percent.
Results of analysis of the audit sample are summarized in Table 3-5 and show acceptable accuracy for all
major gas components.
Table 3-5. Results of Natural Gas Audit Sample Analysis
Gas
Component
Nitrogen
Carbon dioxide
Methane
Ethane
Propane
n-butane
Iso-butane
Iso-pentane
n-pentane
Certified
Component
Concentration
(%)
5.00
1.01
70.41
9.01
6.03
3.01
3.01
1.01
1.01
Analytical
Result for
Initial Analysis
(%)
5.17
1.00
70.05
9.06
6.07
3.03
2.99
1.02
1.01
Analytical
Result for
Initial Analysis
(%)
5.17
0.99
70.18
9.05
6.07
3.03
2.99
0.98
0.98
Combined
Sampling and
Analytical
Error (%)a
3.4
1.0
0.5
0.6
0.7
0.7
0.7
1.0
0.0
Analytical
Repeatability
(%)
0.0
1.0
0.2
0.1
0.0
0.0
0.0
3.9
3.0
a Calculated as: Error =(certified cone. - initial analytical result / certified cone.) * 100
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September 2003
Duplicate analyses, in addition to the blind audit samples, were conducted on two of the samples collected
during the control test periods (the sample collected during Runs 1 and 18). 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 0.07
percent for methane and 0.09 percent for LHV. The results demonstrate that the ± 0.2 percent LHV
accuracy goal was achieved.
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 PG fluid flow rate, fluid supply and return temperatures, fluid
composition, 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 Onicon Model F-l 110
turbine meter was used to continuously monitor PG fluid flow rate. This meter has a NIST-traceable
factory-calibrated accuracy of ± 0.1 percent of reading (the calibration was conducted on June 11, 2002).
This certification serves as the primary DQI. An additional field check on the meter included the GHG
Center comparing readings from the Onicon turbine meter to fluid flow readings generated by the GHG
Center's Controlotron ultrasonic meter. The two meters agreed within 0.2 percent of reading while
operating the CHP system at full load. A zero check was also performed on the turbine meter. The
turbine meter reading was -0.06 gpm with the CHP system shut down and the circulation pump off.
Tables 3-2 and 3-3 showed that the DQI for supply and return temperatures (delta T) was achieved. The
error in the fluid supply and return temperatures were 0.4 and 0.5 °F, respectively, for an overall delta T
uncertainty of 0.9 °F. This absolute error equates to a relative error of 0.5 percent at the highest average
fluid temperatures measured during the full-load testing. To address concerns regarding the amount of
insulation surrounding the GHG Center's surface-mounted RTDs, an additional QC check was conducted.
The facility uses a calibrated set of thermocouples immersed into thermowells in each glycol line to
monitor delta T. A total of 12 one-minute average delta T readings were recorded for the two sets of
temperature sensors to obtain delta T comparisons over a PG-supply temperature range of 104 to 183 °F.
The average absolute difference between the two RTD sets was 0.25 °F. This indicates that the thermal
paste used as a surface contact medium, along with the insulation that was used, was sufficient to provide
reliable delta T data.
The error in the glycol analysis was determined to be 3.6 percent based on results of the blind audit
sample. This analytical error translates to uncertainties in the fluid density and specific heat equal to 0.21
percent (see Test Plan Section 3.2.5). The 3.6 percent error exceeds the DQI goal of 3.0 percent, but the
composite error in heat recovery rate is still well within the DQO goal for that parameter.
The overall error in heat recovery rate is then the combined error in PG temperature, flow rate, and
compositional measurements. This error compounds multiplicatively as follows:
Overall Heat Meter Error = -^(Flow rate error) + (compositional error)2 + (temperature error) (Eqn. 10)
)2 +(0.0021)2 +(0.005)2 = 0.0055
The heat recovery rate determination, therefore, has a relative compounded error of ± 0.55 percent.
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September 2003
The errors in heat-recovery rate and heat input for the heat-recovery efficiency determination compound
similarly to Equation 10 as follows:
Error in Heat Recovery Efficiency = -J(o. 005 5)2 + (0.0102)2 = 0.0116 (Eqn. 11)
Average heat recovery rate (thermal) efficiency was 52.2 ± 0.61 percent, or a relative compounded error
of 1.16 percent for the full-load tests with maximized heat recovery. This compounded relative error
meets the data quality objective for this verification parameter.
3.2.4. Total Efficiency
Total efficiency is the sum of the electrical power and heat-recovery efficiencies. Total efficiency is
defined as 26.2 ± 0.37 percent (± 1.43-percent relative error) plus 52.2 ± 0.61 percent (± 1.16-percent
relative error). This is based on the determined errors in electrical and thermal efficiency at full load.
The absolute errors compound as follows:
c,abs
V2 2
err^ +err2 (Eqn. 12)
= -yO.372 + 0.612 = 0.71 -percent absolute error
Relative error, is:
,i = — (Eqn. 13)
Valuel + Value2
0.71
26.2 + 52.2
where:
= 0.91 -percent relative error
errC;abs = compounded error, absolute
err] = 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
The total efficiency with heat recovery maximized is then 78.4 ± 0.71 percent, or 0.9-percent relative
error. This compounded relative error meets the data quality objective for this parameter.
3.2.5. Exhaust Stack Emission Measurements
EPA reference methods were used to quantify emission rates of criteria pollutants and greenhouse gases.
The reference methods specify the sampling and calibration procedures and data quality checks that must
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September 2003
be followed to collect data that meets the methods required performance objectives. These methods
ensure that run-specific quantification of instrument and sampling system drift and bias occur throughout
the emissions tests. The DQOs specified in the Test Plan were based on an assessment of sampling
system error (bias) and calibration drift for each pollutant. Specifically, they are ± 2 percent for NOX,
CO, CO2, and O2 concentrations, and ± 5 percent for THC and Clr^ concentrations.
The Plan also specified DQOs for emission rates in units of Ib/kWh that were ± 5.59 percent for NOX,
CO, CO2, and ± 7.22 percent for THC and CH4. These composite error estimates were calculated using
statistical propagation of error formulae and the DQOs for the concentrations, flue gas O2 content, and
power output. Although these calculations are not statistically correct because the QC check
requirements substitute standard deviations in the formulae, they provide an estimate of the uncertainty of
the emission rate determinations.
NOx and THC Concentrations
The NOX and THC sampling system calibration error test was conducted prior to the start of each test run.
The calibration was conducted by sequentially introducing a suite of calibration gases into the sampling
system at the sampling probe and recording the system responses. Calibrations were conducted on all
analyzers using Protocol No. 1 calibration gases. The four calibration gas concentrations of NOX and
THC used were zero, 20 to 30 percent of span, 40 to 60 percent of span, and 80 to 90 percent of span.
The results of sampling system error tests are summarized in Appendix A. It should be noted that, at
reduced loads, the higher THC emissions required the analyst to use a higher instrument range of 1 to 500
ppm. The highest-concentration Protocol 1 calibration gas available on short notice was 150 ppm.
Measured concentrations exceeded this calibration level during all tests conducted at 50 and 25 percent of
load. The accuracy of the THC concentrations reported at reduced loads could be an issue even though
the instrument had excellent calibration linearity at the lower levels.
Table 3-2 shows that the maximum actual-measured error for NOX was ±0.9 percent of full scale (± 0.23
ppmvd), which indicates the goal was met. The maximum system error for THC was determined to be ±
0.6 percent of full scale (± 0.11 ppm at full load, ±3.0 ppm at reduced loads), which indicates the goal
was met for the higher load settings.
Zero- and mid-level calibration gases were again introduced to the sampling systems at the probe and the
response recorded at the conclusion of each test. System response was compared to the initial system
calibration error to determine sampling system drift. The maximum sampling system drift was
determined to be 0.16 ppmvd for NOX and 0.07 ppmvw for THC (3.0 ppmvw at reduced loads), which
were all below the method's maximum allowable drift. Sampling system calibration error and drift results
for all runs conducted during the verification are summarized in Appendix A.
An additional QC check was conducted on the NOX analyzer. The check consisted of determining NO2
converter efficiency prior to beginning of testing. This was done by introducing to the analyzer a mixture
of mid-level calibration gas and air. The analyzer response was recorded every minute for 30 minutes.
The response will be stable at the highest peak value observed if the NO2 to NO conversion is 100-percent
efficient. The converter is faulty and the analyzer must be either repaired or replaced prior to testing if
the response decreases by more than 2 percent from the peak value observed during the 30-minute test
period. Table 3-6 shows that the converter efficiency was measured to be 100 percent.
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September 2003
Table 3-6. Additional QA/QC Checks for Emissions Testing
Parameter
NOX
CO, C02,
O2
THC
QA/QC Check
NO2 converter
efficiency
Sampling system
drift checks
Analyzer calibration
error test
Calibration drift test
System calibration
drift test
When
Performed/Frequency
Once before testing
begins
Before and after each
test run
Daily before testing
After each test
After each test
Expected or
Allowable Result
98% efficiency or
greater
± 2% of analyzer
span or less
± 2% of analyzer
span or less
± 3% of analyzer
span or less
± 3% of analyzer
span or less
Maximum Results Measured3
100.0%
0.64% of span or 0. 16 ppmvd
CO: 0.6% of span or 0. 1 5 ppmvd at full
load, and 0.7% of span or 7.0 ppmvd at
reduced loads
CO2: 1.6% of span or 0.16% absolute
O2: 0.4% of span or 0. 1 % absolute
CO: 2.0% of span or 0.50 ppmvd at full
load, and 2.0% of span or 20.0 ppmvd at
reduced loads
CO2: 0.8% of span or 0.08% absolute
O2: 0.8% of span or 0.20% absolute
0.4% of span or 0.07 ppmvd at full load,
and 0.6% of span or 3.0 ppmvd at
reduced loads
a See Appendix A for individual test run results
CO. COZ. and O2
Analyzer calibrations were conducted to verify the error in CO, CO2, and O2 measurements relative to
calibration gas standards. The calibration error test was conducted at the beginning of each day of
controlled test periods. A suite of calibration gases were introduced directly to the analyzer and analyzer
responses were recorded. Three gases were used for CO2 and O2: (1) zero, (2) 40 to 60 percent of span,
and (3) 80 to 100 percent of span. Four gases were used for CO: (1) zero and approximately (2) 30, (3)
60, and (4) 90 percent of span. The analyzer calibration errors for all gases were below the allowable
levels, as shown in Table 3-7. It was necessary to operate the CO analyzer on a higher range during these
tests (0 to 1,000 ppm) similar to the THC testing problem encountered at the reduced loads. Two
additional Protocol 1 calibration gases were obtained that had concentration levels of 303 and 898 ppm.
A mid-level gas of around 600 ppm could not be procured to complete the calibration suite required by
the method. This is not believed to have any impact on the accuracy of the reported CO concentrations
because the instrument was linear throughout the range of operation and measured concentrations never
exceeded the 898-ppm level calibration gas.
Zero-and mid-level calibration gases were introduced to the sampling system at the probe and the
response was recorded before and after each test run. System bias was calculated by comparing the
system responses to the calibration error responses recorded earlier. Table 3-2 shows that the system bias
goal for all gases was achieved and, consequently, the DQO was satisfied. The pre- and post-test system
bias calibrations were also used to calculate sampling system drift for each pollutant and, as shown in
Table 3-7, the drift goals were also met for all pollutants.
Collected bag samples for CH4 were shipped to the laboratory for analysis. The laboratory reported that
all samples were received in good condition and with sufficient volume for analysis other than the
samples collected during Runs 11 and 16. These bags were deflated and, therefore, voided. The Test
Plan specified calibration of the GC/FID with a certified gas standard and duplicate analyses of each
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September 2003
sample as the means to evaluate accuracy. Instrument calibrations were properly performed, but the
duplicate analyses were conducted on only three of the samples due to incorrect analytical instructions on
the sample chain-of-custody form. Results of the duplicate analyses, shown in Table 3-2, indicate an
average analytical repeatability for CH4 of 2.4 percent, which meets the DQO. Another evaluation of
sampling and analytical error was conducted that uses a sample spike and recovery analysis for CH^. A
bag was spiked with a known concentration of methane and several other hydrocarbons and then analyzed
following the same instrumentation, procedures, and personnel as the samples. The results of this test
was 99.8 percent recovery for CH4.
Determination of Error in Emission Rate Determinations
Worst-case estimates of the uncertainty of the emission rate determinations were calculated from the
estimated maximum uncertainties for each of the contributing measurements (that is, pollutant
concentrations, O2 concentrations, and power output). The largest observed bias in the NOX, CO, and
CO2 measurements was 1.1 percent of full scale and the largest bias in the THC and QrU measurements
was 2.4 percent of full scale. The corresponding maximum observed bias in the O2 measurement was 0.6
percent of full scale. Based on the NIST-traceable factory calibration of the power meter, the estimated
uncertainty in the power output measurements was 1.0 percent. Using the propagation of error formulae
to combine these three estimates, the worst-case estimates in emission rate uncertainty are 1.7 percent for
the NOX, CO, and CO2, and 2.7 percent for THC and CH4. Both are well within the Test Plan DQO goals
of ± 5.59 percent for NOX, CO, and CO2, and ± 7.22 percent for THC and
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September 2003
4.0 TECHNICAL AND PERFORMANCE DATA SUPPLIED BY CDH ENERGY
Note: This section provides an opportunity for CDH Energy to provide additional comments concerning
the CHP System and its features not addressed elsewhere in the Report. The GHG Center has not
independently verified the statement made in this section.
This section compares the rated performance data from Capstone to the measured data presented in this
report. Capstone provides thermal performance data on page 44 of the Installation and Start-up Manual
(Part Number 511519-003). The measured performance data for the microturbine alone are compared to
the published data in Figures 4-1 and 4-2 below.
The measured efficiency and power data in figures below are slightly different than the values reported in
Section 2, which were net values that include the impact of parasitic loads such as the gas compressor and
pump. The efficiency data shown in Figure 4-1 are the 1-minute data records for Runs 1 through 6 when
the turbine provided the full rated output. The lines represent rated performance. The measured
efficiency is based on a measured LFfV of 903 Btu/ft3. The rated ISO conditions correspond to 59 °F at
sea level (a barometric pressure of 14.7 psia). The measured data were collected when the barometric
pressure was 14.52 psia. Therefore, the Capstone-recommended adjustment factor of 1.0% was applied to
the rated performance curves1 (shown as dotted lines on the plot). Figure 4-2 compares the measured and
rated turbine power output, with and without similar barometric pressure corrections applied.
Capstone states that the altitude adjustment for efficiency and power is 3% for each 1000 ft of altitude above sea level, or
5.76% for each 1 psia drop in barometric pressure. Therefore, (14.7 psia - 14.52 psia) x 5.76% is equivalent to a 1.0%
decrease in performance.
4-1
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SRI/USEPA-GHG-VR-27
September 2003
29.0
28.5
CD
'O
it
LU
CD
I
Q.
ro
O
28.0
27.5
27.0
*^mitW +
i&+
Recommended
Barometric Correction
Rating at ISO Conditions
52
54
56
58
60
Ambient Temperature (F)
Figure 4-1. Comparing Measured and Rated Efficiency for the Capstone C60 at Full Load
4-2
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SRI/USEPA-GHG-VR-27
September 2003
62
61
Q.
O
60
o
CL
"
Q.
ro
O
59
58
Rating at ISO Conditions
Recommended
Barometric Correction
50
55
60 65
Ambient Temperature (F)
70
75
Figure 4-2. Comparing Measured and Rated Power Output for the Capstone C60 at Full Load
The measured efficiency slightly exceeds the rated performance for the turbine after correcting for both
temperature and barometric pressure. The measured efficiency is 0.3-0.5% higher than expected based on
the Capstone performance curves.
The barometric correction does a good job of explaining the slightly lower power output of 59.5 kW
measured for the unit on that day. The measured power output is within 0.1-0.2 kW of the expected
output.
The thermal performance of the Capstone microturbine installed at this site is generally in line with
expectations. The emissions performance, summarized in Table 4-1, significantly exceed the published
expectations for the microturbine.
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September 2003
Table 4-1. Comparing Measured and Rated Emissions For Capstone C60 at Full Load.
Nitrogen Oxides - NOX (ppmv at 15% O2)
Carbon Monoxide - CO (ppmv at 15% O2)
Total Hydrocarbons - THC (ppmv at 15% O2)
Capstone Rated
Performance
<9
<40
<9
Measured
Performance
3.1
3.7
0.9
Note: Measured data are average of Runs 1-6.
4-4
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September 2003
5.0 REFERENCES
[1] American National Standards Institute, ANSI / Institute of Electrical and Electronics Engineers,
IEEE, Master Test Guide for Electrical Measurements in Power Circuits, ANSI/IEEE Std. 120-
1989, New York, NY. October. 1989.
[2] American National Standards Institute, ANSI / Institute of Electrical and Electronics Engineers,
IEEE, Recommended Practices and Requirements for Harmonic Control in Electrical Power
Systems, IEEE Std. 519-1992, New York, NY. April. 1993.
[3] American National Standards Institute, ANSI / Institute of Electrical and Electronics Engineers,
National Standards for Electric Power Systems and Equipment - Voltage Ratings (Hertz), ANSI
C84.1-1995. American National Standards Institute, National Electrical Manufacturers
Association, Rosslyn, VA. 1996.
[4] American National Standards Institute / American Society of Heating, Refrigeration, and Air-
conditioning Engineers, Method of Testing Thermal Energy Meters for Liquid Streams in HVAC
Systems, ANSI/ASHRAE 125-1992, Atlanta, GA. 1995.
[5] American Society of Mechanical Engineers, Performance Test Code for Gas Turbines, ASTM
PTC-22, New York, NY. 1997.
[6] American Society of Heating, Refrigeration, and Air-conditioning Engineers. Physical
Properties of Secondary Coolants (Brines), F201P, Chapter 20, ASHRAE 1997, Atlanta, GA.
1997.
[7] American Society for Testing and Materials, Standard Test Method for Analysis of Natural Gas
by Gas Chromatography, ASTM D1945-98, West Conshohocken, PA. 2001.
[8] American Society for Testing and Materials, Standard Practice for Calculating Heat Value,
Compressibility factor, and Relative Density of Gaseous Fuels, ASTM D3588-98. West
Conshohocken. PA. 2001.
[9] Ozone Transport Commission. The OTC Emission Reduction Workbook 2.1: Description and
User's Manual, OTC 2002, Washington, D.C. November 2002.
[10] Southern Research Institute, Test and Quality Assurance Plan for the Combined Heat and Power
at a Commercial Supermarket, Capstone 60 kWMicroTurbine System, SRI/USEPA-GHG-QAP-
27, www.sri-rtp.com. Greenhouse Gas Technology Center, Southern Research Institute, Research
Triangle Park, NC. November 2002.
[11] Southern Research Institute, Environmental Technology Verification Report for the Ingersoll-
Rand Energy Systems IR PowerWork™ 70 kWMicroturbine System, SRI/USEPA-GHG-QAP-
21, www.sri-rtp.com. Greenhouse Gas Technology Center, Southern Research Institute, Research
Triangle Park, NC. April 2003.
[12] U.S. Environmental Protection Agency, Code of Federal Regulations, Title 40, Part 60, New
Source Performance Standards, Appendix A, U.S. EPA, Washington, DC, 1999.
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[13] U.S. Environmental Protection Agency, Compilation of Air Pollutant Emission Factors, AP-42,
Fifth Edition, Volume 1. Stationary Point and Area Sources, U.S. EPA, Washington, DC, 1999.
[14] CDH Energy Corporation, Waldbaums CHP Demonstration Data Summary - June 2003, CDH
Energy Corp., Cazenovia, NY 2003.
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September 2003
APPENDIX A
Emissions Testing QA/QC Results
Appendix A-1. Summary of Daily Reference Method Calibration Error Determinations A-2
Appendix A-2. Summary of Reference Method System Bias and Drift Checks A-3
Appendix A-l presents instrument calibration error and linearity checks for each of the analyzers used for
emissions testing. These calibrations are conducted once at the beginning of each day of testing and after
any changes or adjustments to the sampling system are conducted (changing analyzer range, for example).
All of the calibration error results are within the specifications of the reference methods.
Appendix A-2 summarizes the system bias and drift checks conducted on the sampling system for each
pollutant quantified. These system calibrations are conducted before and after each test run. Results of
all of the calibrations are within the specifications of the reference methods.
A-l
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September 2003
Appendix A-l. Summary of Daily Reference Method Calibration Error Determinations
Measurement Cal Gas
Range Value
Date Gas (ppm for NO*. CO. and
6/4/03 NOx 25 0.00
(Runs 1 - 6) 6.26
12.09
24.10
CO 25 0.00
6.04
13.30
24.36
C02 10 0.00
4.45
9.23
02 25 0.00
11.18
21.70
THC 18 0.00
3.07
7.76
15.89
Analyzer
Response
THC: % for C? and
0.04
6.22
12.19
23.80
0.01
6.07
13.42
24.21
0.16
4.45
9.25
0.03
11.17
21.75
0.02
3.11
7.76
15.91
Absolute
Difference
CO>)
0.04
0.04
0.10
0.30
0.01
0.03
0.12
0.15
0.16
0.00
0.02
0.03
0.01
0.05
0.02
0.04
0.00
0.02
Calibration
Error (% of Span)*
0.16
0.16
0.40
1.20
0.04
0.12
0.48
0.60
1.60
0.00
0.20
0.12
0.04
0.20
0.11
0.22
0.00
0.11
A-2
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Appendix A-l. Summary of Daily Reference Method Calibration Error Determinations
(Continued)
Measurement Cal Gas
Range Value
Date Gas (ppm for NOX, CO, and
6/5/03 NOX 25 0.00
(Runs 7 -18) 6.26
12.09
24.10
CO 1000 0.00
303.00
898.00
CO2 10 0.00
4.45
9.23
O2 25 0.00
11.18
21.70
THC 18 0.00
3.07
7.76
15.89
THC 500 0.00
15.89
150.00
Analyzer
Response
THC; % for O2 and
0.01
6.24
12.01
24.32
0.96
303.30
893.00
0.13
4.46
9.21
0.02
11.20
21.73
0.02
3.11
7.76
15.91
-1.3
14.5
149.9
Absolute
Difference
C02)
0.01
0.02
0.08
0.22
0.96
0.30
5.00
0.13
0.01
0.02
0.02
0.02
0.03
0.02
0.04
0.00
0.02
1.30
1.39
0.10
Calibration
Error (% of Span)*
0.04
0.08
0.32
0.88
0.10
0.03
0.50
1.30
0.10
0.20
0.08
0.08
0.12
0.11
0.22
0.00
0.11
0.26
0.28
0.02
Allowable calibration error is 2% span.
A-3
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SRI/USEPA-GHG-VR-27
September 2003
Appendix A-l. Summary of Daily Reference Method Calibration Error Determinations
(Continued)
Measurement Cal Gas Analyzer Absolute
Range Value Response Difference Calibration
Date Gas (ppm for NOX, CO, and THC; % for O2 and CO2) Error (% of Span)*
6/6/03 NOX 25 0.00 -0.04 0.04 0.16
(Profile 6.26 6.12 0.14 0.56
Test) 12.09 12.23 0.14 0.56
0.84
CO 1000 0.00 -1.70 1.70 0.17
0.50
0.70
C02 10 0.00 0.03 0.03 0.30
0.10
0.20
0.08
0.36
0.12
THC 500 0.00 -2.1 2.10 0.42
0.42
0.34
0.10
Allowable calibration error is 2% span.
25
1000
10
25
500
0.00
6.26
12.09
24.10
0.00
303.00
898.00
0.00
4.45
9.23
0.00
11.18
21.70
0.00
7.76
15.89
150.00
-0.04
6.12
12.23
24.31
-1.70
298.00
891 .00
0.03
4.46
9.25
0.02
11.27
21.73
-2.1
5.68
14.21
149.5
0.04
0.14
0.14
0.21
1.70
5.00
7.00
0.03
0.01
0.02
0.02
0.09
0.03
2.10
2.08
1.68
0.50
A-4
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SRI/USEPA-GHG-VR-27
September 2003
Appendix A-2. Summary of Reference Method System Bias and Drift Checks
Analyzer Spans: NOX = 25, CO = 10, THC = 18 ppm, CO2 = 10%, O2 = 25%
NOX Zero System Response (ppm)
0.04 System Bias (% span)
Drift (% span)
NOX Mid System Response (ppm)
6.22 System Bias (% span)
Drift (% span)
CO Zero System Response (ppm)
0.01 System Bias (% span)
Drift (% span)
CO Mid System Response (ppm)
6.07 System Bias (% span)
Drift (% span)
CO2 Zero System Response (ppm)
0.16 System Bias (% span)
Drift (% span)
CO2 Mid System Response (ppm)
4.45 System Bias (% span)
Drift (% span)
O2Zero System Response (ppm)
0.03 System Bias (% span)
Drift (% span)
O2 Mid System Response (ppm)
11.17 System Bias (% span)
Drift (% span)
THC Zero System Response (ppm)
0.02 System Bias (% span)
Drift (% span)
THC Mid System Response (ppm)
3.11 System Bias (% span)
Drift (% span)
Initial
Cal
0.04
0.00
na
6.22
0.00
na
-0.01
-0.08
na
6.19
0.48
na
0.16
0.00
na
4.41
-0.40
na
0.25
0.88
na
11.22
0.20
na
-0.04
-0.33
na
3.12
0.06
na
Run Number
1
-0.03
-0.28
0.28
6.17
-0.20
0.20
-0.11
-0.48
1.00
5.99
-0.32
2.00
0.09
-0.70
0.70
4.41
-0.40
0.00
0.04
0.04
0.84
11.15
-0.08
0.28
0.01
-0.06
0.28
3.19
0.44
0.39
2
-0.01
-0.20
0.08
6.17
-0.20
0.00
-0.13
-0.56
0.20
6.10
0.12
1.10
0.07
-0.90
0.20
4.43
-0.20
0.20
0.02
-0.04
0.08
11.18
0.04
0.12
0.04
0.11
0.17
3.09
-0.11
0.56
3
-0.03
-0.28
0.08
6.19
-0.12
0.08
-0.09
-0.40
0.40
5.99
-0.32
1.10
0.07
-0.90
0.00
4.39
-0.60
0.40
0.01
-0.08
0.04
11.15
-0.08
0.12
0.02
0.00
0.11
3.08
-0.17
0.06
4
-0.04
-0.32
0.04
6.18
-0.16
0.04
-0.13
-0.56
0.40
6.10
0.12
1.10
0.07
-0.90
0.00
4.47
0.20
0.80
0.02
-0.04
0.04
11.25
0.32
0.40
0.03
0.06
0.06
3.12
0.06
0.22
5
-0.03
-0.28
0.04
6.11
-0.44
0.28
-0.12
-0.52
0.10
6.13
0.24
0.30
0.12
-0.40
0.50
4.47
0.20
0.00
0.05
0.08
0.12
11.22
0.20
0.12
0.01
-0.06
0.11
3.18
0.39
0.33
6
-0.04
-0.32
0.04
6.20
-0.08
0.36
0.02
0.04
1.40
6.11
0.16
0.20
0.11
-0.50
0.10
4.40
-0.50
0.70
0.02
-0.04
0.12
11.16
-0.04
0.24
0.02
0.00
0.06
3.10
-0.06
0.44
Allowable system bias is 5% span, allowable drift is 3% span.
A-5
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SRI/USEPA-GHG-VR-27
September 2003
Appendix A-2. Summary of Reference Method System Bias and Drift Checks (Continued)
Analyzer Spans: NOX = 25, CO = 1000, THC = 500 ppm, CO2 = 10%, O2 = 25%
NOX Zero System Response (ppm)
0.01 System Bias (% span)
Drift (% span)
NOX Mid System Response (ppm)
6.24 System Bias (% span)
Drift (% span)
CO Zero System Response (ppm)
0.96 System Bias (% span)
Drift (% span)
CO Mid System Response (ppm)
303.30 System Bias (% span)
Drift (% span)
CO2 Zero System Response (ppm)
0.13 System Bias (% span)
Drift (% span)
CO2 Mid System Response (ppm)
4.46 System Bias (% span)
Drift (% span)
O2 Zero System Response (ppm)
0.02 System Bias (% span)
Drift (% span)
O2 Mid System Response (ppm)
11.20 System Bias (% span)
Drift (% span)
THC Zero System Response (ppm)
0.02 System Bias (% span)
Drift (% span)
THC Mid System Response (ppm)
7.76 System Bias (% span)
149.90 Drift (% span)
Initial
Cal
-0.04
-0.20
na
6.18
-0.24
na
-1.31
-0.23
na
300.37
-0.29
na
0.10
-0.30
na
4.48
0.20
na
-0.02
-0.16
na
11.13
-0.28
na
-0.01
-0.01
na
7.85
0.02
na
Run Number
7
-0.01
-0.08
0.12
6.19
-0.20
0.04
-1.44
-0.24
0.01
296.04
-0.73
0.43
0.10
-0.30
0.00
4.43
-0.30
0.50
0.03
0.04
0.20
11.06
-0.56
0.28
-0.01
-0.01
0.00
7.76
0.00
0.02
8
0.03
0.08
0.16
6.03
-0.84
0.64
-0.56
-0.15
0.09
297.93
-0.54
0.19
0.09
-0.40
0.10
4.43
-0.30
0.00
0.01
-0.04
0.08
11.11
-0.36
0.20
-0.05
-0.01
0.01
7.76
0.00
0.00
9
-0.01
-0.08
0.16
6.01
-0.92
0.08
-0.24
-0.12
0.03
297.82
-0.55
0.01
0.07
-0.60
0.20
4.37
-0.90
0.60
0.01
-0.04
0.00
11.09
-0.44
0.08
0.01
0.00
0.01
7.78
0.00
0.00
10
0.02
0.04
0.12
6.07
-0.68
0.24
-0.49
-0.15
0.03
298.66
-0.46
0.08
0.07
-0.60
0.00
4.39
-0.70
0.20
0.02
0.00
0.04
11.11
-0.36
0.08
-1.77
-0.36
na
152.70
0.56
na
11
0.01
0.00
0.04
6.08
-0.64
0.04
-0.44
-0.14
0.01
296.20
-0.71
0.25
0.07
-0.60
0.00
4.39
-0.70
0.00
0.04
0.08
0.08
11.09
-0.44
0.08
-1.66
-0.34
0.02
153.10
0.64
0.08
12
0.02
0.04
0.04
6.09
-0.60
0.04
-0.31
-0.13
0.01
295.79
-0.75
0.04
0.09
-0.40
0.20
4.38
-0.80
0.10
-0.01
-0.12
0.20
11.11
-0.36
0.08
-1.97
-0.40
0.06
150.82
0.18
0.46
13
0.04
0.12
0.08
6.11
-0.52
0.08
-1.39
-0.24
0.11
294.89
-0.84
0.09
0.09
-0.40
0.00
4.39
-0.70
0.10
-0.01
-0.12
0.00
11.08
-0.48
0.12
-2.21
-0.45
0.05
150.09
0.04
0.15
14
0.01
0.00
0.12
6.13
-0.44
0.08
-0.28
-0.12
0.11
294.91
-0.84
0.00
0.08
-0.50
0.10
4.37
-0.90
0.20
0.01
-0.04
0.08
11.08
-0.48
0.00
-2.10
-0.42
0.02
147.12
-0.56
0.59
15
0.00
-0.04
0.04
6.13
-0.44
0.00
-0.77
-0.17
0.05
296.25
-0.71
0.13
0.09
-0.40
0.10
4.33
-1.30
0.40
0.01
-0.04
0.00
11.07
-0.52
0.04
-1.98
-0.40
0.02
148.65
-0.25
0.31
16
0.02
0.04
0.08
6.14
-0.40
0.04
-0.81
-0.18
0.00
294.60
-0.87
0.16
0.12
-0.10
0.30
4.36
-1.00
0.30
0.00
-0.08
0.04
11.14
-0.24
0.28
-2.03
-0.41
0.01
148.87
-0.21
0.04
17
0.07
0.24
0.20
6.14
-0.40
0.00
-0.77
-0.17
0.00
296.80
-0.65
0.22
0.08
-0.50
0.40
4.40
-0.60
0.40
0.01
-0.04
0.04
11.07
-0.52
0.28
-2.13
-0.43
0.02
151.95
0.41
0.62
18
0.03
0.08
0.16
6.16
-0.32
0.08
-0.44
-0.14
0.03
296.89
-0.64
0.01
0.12
-0.10
0.40
4.35
-1.10
0.50
0.03
0.04
0.08
11.09
-0.44
0.08
-1.92
-0.39
0.04
150.87
0.19
0.22
Allowable system bias is 5% span, allowable drift is 3% span.
A-6
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SRI/USEPA-GHG-VR-27
September 2003
Appendix A-2. Summary of Reference Method System Bias and Drift Checks (Continued)
Analyzer Spans: NOX = 25, CO = 1000, THC = 500 ppm, CO2 = 10%, O2 = 25%
NOX Zero System Response (ppm)
-0.04 System Bias (% span)
Drift (% span)
NOX Mid System Response (ppm)
6.12 System Bias (% span)
Drift (% span)
CO Zero System Response (ppm)
-1.70 System Bias (% span)
Drift (% span)
CO Mid System Response (ppm)
298.00 System Bias (% span)
Drift (% span)
CO2 Zero System Response (ppm)
0.03 System Bias (% span)
Drift (% span)
CO2 Mid System Response (ppm)
4.46 System Bias (% span)
Drift (% span)
O2 Zero System Response (ppm)
0.02 System Bias (% span)
Drift (% span)
O2 Mid System Response (ppm)
11.27 System Bias (% span)
Drift (% span)
THC Zero System Response (ppm)
-2.10 System Bias (% span)
Drift (% span)
THC Mid System Response (ppm)
149.50 System Bias (% span)
Drift (% span)
Initial
Cal
-0.04
0.00
na
6.13
0.04
na
-0.42
0.13
na
298.02
0.00
na
0.07
0.40
na
4.40
-0.60
na
0.06
0.16
na
11.20
-0.28
na
-2.11
0.00
na
149.52
0.00
na
Profile
Test
-0.02
0.08
0.08
6.07
-0.20
0.24
-1.58
0.01
0.12
298.69
0.07
0.07
0.04
0.10
0.30
4.38
-0.80
0.20
0.08
0.24
0.08
11.19
-0.32
0.04
-2.63
-0.11
0.10
149.01
-0.10
0.10
Allowable system bias is 5% span, allowable drift is 3% span.
A-7
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SRI/USEPA-GHG-VR-27
September 2003
APPENDIX B-l
Estimation of Regional Grid Emissions
EPA has long recognized that clean energy technologies have the potential for significant emission
reductions through displaced generation. However, a robust and analytically sound method to quantify
the potential of displaced emissions has yet to be developed. Displaced generation is defined as the total
electrical output (measured in kWh) from conventional electricity sources that is either displaced by or
avoided through the implementation of energy-efficient measures. Displaced emissions is defined as the
change in emissions (measured in Ib) that results when conventional electrical generation is displaced by
energy-efficient measures. On-site power generation with a distributed energy technology is an example
of a clean energy source, provided its emissions are less than conventional sources. DG-CHP systems can
result in displaced generation and ultimately displace emissions.
Several different methods have been developed and employed by various organizations to estimate
emissions displaced by on-site electricity generation. There are many variations of such methodologies
and they are all derived from the average emission rate method—the marginal unit method—or historical
emissions-generation data.
• The average emission rate method uses the average emission rate of electricity
generating units in a particular region or nationally. It is usually based on the
average emission characteristics of all electricity-generating units or fossil-fired units
only. It is often derived from historic generation and emissions data or projections of
future generation and fuel use patterns. This approach is most widely used due to its
simplicity and wide availability of average rates for many U.S. regions.
Unfortunately, there is little or no correlation between the average emission rate and
the emission rate at which the emissions are displaced by energy-efficient measures.
The result is that estimates of emissions impacts can be inaccurate and may not
adequately reflect the realities of power markets.
• The marginal-unit method is an attempt to improve on the average emission rate
approach by identifying a particular unit or type of unit that may be displaced.
Similar to the average emission rate method, the average emission characteristics of
the displaced units are applied to total electricity saved to estimate displaced
emissions. The marginal unit method assumes that at any point in time the marginal
unit, by virtue of being the most expensive generating unit to operate, will be the unit
that is displaced. Although this approach conceptually appears to be more reasonable
than simply using an average emission rate, identifying the marginal unit is difficult,
particularly in regions with large and frequent variations in hourly electricity
demand.
B-l
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SRI/USEPA-GHG-VR-27
September 2003
• Displaced emissions are also estimated using statistical techniques based on historical
data. This approach seeks to forecast how displaced emissions arise from observed
changes in electricity demand/supply instead of identifying the average or marginal
emission rate of particular units. This approach requires statistical modeling, and
data such as regional generation, emissions, and electricity demand. Its primary
limitation is that actual site-specific and electricity control area specific data must be
available.
EPA has been developing a newer approach that utilizes region/time specific parameters to represent
average displaced emission rate (ADER). The ADER methodology accounts for the complexities of
electricity markets in assessing how displaced emissions result from changes in electric demand or supply
and produces regional, national, short-term, and long-term estimates of displaced emissions of CO2, NOX,
SO2, and mercury (Hg) from electric generation. The results of the ADER analysis are not yet available;
as such, the GHG Center is unable to apply this methodology for this verification. However, at the
suggestion of the EPA project officer leading this effort, a similar approach developed by the Ozone
Transport Commission (OTC), has been adopted for this verification to estimate displaced emissions and
is described below.
OTC is a multi-state organization focused on developing regional solutions to the ground-level ozone
problem in the Northeast and Mid-Atlantic region of the U.S. with special emphasis on the regional
transport of ground-level ozone and other related pollutants. OTC was created by Congress in 1990 and
consists of the jurisdictions within Connecticut, Delaware, D.C., Maine, Maryland, Massachusetts, New
Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Vermont, and Virginia. OTC has
recently developed an Emission Reduction Workbook (workbook) to provide a method of assessing the
emissions impacts of a range of energy policies affecting the electric industry [9]. The geographic focus
of the workbook is the three northeastern electricity control areas: Pennsylvania/New Jersey /Maryland
(PJM), the New York Independent System Operator (NY ISO), and Independent System Operator of New
England (ISO NE).
The three energy programs evaluated by the workbook are programs that (1) displace generation (e.g.,
DG-CHP systems), (2) alter the average emission rate of the electricity used in a state or region (e.g.,
emissions performance standard), and (3) reduce emission rates of specific generating units (e.g., multi-
pollutant regulations applied to existing generating units). The Workbook contains default displaced
emission rates for the three northeastern control areas to evaluate these programs. The default displaced
emission rates are divided into three time periods: near-term (2002-2005), medium-term (2006-2010),
and long-term (201 1-2020). The short-term default emission rates for the NY ISO control area have been
used to represent the ERodd variable shown in Equation 8 for this verification.
The near-term rates for the NY ISO are summarized in Table B-l. These rates were compiled using the
PROSYM electricity dispatch model and are reported to be representative of actual operations because the
identity of generating units that constitute each regional power system are known with a relatively high
level of certainty.
B-2
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SRI/USEPA-GHG-VR-27
September 2003
Table B-l. Displaced Emission Rates For the
(2002)
Ozone season weekday a
Ozone season night/weekend b
Non-ozone season weekday °
Non-ozone season night/weekend d
NOx (lb/kWhe)
0.0021
0.0028
0.0021
0.0028
NY ISO
CO2 (lb/kWhe)
1.37
1.67
1.46
1.61
a Average of all hourly marginal emission rates during weekdays, May through September,
7:00 am through 10:59 pm
b Average of all hourly marginal emission rates during all nights, May through September,
1 1 :00 pm through 6:59 am, and all weekend days during this period
0 Average of all hourly marginal emission rates during weekdays, October through April, 7:00
am through 10:59 pm
d Average of all hourly marginal emission rates during all nights, October through April,
1 1 :00 pm through 6:59 am, and all weekend days during this period
PROSYM is a chronological, multi-area electricity market simulation model that is often used to forecast
electricity market prices, analyze market power, quantify production cost and fuel requirements, and
estimate air emissions. It simulates system operation on an hourly basis by dispatching generating units
each hour to meet load. The simulation is based on unit-specific information on the generating units in
multiple interconnection areas (unit type and size, fuel type, heat-rate curve, emission and outage rates,
and operating limitations) and on detailed data on power flows and transmission constraints within and
between ISOs. Actual constraints on system operation (such as unit-ramp times and minimum up and
down times) are taken into account because the simulation is done in chronological order. The resulting
emission rates in one control region take into account emission changes in neighboring regions.
PROSYM has been used by many organizations, including the EPA and Department of Justice, to pursue
New Source Review violations and by DOE, numerous utility companies, Federal Energy Regulatory
Commission (FERC), and the Powering the South organization to simulate the electric power system in
the Southern U.S.
OTC generated the displaced emission rates for the Northeast control areas by first performing a "base
case" model run simulating plant dispatch across all three control areas for the year. OTC then performed
three "decrement" model runs. In one decrement run, all hourly loads in PJM were reduced by 1 percent;
loads in ISO NE and NY ISO were not reduced. In another decrement run, loads in ISO NE were reduced
by 1 percent and in the third, NY ISO loads were reduced. The total difference in kWhs generated
between the base case and decrement case and the total difference in emissions was calculated and the
emissions were divided by kWhs to derive the marginal emission rate for the time period OTC calculated
marginal emission rates for different periods. Marginal rates shown in Table B-l takes into account
changes in generation in all areas resulting from the load reductions in the target DG-CHP use area. This
includes analysis of emissions changes across six interconnected control areas: PJM, NY ISO, ISO NE,
Canada's Maritime Provinces, Ontario, and Quebec.
B-3
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SRI/USEPA-GHG-VR-27
September 2003
B-4
------- |