SRI/USEPA-GHG-VR-21
April 2003
Environmental
Technology
Verification Report
Ingersoll-Rand Energy Systems
IR PowerWorks™
70 kW Microturbine System
Prepared by:
Greenhouse Gas Technology Center
Southern Research Institute
Under a Cooperative Agreement With
U.S. Environmental Protection Agency
and
Under Agreement With
IW5HiI1A New York State Energy Research and Development Authority
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EPA REVIEW NOTICE
This report has been peer and administratively reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Mention of trade names or commercial products does not constitute endorsement or
recommendation for use.
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SRI/USEPA-VS-GHG-VR-21
April 2003
THE ENVIRONMENTAL TECHNOLOGY VERIFICATION PROGRAM
SB*
IW5ERDA
SOUTHERN RESEARCH
U.S. Environmental Protection Agency 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: IR Power Works™ 70 kW Microturbine System
COMPANY: Ingersoll-Rand Energy Systems
ADDRESS: 30 New Hampshire Ave., Portsmouth, NH 03801
E-MAIL: powerworks@irco.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 substantially 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 the IR PowerWorks™ 70 kW
Microturbine System offered by Ingersoll-Rand Energy Systems. This verification statement provides a
summary of the test results for the IR PowerWorks System.
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April 2003
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 IR PowerWorks System is one
of the first cogeneration installations that integrates microturbine technology with a heat recovery system.
The following description of the IR PowerWorks System was provided by the vendor and does not
represent verified information.
Electric power is generated with an integrated Ingersoll-Rand microturbine with a nominal power output of
70 kW (59 °F, sea level). The system incorporates a gas generator compressor, recuperator, combustor,
power turbine, and electric generator. Air enters the unit and is compressed to about 35 psig in the gas
generator compressor and then heated to around 1,000 °F in the recuperator. A screw compressor type fuel
booster is used to compress the natural gas fuel, the compressed air is 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 power turbine section to perform work, rotating the turbine blades
to turn a generator that produces electricity. The rotating components are of a two-shaft design with the
power turbine connected to a gearbox and supported by oil lubricated bearings. The generator is cooled by
air flow into the gas turbine. The exhaust gas exits the turbine and enters the recuperator, which captures
some of the thermal energy and uses it to pre-heat the air entering the combustor, improving the efficiency
of the system. The exhaust gas then exits the recuperator through a muffler and into the integrated IR heat
recovery unit.
The integral heat recovery system consists of a fin-and-tube heat exchanger, which circulates a mixture of
approximately 16 percent propylene glycol (PG) in water through the heat exchanger at approximately 20
gallons per minute (gpm). The heating loop is driven by an internal circulation pump and no additional
pumping is required. The thermal control system is programmable for individual site requirements.
Minimum settings may vary, but the maximum fluid temperature entering the PowerWorks may never
exceed 200 °F.
The IR PowerWorks system includes an induction generator that produces high-frequency alternating
current (AC) at 480 volts. 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 turbine is
reported by the turbine manufacturer to provide clean power, free of spikes and unwanted harmonics. The
power unit operates at 44,000 revolutions per minute (rpm), and the generator operates at 3,260 rpm
regardless of load.
VERIFICATION DESCRIPTION
Verification of the IR PowerWorks was conducted at the Crouse Community Center in Morrisville, New
York. The facility is a 60,000-square foot skilled nursing facility providing care for approximately 120
residents. The IR PowerWorks system was installed to provide electricity to the facility and to provide heat
for domestic hot water (DHW) and space heating. During normal occupancy and facility operations,
electrical demand exceeds the IR PowerWorks generating capacity, and additional power is purchased from
the grid. On rare occasions, when facility electrical demand is below 70 kW (demand can drop as low as
50 kW in some instances), the excess power is exported to the grid. In the event of a power grid failure, the
system is designed to automatically shut down to isolate system from grid faults. When grid power is
restored, the IR PowerWorks system can be restarted manually.
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April 2003
Prior to installation of the IR PowerWorks, the facility used two gas-fired boilers to generate hot water for
space heating and DHW throughout the complex. The two boilers are Weil-McLain Model Number BG-
688 units, installed in 1996. Each boiler has a rated heat input of 1,700 thousand British thermal units per
hour (MBtu/hr), gross output capacity of 1,358 MBtu/hr, and a net hot water production rate of 1,181
MBtu/hr. The IR PowerWorks is configured in-line with the boiler supply and return fluid (PG) lines
(working fluid is a mixture of 16-percent propylene glycol in water).
Testing commenced on August 14, 2002, and was completed on August 21, 2002. It consisted of a series
of short periods of "controlled tests" in which the unit was operated at full load (the IR PowerWorks unit
tested did not have the capability of intentionally modulating power output). Three test replicates were
conducted during normal site operations regarding heat recovery and use. During these tests, the facility
boilers were thermostatically controlled to maintain desired supply PG temperature. A second set of three
tests was conducted at full power with the boilers turned off to demonstrate the unit's ability to produce
more heat. These controlled test periods were followed by six days of extended monitoring to verify
electric power production, heat recovery, power quality performance, and efficiency during an extended
period of normal site operations. During this period, the IR PowerWorks System operated 24 hours per day
at full electrical power output and normal heat recovery rate.
The classes of verification parameters evaluated are:
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 heating value, 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 determination at both
normal site conditions and with site conditions altered to enhance heat recovery. Pollutant concentration
and emission rate measurements for nitrogen oxides (NOX), carbon monoxide (CO), total hydrocarbons
(THC), carbon dioxide (CO2), and methane (CFy were conducted in the turbine exhaust stack. All test
procedures used in the verification were U.S. EPA Federal Reference Methods. Pollutant concentrations in
the exhaust gas are reported in two sets of units-parts per million volume, dry (ppmvd) corrected to 15
percent oxygen (O2), and 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).
Annual NOX and CO2 emissions reductions for the IR PowerWorks 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 IR PowerWorks System were not present).
At this site the baseline systems include electricity supplied from the local utility grid and heat from the
facility's standard natural gas boilers. Baseline emissions for the electrical power were determined
following Ozone Transport Commission guidelines. Baseline emissions from heat production are based on
EPA emission factors for commercial-scale gas-fired boilers.
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April 2003
Electrical power quality parameters, such as electrical frequency and voltage output, were also measured
during the six-day extended test. Other performance parameters, including current and voltage total
harmonic distortions (THD) and power factor, were monitored to characterize the quality of electricity
supplied to the end user. The guidelines listed in the Institute of Electrical and Electronics Engineers'
Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems were used to
perform power quality testing.
Quality Assurance (QA) oversight of verification testing was provided by Southern Research Institute
(SRI). Following specifications of the ETV Quality Management Plan (QMP), SRI staff conducted three
performance evaluation audits and an audit of data quality on at least 10 percent of the data generated
during this verification.
VERIFICATION OF PERFORMANCE
Heat and Power Production Performance
• All controlled tests occurred at similar operating conditions (ambient temperatures defined on S-2: 76
to 86 °F; barometric pressure: 14.01 to 14.07 psia; relative humidity: 45 to 68 percent).
• During the controlled test period, 50.62±0.84 kW of electric power was generated at full load. Heat
recovery rate during normal facility operations was 143.5±1.82 MBtu/hr. Corresponding efficiencies
were 25.3±0.46 percent for electrical generation, 21.0 ± 0.31 percent for heat production, and
46.3±0.55 percent for total combined heat and power (CHP) efficiency.
• During controlled test periods with the boilers turned off, enhanced heat recovery rate was 173.2+1.82
MBtu/hr. Corresponding heat production efficiency was 24.9±0.35 percent during these tests. These
results demonstrate that heat recovery performance of the IR PowerWorks can be improved by
reducing the heating loop temperature. These results represent the highest heat recovery rate
achievable at this facility under current heating loop design and operation, but do not represent the
maximum heat recovery potential of the IR PowerWorks where lower loop temperatures are evident.
HEAT AND POWER PRODUCTION
Test Condition
Full Power, Normal Site
Operations
Full Power, Heat Recovery
Potential Enhanced
Electrical Power
Generation
Power
Delivered
(kW.)
50.62
52.34
Electrical
Efficiency
(%)
25.3
25.7
Heat Recovery
Performance
Heat
Recovery
Rate
(MBtu/hr)
143.5
173.2
Thermal
Efficiency
(%)
21.0
24.9
Total IR
PowerWorks
System
Efficiency
(%)
46.3
50.6
• Heat input at full load was 684.1 MBtu/hr, or 12.5 standard cubic feet per minute (scfm) natural gas.
Heat rate at full load was 13,487 Btu/kWhe.
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April 2003
Emissions Performance
• During normal site operations, average NOX concentration was 0.86 ppmvd @ 15 percent O2. This
equates to a mass emission rate of 0.0024 Ib/hr and a power normalized emission rate of 4.67 x 10"5
lb/kWhe. Mass emissions of CO2 averaged 82.9 Ib/hr (1.60 lb/kWhe).
• CO concentrations averaged 0.62 ppmvd @ 15 percent O2 during normal site operations. This equates to a
mass emission rate of 0.0011 Ib/hr and a power normalized emission rate of 2.09 x 10"5 lb/kWhe.
• Emissions of THC were near the sensitivity of the sampling system, averaging 2.38 ppmvd @ 15-
percent O2 during normal site operations. Methane concentrations were not detected during any of the
test periods (< 1 ppmvd).
• At full load, NOX emissions per unit electrical power output were 4.67E-05 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 slightly lower than the emission rate for the IR
PowerWorks (1.60 Ib/kWh). These values, along with emission reductions attributed to the IR
PowerWorks heat recovery performance yield an average annual emission reduction of 1,333 Ibs (34
percent) for NOX, and 211,744 Ibs (7 percent) for CO2. Calculated emission reductions include 7.8
percent line losses across the regional grid.
CRITERIA POLLUTANT AND GHG EMISSIONS
Test Condition
Full Power,
Normal Site
Operations
Full Power, Heat
Recovery
Potential
Enhanced
(ppmvd @ 15% O2)
NOX
0.86
1.07
CO
0.62
0.65
THC
2.38
0.54
CH4
<1.0
< 1.0
(lb/kWhe)
NOX
4.67 x 10'5
5.84 x 10"5
CO
2.09 x 10'5
2.14xlO"5
THC
4.48 x 10'5
1.04 x 10"6
CH4
<4.93x
io-5
<4.87x
io-5
C02
1.60
1.78
Power Quality Performance
• Throughout the six-day test period, the IR PowerWorks System maintained continuous synchronization
with the utility grid. Average electrical frequency was 60.001 Hz and average voltage output was 494.75
volts.
• The power factor remained relatively constant for all monitoring days with an average of 67.5 percent and
a range of 62.7 to 73.9 percent.
• The average current THD was 4.76 percent and the average voltage THD was 2.05 percent, both lower
than the ±5 percent threshold specified in IEEE 519.
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April 2003
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 Ingersoll-
Rand Energy Systems, IR PowerWorks™ 70 kW Microturbine System (SRI 2002). Detailed results of the
verification are presented in the Final Report titled Environmental Technology Verification Report for the
Ingersoll-Rand Energy Systems, IR PowerWorks™ 70 kW Microturbine System (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).
Hugh W. McKinnon. M.D.. M.P.H. 5/23/03 Stephen D. Piccot 5/23/03
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-21
April 2003
SRI/USEPA-GHG-VR-21
April 2003
Greenhouse Gas Technology Center
A U.S. EPA Sponsored Environmental Technology Verification ( fcj1*/ ) Organization
Environmental Technology Verification Report
Ingersoll-Rand Energy Systems
IR PowerWorks™ 70 kW Microturbine 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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SRI/USEPA-GHG-VR-21
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TABLE OF CONTENTS
Page
APPENDICES iii
LIST OF FIGURES iii
LIST OF TABLES iii
ACKNOWLEDGMENTS v
ACRONYMS/ABBREVIATIONS vi
1.0 INTRODUCTION 1-1
1.1. BACKGROUND
1.2. IR POWERWORKS TECHNOLOGY DESCRIPTION..
1.3. TEST FACILITY DESCRIPTION
1.4. PERFORMANCE VERIFICATION OVERVIEW
1.4.1. Power and Heat Production Performance ...
1.4.2. Measurement Equipment
-1
-2
-5
-6
-8
-9
1.4.3. Power Quality Performance 1-11
1.4.4. Emissions Performance 1-13
1.4.5. Estimated Annual Emission Reductions for Grouse Community Center 1-15
2.0 VERIFICATION RESULTS 2-1
2.1. POWER AND HEAT PRODUCTION PERFORMANCE 2-2
2.1.1. Electrical Power Output, Heat Recovery Rate, and Efficiency During
Controlled Tests 2-2
2.1.2. Electrical and Thermal Energy Production and Efficiencies Over the
Extended Test 2-5
2.2. POWER QUALITY PERFORMANCE 2-7
2.2.1. Electrical Frequency 2-7
2.2.2. Voltage Output 2-7
2.2.3. Power Factor 2-8
2.2.4. Current and Voltage Total Harmonic Distortion 2-9
2.3. EMISSIONS PERFORMANCE 2-10
2.3.1. IRPowerWorks System Stack Exhaust Emissions 2-10
2.3.2. Estimation of Annual Emission Reductions for Grouse Community Center 2-13
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 3-10
3.2.4. Total Efficiency 3-11
3.2.5. Exhaust Stack Emission Measurements 3-12
4.0 TECHNICAL AND PERFORMANCE DATA SUPPLIED BY INGERSOLL-RAND
ENERGY SYSTEMS 4-1
4.1. SYSTEM CONFIGURATION 4-1
4.2. ELECTRICAL PERFORMANCE 4-1
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April 2003
4.3. COGENERATION PERFORMANCE 4-2
4.4. ELECTRICAL POWER QUALITY 4-2
4.5. EMISSIONS AND THE FUEL SYSTEM 4-2
5.0 REFERENCES 5-1
APPENDICES
Page
APPENDIX A Emissions Testing QA/QC Results A-l
LIST OF FIGURES
Page
Figure 1-1 The IR PowerWorks CHP System 1-3
Figure 1-2 IRPowerWorks Process Diagram 1-3
Figure 1 -3 Grouse Community Center Space Heating and Hot Water System 1-6
Figure 1-4 Schematic of Measurement System 1-10
Figure 2-1 Anticipated IR PowerWorks Heat Recovery Rates as a Function
Of Inlet Water Temperature 2-4
Figure 2-2 Power and Heat Production During the Verification Periods 2-5
Figure 2-3 Ambient Temperature Effects on Power Production During Extended
Test Period 2-6
Figure 2-4 Ambient Temperature Effects on System Efficiency During Extended
Test Period 2-6
Figure 2-5 IR PowerWorks System Electrical Frequency During Extended Test Period 2-7
Figure 2-6 IR PowerWorks System Voltage Output During Extended Test Period 2-8
Figure 2-7 IR PowerWorks System Power Factors During Extended Test Period 2-9
Figure 2-8 IR PowerWorks System Current and Voltage THD During Extended
Test Period 2-10
LIST OF TABLES
Page
Table 1-1 IR Power Works Physical, Electrical, and Thermal Specifications 1-4
Table 1-2 Controlled and Extended Test Periods 1-7
Table 1-3 Summary of Emissions Testing Methods 1-14
Table 1-4 Electrical and Thermal Energy Profiles of the Grouse Community Center 1-17
Table 1-5 Displaced Emission Rates for the NY ISO (2002) 1-21
Table 2-1 Heat and Power Production Performance 2-3
Table 2-2 Fuel Input and Heat Recovery Unit Operating Conditions 2-3
Table 2-3 IR PowerWorks Electrical Frequency During Extended Period 2-7
Table 2-4 IRPowerWorks Voltage During Extended Period 2-8
Table 2-5 IRPowerWorks Power Factors During Extended Period 2-9
Table 2-6 IR PowerWorks THDs During Extended Period 2-9
Table 2-7 IRPowerWorks Emissions During Controlled Periods 2-12
Table 2-8 Emissions Offsets From On-Site Electricity Production 2-14
Table 2-9 Emissions Offsets From On-Site Heat Recovery 2-15
Table 2-10 Estimated Annual Emission Reductions from DG-CHP System at Grouse
Community Center 2-15
Table 3-1 Verification Parameter Data Quality Objectives 3-1
Table 3-2 Summary of Data Quality Goals and Results 3-3
Table 3-3 Results of Additional QA/QC Checks 3-6
in
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Table 3-4 Variability Observed in Operating Conditions 3-8
Table 3-5 Comparison of Integral Orifice Meter With Dry Gas Meter During
Controlled Testing 3-9
Table 3-6 Results of Natural Gas Audit Sample Analysis 3-10
Table 3-7 Additional QA/QC Checks for Emissions Testing 3-14
IV
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ACKNOWLEDGMENTS
The Greenhouse Gas Technology Center wishes to thank NYSERDA, especially Richard Drake and
Joseph Sayer, for reviewing and providing input on the testing strategy and this Verification Report.
Thanks are also extended to the Grouse Community Center for hosting the verification, in particular Larry
Nelson, for his assistance in executing the verification testing.
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ACRONYMS/ABBREVIATIONS
Abs. Diff.
AC
acf
ADER
ADQ
Amp
ANSI
APPCD
ASHRAE
ASME
Btu
Btu/hr
Btu/lb
Btu/min
Btu/scf
Cl
ccc
CH4
CHP
CO
CO2
CT
DAS
DG
DHW
DMM
DOE
DP
DQI
DQO
dscf/MMBtu
EA
EIA
EPA
ETV
°C
°F
FERC
FID
fps
ft3
gal
GC
GHG Center
gpm
GU
Hg
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 cubit feet
quantification of methane
Grouse Community Center
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
Mercury (metal)
(continued)
VI
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HHV
hr
Hz
1C
IEEE
IPCC
IR PowerWorks
ISO
ISONE
kVA
kVAr
kW
kWh
kWhe
kWhth
kWh/yr
Ib
Ib/Btu
Ib/dscf
lb/ft3
Ib/hr
Ib/kWh
Ib/yr
ISO
LHV
MBtu/hr
MMBtu/hr
MMcf
mol
N2
NDIR
NIST
NO
NO2
NOX
NSPS
NY ISO
NYSEG
NYSERDA
02
O3
ORD
OTC
PEA
PG
PJM
ppmv
ppmvw
ACRONYMS/ABBREVIATIONS
(continued)
higher heating value
hours
hertz
internal combustion
Institute of Electrical and Electronics Engineers
Intergovernmental Panel on Climate Change
Ingersoll-Rand PowerWorks™ 70 kW microturbine system
International Standards Organization and Independent System Operation
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
International Standards Organization and Independent System Operation
lower heating value
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 Electric and Gas Corporation
New York State Energy Research and Development Authority
oxygen
ozone
Office of Research and Development
Ozone Transport Commission
Performance Evaluation Audit
propylene glycol
Pennsylvania/New Jersey/Maryland
parts per million volume
Parts per million volume wet
vn
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ppmvd
psia
psig
PT
QA/QC
QMP
Rel. Diff.
Report
RH
rms
rpm
RTD
scf
scfh
scfm
SRI
T&D
TEI
Test Plan
THCs
THD
TSA
U.S.
VAC
ACRONYMS/ABBREVIATIONS
(continued)
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
Vlll
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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 substantially 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 (SRI), which conducts verification testing of promising GHG 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-review 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 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 closer to customers than central
station generation. A distributed power unit can be connected directly to the customer and/or to a utility's
transmission and distribution system. Examples of technologies available for DG include gas turbine
generators, internal combustion (1C) 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) generation).
Recently, the GHG Center and the New York State Energy Research and Development Authority
(NYSERDA) agreed to collaborate and share the cost of verifying several new DG technologies operating
throughout the state of New York under NYSERDA-sponsored programs. This verification evaluated the
performance of the Ingersoll-Rand (IR) PowerWorks™ 70 kW microturbine system offered by Ingersoll-
Rand Energy Systems (IR PowerWorks). The test unit is currently in use at the Grouse Community
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Center (CCC) in Morrisville, New York which includes an adult care assisted living facility. The IR
PowerWorks system uses a natural-gas-fired 70 kW microturbine for electricity generation and a heat
recovery unit to provide domestic hot water (DHW) and space heating at the CCC complex. Facility
electrical and thermal demand exceeds the IR PowerWorks 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 overall energy conversion efficiency is estimated to range from
70 to 80 percent, which is high enough to significantly reduce greenhouse gas emissions and provide end
users with high-quality energy services at competitive prices.
The GHG Center evaluated the performance of the IR PowerWorks by conducting field tests over a
seven-day verification period (August 14 through 21, 2002). 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 GHG emission reductions for the Grouse
Community Center. 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
Ingersoll-Rand Energy Systems, IR PowerWorks™ 70 kW Microturbine System (SRI 2002). 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 operators at the
Grouse Community Center, Ingersoll-Rand, 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. In some cases, deviations from the Test Plan were required. These deviations, and the
alternative procedures selected for use, are discussed in this report.
The remainder of Section 1.0 describes the IR PowerWorks 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 Ingersoll-Rand, presents
additional information regarding the IR PowerWorks System. Information provided in Section 4 has not
been independently verified by the GHG Center.
1.2. IR POWERWORKS TECHNOLOGY DESCRIPTION
Large- and medium-scale gas-fired turbines have been used to generate electricity since the 1950s.
Recently they have become more widely used to provide additional generation capacity because of their
ability to be quickly and economically deployed. Technical and manufacturing developments during the
last decade have enabled the introduction of microturbines, with generation capacities ranging from 30 to
200 kW. The IR PowerWorks is one of the first microturbine (CHP) units that integrates microturbine
and heat recovery technologies to produce electric power, heat, and hot water all in a single package
(Figure 1-1). Figure 1-2 illustrates a simplified process flow diagram of the IR PowerWorks system, and a
discussion of key components is provided below.
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Figure 1-1. IR PowerWorks CHP System
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Figure 1-2. IR PowerWorks Process Diagram
Domestic Hot water
Exhaust
Air Inlet
Recuperator
Electric Power
to User
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Electric power is generated with an integrated Ingersoll-Rand microturbine with a nominal power output
of 70 kW (59 °F, sea level). Table 1-1 summarizes the physical and electrical specifications reported by
IR. The system incorporates a gas generator compressor, recuperator, combustor, power turbine, and
electric generator. Air enters the unit and is compressed to about 35 psig in the gas generator compressor
and then heated to around 1,000 °F in the recuperator. A screw-compressor type fuel booster is used to
compress the natural gas fuel, the compressed air is 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 power turbine section to perform work, rotating the turbine blades to turn a
generator that produces electricity. The rotating components are of a two-shaft design with the power
turbine connected to a gear box and supported by oil lubricated bearings. The generator is cooled by air.
The exhaust gas exits the turbine and enters the recuperator, which captures some of the thermal energy
and uses it to pre-heat the air entering the combustor, improving the efficiency of the system. The exhaust
gas then exits the recuperator through a muffler and into the integrated IR heat recovery unit.
The IR PowerWorks system includes an induction generator that produces high frequency alternating
current (AC) at 480 volts. 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 turbine is
reported by the turbine manufacturer to provide clean power, free of spikes and unwanted harmonics.
The power unit operates at 44,000 revolutions per minute (rpm), and the generator operates at 3,260 rpm
regardless of load. The Grouse Community Center IR PowerWorks system runs parallel with the local
power utility. If the power demand exceeds the available capacity of the turbine, additional power is
drawn from the grid. In the event of a power grid failure, the system is designed to automatically shut
down to isolate the system from grid faults. When grid power is restored, the IR PowerWorks system can
be restarted manually.
Table 1-1. IR PowerWorks Physical, Electrical, and Thermal Specifications
(Source: Ingersoll-Rand Energy Systems)
Electrical Efficiency (Lower heating value (LHV) basis)
Power (start-up)
Communications
Electrical Outputs (Power at ISO Conditions (59 °F @ sea level))
Full Load Emissions Nitrogen oxides (NOX)
Full Load Emissions Carbon monoxide (CO)
Full Load Emissions Total hydrocarbon (THC)
Natural gas Fuel Consumption Rate
Maximum Fuel Supply Pressure
Minimum Fuel Supply Pressure
Total Exhaust Heat Output
Heat Recovery Rate - Inlet water temperature
Heat Recovery Rate - Inlet water flow rate
Grouse Community Center IR Powerworks Noise Level
Length
Width
Weight
28% (±2%)
Utility grid or black start battery
Ethernet IP or modem
70 kW, 480 VAC, 60 Hz, 3 -phase
<9ppmv@15%O2
<9ppmv@15%O2
<9ppmv@15%O2
832,230 Btu/hr
5 psig
0.29 psig
11 9,400 Btu/hr
40 to 160 °F
5 to 20 gallons per minute
73 dbA at 1 m
69 in.
42 in.
41001bs
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The turbine at the Grouse Community Center facility uses natural gas supplied at about 2 pounds per
square inch gauge (psig). The IR PowerWorks system boosts the fuel pressure to about 50 psig using the
fuel booster compressor.
The integral heat recovery system consists of a fm-and-tube heat exchanger, which circulates a mixture of
approximately 16 percent propylene glycol (PG) in water through the heat exchanger at approximately 20
gallons per minute (gpm). The heating loop is driven by an internal circulation pump, with no additional
pumping required. The recovered heat is circulated through the facility's mechanical room to offset or
supplement heat generated by two gas-fired boilers. The resulting, cooler PG mixture is circulated back
to the heat exchanger, energy is exchanged between the PG mixture and the hot turbine exhaust gas, and
the entire circulation loop is repeated. If overheating of the glycol loop should occur due to the Grouse
Community Center heat load being significantly lower than the heat transferred with the IR PowerWorks
system, the system will automatically shut off.
The thermal control system is programmable for individual site requirements. Minimum settings may
vary, but the maximum fluid temperature entering the PowerWorks may never exceed 200 °F. Section
1.3 below contains further discussion regarding the use of recovered heat.
1.3. TEST FACILITY DESCRIPTION
The Grouse Community Center is located in Morrisville, New York. The facility is a 60,000 square foot
skilled nursing facility providing care for approximately 120 residents. Similar to a hospital, the facility
includes private residential rooms, social and recreational areas, industrial-scale laundry facilities, and
cafeterias. The IR PowerWorks system was installed to provide electricity to the facility and to provide
heat for DHW and space heating.
During normal occupancy and facility operations, electrical demand exceeds the IR PowerWorks
generating capacity, and additional power is purchased from the grid. On rare occasions, when facility
electrical demand is below 70 kW (demand can drop as low as 50 kW in some instances), the excess
power is exported to the grid.
Prior to installation of the IR PowerWorks, the facility used two gas-fired boilers to generate hot water for
space heating and DHW throughout the complex. The two boilers are Weil-McLain Model Number BG-
688 units, installed in 1996. Each boiler has a rated heat input of 1,700 thousand British thermal units per
hour (MBtu/hr) and a net hot water production rate of 1,181 MBtu/hr. (rated efficiency of 69.5%). The IR
PowerWorks is configured in-line with the facilities existing boiler supply and return PG lines (Figure 1-
3).
During normal facility occupancy and operation, the IR PowerWorks system provides enough heat to
supply all of the facility's DHW needs throughout the year. Space heating demand at the facility varies
greatly by season. During warm seasons, the IR PowerWorks system usually provides all of the heat for
space heating as well as DHW. The boilers remain idle unless DHW demand is high, at which time one
boiler may operate for short periods of time. This system is thermostatically controlled such that supply
PG fluid temperature to the DHW and space heating loops is maintained at 185 °F or higher. Should the
fluid temperature drop below this set-point (e.g., cold weather periods or times of high DHW demand),
one or both of the gas-fired boilers will turn on as needed to supplement the heat generated by the IR
PowerWorks and maintain the desired 185 °F PG supply temperature. At times when the space heating
and DHW demand is low, the return PG fluid temperature becomes elevated. Should this temperature
reach 200 °F, the PowerWorks will automatically shut down.
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Figure 1-3. Grouse Community Center Space Heating and Hot Water System
Main system
Circulation pump Weil-McLain
(2° gPm) //Boilers
Hot PG supply for space heating
V
Cool PG return from facility
IR system
circulation pump
(20 gpm)
DHWto
facility
DHW Heat
Exchanger
Hot PG supply
from PowerWorks
IRPowerWorks
Cool PG return
to PowerWorks
Cool water return from facility
1.4. PERFORMANCE VERIFICATION OVERVIEW
This verification test design was developed to evaluate only the performance of the combined heat and
power system and not the overall building integration or specific management strategy. The Test Plan
specified that the verification would include a series of controlled test periods in which the GHG Center
would intentionally modulate the unit to produce electricity at 50, 75, 90, and 100 percent of rated
capacity (70 kW nominal), followed by a period of extended monitoring. However, after development of
the Test Plan, IR informed the Center that the PowerWorks unit at this facility does not have the
capability of modulating power command or output. Instead, the System operates at full capacity during
all operations. The power delivered can vary only slightly in response to natural changes in ambient
conditions. Therefore, the controlled test periods were conducted only at full load. During the extended
monitoring period, the PowerWorks unit was allowed to operate continuously at full load.
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 1.4.3. Detailed
descriptions of testing and analysis methods are not provided here but can be found in the Test Plan.
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Power and Heat 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
• Carbon monoxide (CO) concentrations and emission rates
• Total hydrocarbon (THC) concentrations and emission rates
• Carbon dioxide (CO2) and methane (CfLO concentrations and emission rates
• Estimated GHG emission reductions
Each of the verification parameters listed were evaluated during the controlled or extended monitoring
periods as summarized in Table 1-2. This table also specifies the dates and time periods during which the
testing was conducted.
Table 1-2. Controlled and Extended Test Periods
Controlled Test Periods
Date
08/14/02
08/15/02
Time
09:20-11:30
09:30-13:00
Test Condition
Official Controlled Test Period, three 1 5 to 30-minute test runs
Additional Controlled Test Period - Enhanced recovery potential
with boiler turned off, three 30-minute test runs
Extended Test Periods
Date
8/15/02
8/16/02
8/17/02
8/18/02
8/19/02
8/20/02
8/21/02
Time
20:30 -23:59
00:00-23:59
00:00-23:59
00:00-23:59
00:00-23:59
00:00-23:59
00:00-09:00
Verification
Parameters Evaluated
NOX, CO, THC, CH4,
CO2 emissions, and
electrical, thermal, and
total efficiency
Verification Parameters Evaluated
Total electricity generated; total heat recovered; electrical, tl
efficiency; power quality; and emission offsets
lermal, and total
With the PowerWorks at full load and under normal facility operations, three test runs were executed to
constitute the official controlled tests. During the controlled and extended test periods, facility heat
demand exceeded the heat recovery capacity of the PowerWorks, and therefore one of the facility boilers
was operating intermittently. Under this condition, the facility's heat demands were satisfied, but it was
suspected that the elevated PG fluid return temperatures to the IR PowerWorks that are inherent to this
facility may affect heat recovery performance. To assess any such effects, a second series of controlled
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tests were conducted with the boiler control system manually turned off. With the boiler off and the IR
PowerWorks operating at full load, PG fluid return temperatures dropped considerably (and facility DHW
demand was not being fully met). This series of tests (shown in Table 1-2) allowed the GHG Center to
report enhanced heat recovery potential for this system in addition to the performance measured during
normal site operations. More detail regarding justification of these additional controlled tests, and the
Center's findings, is provided along with the official test results in Section 2.1.1.
During each of the controlled test periods, simultaneous monitoring for power output, heat recovery rate,
fuel consumption, ambient meteorological conditions, and exhaust emissions were performed. Manual
samples of natural gas and PG solution were collected to determine fuel lower heating value and specific
heat of the heat transfer fluid, respectively. 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.
Following the controlled test periods, daily performance of the IR PowerWorks System was characterized
over the six-day extended monitoring period. The IR PowerWorks System was operating 24 hours per
day at maximum electrical power output. During this period, the facility's heat demand exceeded the heat
recovery capacity of the IR PowerWorks at all times, and therefore the test results represent the heat
recovery performance for this facility under normal operations. During the first day of extended
monitoring (8/15/02), the boiler was turned off for a period of approximately 13 hours (0700 to 2000
hours), and the PG loop temperature dropped through the evening hours (period of highest DHW
demand). Although data collected during this period does not represent normal facility operations, it was
used to further evaluate the enhanced potential heat recovery of the IR PowerWorks at this site.
Results from the extended test are used to report total electrical energy generated and used on site, total
thermal energy recovered, GHG emission reductions, and electrical power quality. GHG emission
reductions are estimated using measured GHG emission rates, emissions estimates for electricity
produced at central station power plants, and emissions estimates for the facility's gas-fired boilers.
1.4.1. Power and Heat Production Performance
Electrical efficiency determination was based upon guidelines listed in ASME PTC-22 (ASME 1997),
and was calculated using the average measured power output, fuel flow rate, and fuel lower heating value
(LHV) during each 30-minute test period. The electrical power output in kW was measured with a 7600
ION Power Meter (Power Measurements Ltd.). 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.
34\2.\4kW
77= (Eqn. 1)
HI
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where:
*7 = efficiency
kW = average electrical power output measured over the 30-minute interval (kW)
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)
Simultaneous with electrical power measurements, heat recovery rate was measured using an in-line heat
meter (Controlotron Model 1010EP). The meter enabled 1-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 (ANSI 1992).
Heat Recovery Rate (Btu/min) = Vp Cp 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+Tl)/2
Cp = specific heat of PG solution (Btu/lb °F), evaluated at the avg. temp. (T2+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 IR PowerWorks System. Thermal energy conversion
efficiency was computed as the average heat recovered divided by the average energy input (Equation 3).
Tix = 60*Qavg/HI (Eqn. 3)
where:
T|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.
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Figure 1-4. Schematic of Measurement System
Gas Temperature
Gas Pressure /
1
Fuel
Gas In
Gas Sampling
Port
Heat Recovery
System
Controlotron
PG Return
Utility^
Grid
Exhaust to
Atmosphere
Heat and Power To Facility
The 7600 ION electrical power meter continuously monitored the kilowatts of power at a rate of
approximately one reading every 8 to 12 milliseconds. These data were averaged every minute using the
GHG Center's data acquisition system (DAS). The 7600 ION was factory calibrated by Power
Measurements, complies with ISO 9002 requirements (ISO 9002: 1999), and is traceable to National
Institute of Standards and Technology (NIST) standards. The electric meter was located in the main
switchbox connecting the IR PowerWorks to the host site and represented power delivered to Grouse
Community Center. The real-time data collected by the 7600 ION were downloaded and stored on a data
acquisition computer using Power Measurements' PEGASYS software. The logged 1-minute average kW
readings were averaged over the duration of each controlled test period to compute electrical efficiency.
For the extended test period, kW readings were integrated 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 standard cubic feet per minute natural gas). The orifice meter
was temperature- and pressure-compensated to provide mass flow output at standard conditions (60 °F,
14.696 pound per square inch absolute (psia)). The meter was configured to continuously monitor the
average flow rate per minute. Prior to testing, the meter components (orifice plate and differential
pressure sensors) were calibrated using NIST-traceable instruments. QA/QC checks for this meter were
performed routinely in the field using an in-line positive displacement rotary type gas meter. As shown in
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Figure 1-4, the two meters were installed in series to allow natural gas to flow through both meters while
the turbine was operating. The rotary gas meter, manufactured by Dresser/DMD Roots (Series B3, Model
11C175), was capable of metering flow rates up to 20 acfm. This meter, owned by the local gas utility
(New York State Electric and Gas (NYSEG)), was calibrated prior to testing using a NIST-traceable
volume prover (primary standard) at the range of flows expected during the verification test.
Natural gas samples were collected and analyzed to determine gas composition and heating value. A total
of four samples were collected, three during the control test periods and another after four days of
monitoring. Collection of daily samples were planned, but several samples were invalidated after analysis
due to obvious air contamination (sample collection error). This error is not expected to affect results due
to the consistency in gas composition observed in the four valid samples and the four additional gas
analyses obtained from NYSEG (see Section 3.2.2 for more detail on gas composition). The collected
samples were submitted to a qualified laboratory (Core Laboratories, Inc. of Houston, Texas) for
compositional analysis in accordance with ASTM Specification D1945 for quantification of methane (Cl)
to hexanes plus (C6+), nitrogen, oxygen, and carbon dioxide (ASTM 200la). The compositional data
were then used in conjunction with ASTM Specification D3588 to calculate LHV, and the relative density
of the gas (ASTM 2001b). Duplicate analyses were performed by the laboratory on two of the samples to
determine the repeatability of the LHV results.
A Controlotron (Model 1010EP1) energy meter was used to monitor heat recovery rates. 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 system has an overall rated accuracy of ±1
to ±2 percent of reading depending on the application characteristics described below. The system can be
used on pipe sizes ranging from 0.25 to 360 inches in diameter with fluid flow rates ranging from 0 to 60
feet per second (fps) (bi-directional).
The energy meter's software contains lookup tables that provide the American Society of Heating,
Refrigerating, and Air-Conditioning Engineers (ASHRAE) working fluid density and specific heat values
corrected to the average fluid temperature measured by the RTDs. In order for these values to be correct,
the fluid composition must be known or determined, and programmed into the computer. Fluid
composition testing was conducted before and during testing as described below to ensure proper system
programming.
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. Samples were collected once per day during the testing period.
Each sample collection event was recorded on field logs and shipped to Enthalpy Analytical Laboratories
in Durham, NC along with completed chain-of-custody forms. At the laboratory, samples were analyzed
for PG concentration and fluid density using gas chromatography with a flame ionization detector
(GC/FID). Using the measured concentrations, specific heat of the PG solution was selected using
published PG properties data (ASHRAE 1997).
1.4.3. Power Quality Performance
When an electrical generator is connected in parallel and operated simultaneously with the utility grid,
there are a number of issues of concern. The voltage and frequency generated by the power system must
be aligned with the power grid. While in grid parallel mode, the units must detect grid voltage and
frequency to ensure proper synchronization before actual grid connection occurs. The PowerWorks
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. For previous verifications, the GHG Center has
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defined grid voltage tolerance as the nominal voltage ±10 percent. Frequency tolerance is 60±0.6 Hz (1.0
percent).
The generator's effects on electrical frequency, power factor, and total harmonic distortion (THD) cannot
be completely isolated from the grid. The quality of power delivered actually represents an aggregate of
disturbances already present in the utility grid. For example, local CHP power with low TFiD 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 IR PowerWorks incorporates an induction generator, and therefore always requires reactive power
from the grid and operates at less than unity power factor. The generator's power factor effects will also
change with distance from the CHP generator as the aggregate grid power factor begins to predominate.
The GHG Center and its stakeholders developed the following power quality evaluation approach to
account for these issues. Two documents (IEEE 519, ANSI/IEEE 1989) 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 6-day extended period:
• Electrical frequency
• Voltage
• Voltage THD
• Current THD
• Power factor
The ION power meter (7600 ION) used for power output determinations was used to perform these
measurements as described below and detailed in the Test Plan. Prior to field installation, the factory
calibrated the ION power meter to ANSI C12.20 CAO.2 standards (ANSI/IEEE 1989). 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 frequency, maximum, minimum, and standard
deviation are reported.
The CHP unit generates power at 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. 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 voltage, maximum,
minimum, and standard deviation for the average of the three phases are reported.
THD results from 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. For electrical power in the US, the fundamental is 60 Hz. 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 (i.e., capacitors, motor control thyristors, inverters) connected to the distribution
network.
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For each harmonic, the magnitude of the distortion can vary. Typically, each harmonic's magnitude is
represented as a percentage of the rms voltage of the fundamental. The aggregate effect of all harmonics
is called THD. THD amounts to 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. Based on "recommended practices for individual customers" in the IEEE 519
Standard (IEEE 519), the specified value for total voltage harmonic is a maximum THD of 5.0 percent.
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 (IEEE
1992) 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. For
example, the standard's recommendations for a small CHP unit connected to a large capacity grid 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. As with voltage THD, the ION power meter continuously measured current THD for
each phase and reported the average.
Power factor is the phase relationship of current and voltage in AC electrical distribution systems. Under
ideal conditions, current and voltage are in phase, which results in a unity (100 percent) power factor. If
reactive loads are present, power factors are less than this optimum value. Although it is desirable to
maintain unity power factor, the actual power factor of the electricity supplied by the utility may be much
lower because of load demands of different end users. Typical values ranging between 60 and 90 percent
are common. Low power factor causes heavier current to flow in power distribution lines for a given
number of real kilowatts delivered to an electrical load.
The ION power meter 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 averaged over all three phases.
1.4.4. Emissions Performance
Pollutant concentration and emission rate measurements for NOX, CO, THCs, and CO2 were conducted
on the turbine exhaust stack during the full load controlled test periods. Emissions testing coincided with
the efficiency determinations described earlier. All of the test procedures used are U.S. EPA Federal
Reference Methods, which are well documented in the Code of Federal Regulations. The Reference
Methods include procedures for selecting measurement system performance specifications and test
procedures, quality control procedures, and emission calculations (40CFR60, Appendix A). Table 1-3
summarizes the standard test methods that were followed. A complete discussion of the data quality
requirements (e.g., NOX analyzer interference test, nitrogen dioxide (NO2) converter efficiency test,
sampling system bias and drift tests) is presented in the Test Plan.
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Table 1-3. 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 10 (chemiluminescense)
TEI Model 48 l(NDIR)
TEI Model 51 (FID)
Hewlett-Packard 5890 GC/FID
Infrared Industries Model 703D (NDIR)
Infrared Industries Model 2200
(electrochemical)
Instrument Range
0-25 ppm
0-25 ppm
0 - 25 ppm
0 - 25 ppm
0 - 10%
0 - 25%
During each test, sampling was conducted for approximately 30 minutes at a single point near the center
of the 12-inch diameter stack. Results of the instrumental testing are reported in units of parts per million
by volume dry (ppmvd) and ppmvd corrected to 15 percent O2. The emissions testing was conducted by
ENSR International of East Syracuse, New York, under the on-site supervision of the GHG Center Field
Team Leader. A detailed description of the sampling system used for criteria pollutants, GHGs, and O2 is
provided in the Test Plan and is not repeated in this report. A brief description of key features is provided
below.
In order for the CO2, O2, NOX, and CO instruments to operate properly and reliably, the flue gas must be
conditioned prior to introduction into the analyzers. The gas conditioning system used for this test was
designed to remove water vapor and/or particulate from the sample. Gas was extracted from the turbine
exhaust gas stream through a stainless steel probe and heated sample line and transported to ice-bath
condensers, one on each side of a sample pump. The condensers removed moisture from the gas stream.
The clean, dry sample was then transported to a flow distribution manifold where sample flow to each
analyzer was controlled. Calibration gases were routed through this manifold to the sample probe to
perform bias and linearity checks.
NOX concentrations were determined using a Thermo Environmental Instruments (TEI) Model 10. This
analyzer catalytically reduces NO2 in the sample gas to nitric oxide (NO). The gas is then catalytically
converted to excited NO2 molecules by oxidation with ozone (O3) (normally generated by ultraviolet
light). The resulting NO2 emits light (luminesces) in the infrared region. The emitted light is measured by
an infrared detector and reported as NOX. The intensity of the emitted energy from the excited NO2 is
proportional to the concentration of NO2 in the sample. The efficiency of the NO to NO2 catalytic
converter is checked as an element of instrument setup and checkout. The NOX analyzer was calibrated
to a range of 0 to 25 ppmvd.
A TEI Model 48 gas filter correlation analyzer with an optical filter arrangement was used to determine
CO concentrations. This method provides high specificity for CO. Gas filter correlation uses a constantly
rotating filter with two separate 180-degree sections (much like a pinwheel.) One section of the filter
contains a known concentration of CO, and the other section contains an inert gas without CO. The
sample gas is passed through the sample chamber containing a light beam in the spectral region absorbed
by CO. The sample is then measured for CO absorption with and without the CO filter in the light path.
These two values are correlated, based upon the known concentrations of CO in the filter, to determine
the concentration of CO in the sample gas. The CO analyzer was operated on a range of 0 to 25 ppmvd.
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THC concentrations in the exhaust gas were measured using a TEI Model 51 flame ionization analyzer
and quantified as methane. This detector analyzes gases on a wet, unconditioned basis. Therefore, a
second heated sample line was used to deliver unconditioned exhaust gases directly to the THC analyzer.
All combustible hydrocarbons were analyzed. Emission rates are reported on an equivalent methane
basis.
For determination of CO2 concentrations, an Infrared Industries Model 703D analyzer equipped with a
non-dispersive infrared (NDIR) detector was used. NDIR measures the amount of infrared light that
passes through the sample gas versus through a reference cell. Because CO2 absorbs light in the infrared
region, the degree of light attenuation is proportional to the CO2 concentration in the sample. The CO2
analyzer range was set at 0 to 10 percent. A Infrared Industries Model 2200 electrochemical cell analyzer
was used to monitor O2 concentrations. The O2 analyzer range was set at 0 to 25 percent.
The instrumental testing for CO2, O2, NOX, CO, and THC yielded concentrations in units of ppmvd and
ppmvd corrected to 15 percent O2. 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. For this verification, the published F-factor of 8,710 dry standard cubic feet per million Btu
(dscf/MMBtu) was used to determine emission rates for each controlled test period. After converting the
pollutant concentrations from a ppmvd basis to Ib/dscf, emission rates were calculated using the measured
heat input to the turbine [MMBtu/hr based on the higher heating value (HHV) of the gas] and stack gas
O2 concentration (dry basis), in terms of Ib/hr using Equation 4.
Mass Emission Rate (Ib/hr) = HI * Concentration * F-factor * [20.9 / (20.9 - % O2J] (Eqn. 4)
where:
HI = average measured heat input, HHV based (MMBtu/hr)
Concentration = measured pollutant concentration (Ib/dscf)
F-factor = calculated exhaust gas flow rate (dscf/MMBtu)
02,d
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 Grouse Community Center
Without on-site generation of electricity and heat with the IR PowerWorks, all of the Grouse Community
Center's electrical power and heat demand is met by the local utility, NYSEG, and two on-site gas-fired
boilers, respectively. Electricity generation from central power stations and heat production from gas
boilers is defined as the baseline power and heat scenario for this facility, and emissions of NOX and CO2
generated by these systems represent the baseline emissions in the absence of the IR PowerWorks CHP
system. With the IR PowerWorks system operating, some of the power and heat demand of the facility is
met through on-site generation. Under this scenario, less power is purchased from the utility grid, and
less heat is generated by the gas-fired boilers. If emissions of CO2 and NOX with the IR PowerWorks
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scenario are lower than the emissions associated with the baseline scenario, then a reduction in emissions
would be realized under the CHP system scenario.
For this verification, emissions from the IR PowerWorks scenario are compared with the baseline
scenario to estimate annual NOX and CO2 emission levels and reductions (Ib/yr). These pollutants were
considered because CO2 is the primary greenhouse gas emitted from combustion processes, and NOX is a
primary pollutant of regulatory interest. Reliable emission factors for electric utility grid and boilers are
available for both gases. Emission reductions were computed as follows:
Annual Emission Reductions (Ib/yr) = [Baseline Scenario Emissions] - [IR PowerWorks 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 Grouse Community Center Annual Electrical and Thermal Energy Profiles
The first step in estimating emission reductions was to determine the facility's annual electrical (kWhe)
and thermal energy demand (kWhth). This was done by obtaining the monthly electricity and natural gas
utility bills from the facility operator and reviewing the information to estimate the energy demand for
each month of 2002. The IR PowerWorks was operating during this fiscal year; therefore, the electrical
demand was simply the sum of electricity purchased from the utility (obtained from the utility bills) and
the electricity supplied by the IR PowerWorks CHP (obtained from site's data records). Table 1-4
summarizes the site's electrical energy demand.
The site operators also provided utility bills which contained monthly natural gas consumption records for
both the on-site boilers and the IR PowerWorks CHP. Since these records indicate fuel input levels,
thermal energy delivered was estimated by multiplying heat input levels by the efficiency of each system.
For the gas fired boilers, manufacturer's efficiency rating of 69.5% was used, which accounts for
radiation losses and normal piping and pickup losses. For the IR PowerWorks CHP, the efficiency rating
as measured during full load testing by the GHG Center was used. The sum of energy delivered by the
boilers and the IR PowerWorks CHP represented the monthly thermal energy demand of the site. Table
1-4 summarizes the site's thermal energy demand.
Table 1-4 also shows the distribution of energy demand as supplied by the systems in the baseline and IR
PowerWorks scenarios. Note, based on the site operator's observations, the operational availability of the
IR PowerWorks is assigned to be 98%. Also, the electrical and thermal energy supplied by the IR
PowerWorks are derated using average monthly air temperatures for the site. This was accomplished by
using the trends observed during the verification test. Specifically, as discussed later in Section 2, the
heat and power production performance of the IR PowerWorks was monitored when ambient
temperatures ranged between 47 and 93 °F. Using this verification data, electrical and thermal energy
efficiency curves were developed as a function of ambient temperatures, and the efficiency levels at the
average monthly temperatures in 2002 were used to estimate electrical energy and thermal energy
generation potential with the IR PowerWorks system (Table 1-4). The average monthly temperatures for
8 months were characterized using the efficiency observed during the verification period. For the
remaining months (the four coldest), the de-rate curves were extrapolated to the lowest average monthly
temperature of 18 °F.
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Table 1-4 Electrical and Thermal Energy Profiles of the Grouse Community Center
Jan
Feb
Mar
Apr
May
June
July
Aug
Sept
Oct
Nov
Dec
Annual Total
Estimated Energy Demand
of the Facilitv
Electric
kWhe
114,710
90,833
94,007
86,251
86,066
99,260
112,824
112,770
95,335
86,451
88,677
104,540
1.171.724
Thermal
kWhth
177,662
183,189
165,096
130,643
116,370
86,351
74,310
84,705
93,924
131,030
146,155
191,566
1.581.001
Baseline Scenario
Energy Supplied
Bv Utility Grid
Electric
kWlleorid
114,710
90,833
94,007
86,251
86,066
99,260
112,824
112,770
95,335
86,451
88,677
104,540
1.171.724
Energy Supplied
Bv Gas Boilers
Thermal
kWhe.Boiler
177,662
183,189
165,096
130,643
116,370
86,351
74,310
84,705
93,924
131,030
146,155
191,566
1.581.001
IR PowerWorks Scenario
Energy Su
Electric
kWheIR
46,204
41,774
44,263
38,216
35,884
33,304
32,157
33,191
34,530
38,177
40,466
44,820
462.987
alied By IR
Thermal
kWhtujR
23,919
21,836
25,333
26,132
28,545
28,743
30,215
29,958
27,997
27,517
25,386
24,819
320.400
Makeup Energy Supplied By
Grid and Gas Boilers
Electric
kWhe.Glid
68,506
49,059
49,744
48,035
50,182
65,956
80,667
79,579
60,805
48,274
48,211
59,720
708.737
Thermal
kWhtll.Boiler
153,743
161,353
139,763
104,511
87,825
57,608
44,095
54,747
65,927
103,513
120,769
166,747
1.260.601
Step 2 - Emissions Estimate For the IR PowerWorks CHP
Using the energy production data for the IR PowerWorks, emissions associated with this DG-CHP system
were estimated as follows:
Em =kWhem*ERIR
(Eqn.5)
where:
EIR
kWheni
= IR PowerWorks emissions, Ib/yr
= Electrical energy generated by IR PowerWorks, Table 1-4, kWheiR
= IR PowerWorks emission rate, lb/kWhe
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 Gas Boiler(s)
The host facility's baseline heating units, (two identical natural gas-fired Weil-McLain boilers), have a
manufacturer's specified gross combustion efficiency of 81.4 percent. The units are designed to provide
1.181 MMBtu/hr of hot water from 1.703 MMBtu/hr natural gas fuel input. After accounting for boiler
insulation, heat transfer, and other losses, the rated net boiler efficiency reported by the manufacturer for
hot water production is 69.5 percent. This means that, for every Btu of heat required, 1/0.695, or 1.439
Btu, of fuel would have been supplied to the boilers. The carbon in the natural gas, when combusted, will
form CO2. The resulting CO2 emission rate can be calculated as follows:
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44 3412 1 1
ERBoaerC02
where:
ERBoiierco2 = boiler CO2 emission rate, lb/kWhth
44 = molecular weight of CO2, Ib/lb-mol
12 = molecular weight of carbon, Ib/lb-mol
CC = measured fuel carbon content, 35.04 Ib/MMBtu
FO = 0.995; fraction of natural gas carbon content oxidized during
combustion
3412.1 =lkWth/Btu
1,000,000 = 1 MMBtu/Btu
Eff Boiler = Combustion efficiency of gas boiler, 69.5%
Using the carbon content of natural gas sampled at the test site by the GHG Center, the CO2 emission rate
for the boiler is 0.627 lb/kWhth. Note, this emission rate assumes that the boiler efficiency is the same at
all heat output levels (i.e., the unit is 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.
For NOX, emission factor for commercial boilers was obtained from AP-42 (EPA 1995). For boiler sizes
ranging between 0.3 and 10 MMBtu/hr of heat input, 100 Ib NOX/106 scf of natural gas is emitted. Using
the measured LFfV of the natural gas used at the facility, the NOX emission rate for the boilers is
0.000538 lb/kWhth.
The CO2 and NOX emission rates, combined with the energy supplied by the boilers, yields the following
equation for estimating boiler emissions:
E Boiler = kWhth,Bo,ler * ERBoiler (Eqn. 7)
where:
Eeoiier = boiler emissions, Ib/yr
kWh th,Boiier = thermal energy supplied by the boilers, kWhth
EReoiier = boiler emission rate, lb/kWhth
Step 4 - Emissions Estimate For the Utility Grid
Emissions associated with electricity generation at central power stations is defined by the following
equation:
Ear* = kWheflrid * 1.078* ERGrid (Eqn. 8)
where:
Eorid = grid emissions (Ib/yr)
kWheGnd = electricity supplied by the grid, Table 1-4 (kWhe)
1.078 = transmission and distribution system line losses
= NY ISO displaced emission rate (lb/kWhe)
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The kWheGnd variable shown above represents the estimated electricity supplied by (EIA 2000b) the
utility grid under the baseline scenario and the IR PowerWorks scenario (Table 1-4). 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 methodology for estimating this parameter is
continuously evolving. The following discussion provides a brief background on the concept of displaced
emissions and presents the strategy employed by the GHG Center to assign ER^d for this verification.
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 heat and power generation with a distributed energy technology (e.g.,
IR PowerWorks) 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 methodologies have been developed and employed by various organizations to estimate
emissions displaced by on-site electricity generation. Although there are many variations of such
methodologies, 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, and 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.
As a result, 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.
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• 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
currently 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. It 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 (OTC 2002). The
geographic focus of the Workbook is the three northeastern electricity control areas: Pennsylvania/New
Jersey/Maryland (PJM), the New York Independent System Operation (NY ISO), and Independent
System Operation 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). To evaluate these programs, the Workbook
contains default displaced emission rates for the three northeastern control areas. The default displaced
emission rates are divided into three time periods: near term (2002-2005), medium term (2006-2010),
and long term (2011-2020). For this verification, the short-term default emission rates for the NY ISO
control area have been used to represent the ERodd variable shown in Equation 8.
The near-term rates for the NY ISO are summarized in Table 1-5. 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.
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Table 1-5. 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. Because the simulation is done in chronological order, actual constraints on system
operation (such as unit ramp times and minimum up and down times) are taken into account. 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 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. To calculate marginal emission
rates for different periods, OTC calculated the total difference in kWhs generated between the base case
and decrement case and the total difference in emissions and then divided the emissions by kWhs to
derive the marginal emission rate for the time period. It should be noted that marginal rates shown in
Table 1-5 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 Provences, Ontario, and Quebec.
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2.0 VERIFICATION RESULTS
The verification period started on August 14, 2002, and continued through August 21, 2002. The
controlled tests at full load were conducted on August 14 and repeated on August 15 with the boiler shut
down to enhance heat recovery. This was followed by an extended six-day period of continuous
monitoring to examine heat and power output, power quality, efficiency, and emission reductions.
During the controlled and extended verification test periods, 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 (i.e., 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
• IR PowerWorks and facility operating data
The Field Team Leader reviewed, verified, and validated some data (e.g., DAS file data, reasonableness
checks) while on site. In the field, the Team Leader reviewed collected data for reasonableness and
completeness. The data from each of the controlled test periods was reviewed on-site to verify that PTC
22 (ASME 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 glycol solution analysis results, were reviewed, verified, and validated after
testing had ended. Upon review, all collected data was classed as valid, suspect, or invalid 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. In general, all 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. Although 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, the reader is cautioned 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).
With the verification testing occurring in August and the IR PowerWorks System and its intake air
located outdoors, the high summer air temperatures encountered must be considered when evaluating the
results. During the test period, temperatures generally ranged from 65 °F at night to highs approaching 95
°F in afternoons (the lowest temperature recorded was 47 °F on the last night of the test period).
Therefore, the test results do not provide information related to the system's response to lower ambient
temperatures that are encountered in this and other regions.
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Test results are presented in the following subsections:
Section 2.1 - Heat and Power Production Performance
(short-term controlled testing and six days of extended testing)
Section 2.2 - Power Quality Performance
(six days of extended testing)
Section 2.3 - Emissions Performance and Reductions
(controlled test periods)
The results show that the quality of power generated by the IR PowerWorks System is generally high, and
that the unit is capable of operating in parallel with the utility grid. The unit produced between 50 and 69
kW of electrical power depending on ambient temperature (47 to 95 °F). The highest heat recovery rate
measured was approximately 173,600 Btu/hr under normal site operation (approximately 178,000 Btu/hr
with the boiler turned off). During normal operations, electrical efficiency averaged 25.3 percent and
thermal efficiency averaged 21.0 percent (24.9 percent with the boilers turned off). Total IR PowerWorks
System efficiency at full load was 46.3 percent (50.6 percent with the boilers turned off). NOX and CO
emissions at full load were 1 ppmvd or less (corrected to 15 percent O2). NOX and CO2 emission
reductions are estimated to be at least 99 and 61 percent, respectively.
An 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. POWER AND HEAT 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.
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 IR
PowerWorks System. All controlled testing occurred during relatively consistent atmospheric conditions:
81 °F average ambient temperature, 56 percent average RH, and 14.0 psia average barometric pressure.
Actual conditions encountered during testing were warmer than standard conditions defined by the
International Standards Organization (59 °F, 60 percent RH, and 14.696 psia), and as a result, some
deration of the electrical power and efficiency should be expected in the verification results. The reader is
cautioned that 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 (e.g., cooler temperatures, different elevations). Natural gas fuel input characteristics and heat
recovery unit operation data corresponding to these efficiency results are summarized in Table 2-2.
2-2
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SRI/USEPA-GHG-VR-21
April 2003
Table 2-1. Heat and Power Production Performance
Runl
Run 2
Run 3
Avg.
Run 4
Run 5
Run 6
Avg.
Test Condition
%of
Rated
Power
100
100
Site
Operations
Normal
Boiler off
Heat
Input
(M
Btu/hr)
691.5
677.3
683.4
684.1
691.6
690.0
705.2
695.6
Electrical Power
Generation
Performance
Power
Delivered a
(kWe)
51.69
49.80
50.37
50.62
51.95
51.76
53.31
52.34
Electrical
Efficiency
(%)
25.5
25.1
25.2
25.3
25.6
25.6
25.8
25.7
Heat
Recovery
Performance
Heat
Recovery
Ratec
(M
Btu/hr)
142.9
142.1
145.6
143.5
171.0
173.0
175.7
173.2
Thermal
Efficiency
(%)
20.7
21.0
21.3
21.0
24.7
25.1
24.9
24.9
Total IR
Power-
Works
System
Efficiency
(%)
46.2
46.1
46.5
46.3
50.4
50.7
50.7
50.6
Ambient
Conditions b
Temp
(°F)
76.1
80.9
86.0
81.0
80.4
84.5
79.1
81.3
RH
(%)
69
58
45
57
55
46
63
55
a Represents actual power available for consumption at the test site.
b To convert to equivalent kilowatts (kWth), divide by 3412. 14.
0 Barometric pressure remained relatively consistent throughout the test runs (14.01 to 14.07 psia).
Table 2-2. Fuel Input and Heat Recovery Unit Operating Conditions
Runl
Run 2
Run 3
Avg.
Run 4
Run 5
Run 6
Avg.
Test Condition
%of
Rated
Power
100
100
Site
Operations
Normal
Boiler off
Natural Gas Fuel Input
Gas
Flow
Rate
(scfm)
12.6
12.4
12.5
12.5
12.7
12.7
13.0
12.8
LHVa
(Btu/ft3)
913.4
~
911.7
912.6
—
906.9
~
906.9
Gas
Pressure
(psig)
1.89
1.89
1.89
1.89
1.89
1.89
1.89
1.89
Gas
Temp
(°F)
76.8
80.6
84.5
80.6
79.9
82.7
83.8
82.1
PG Fluid Conditions
PG Comp.b
(% volume)
15.4
~
~
15.4
15.3
~
~
15.3
Fluid
Flow
Rate
(gpm)
16.2
16.2
16.2
16.2
16.0
16.0
16.0
16.0
Outlet
Temp.
(°F)
188.5
189.0
189.6
189.0
157.9
156.8
159.5
158.1
Inlet
Temp.
(°F)
170.4
171.0
171.1
170.8
136.0
134.6
137.0
135.9
Temp.
Diff.
(°F)
18.1
18.0
18.5
18.2
21.9
22.2
22.5
22.2
a Represents results of actual gas samples collected during each day (average of two samples for runs 1-3, one sample for runs 4-6)
b Represents results of actual PG samples collected during each day
2-3
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SRI/USEPA-GHG-VR-21
April 2003
During normal site operations, the average electrical power delivered was 50.62 kWe at full load, and the
average electrical efficiency corresponding to these measurements was 25.3 percent. Electric power
generation heat rate, which is an industry accepted term to characterize the ratio of heat input to electrical
power output, was measured to be 13,487 Btu/kWhe at full power. Net heat rate, which includes energy
from heat recovery, was 7,370 Btu/kWhtot at full power. The average heat recovery rate during normal
site operations was 144.5 MBtu/hr, or 42.35 kWth/hr, and thermal efficiency was 21.0 percent. Based on
results of three runs, the total efficiency (electrical and thermal combined) was 46.3 percent.
As briefly discussed in Section 1.4, the return PG temperature averaged 170.8 °F during normal
operations at this facility, which is higher than design specifications for the IR PowerWorks (the unit is
designed for return temperatures in the range of 40 to 160 °F). To evaluate if the elevated return
temperatures at this site impacted heat recovery performance, the second series of controlled tests were
conducted at full load with the boilers turned off to reduce return temperature (enhanced heat recovery
tests). During these tests, average electrical power output and efficiency were 52.34 kWe and 25.7
percent. The average heat recovery rate increased to 173.2 MBtu/hr, or 50.78 kWth/hr, and thermal
efficiency was 24.9 percent. Based on results of three runs, the total system efficiency was 50.6 percent
with the reduced PG loop temperature. Table 2-2 shows that this increase was due to a greater difference
between supply and return temperature, indicating that the IR System transferred more heat to the PG
loop once the inlet temperature was reduced. After the PG return temperature dropped from 170.8 to
135.9 °F, the temperature differential increased from 18.2 to 22.2 °F. This trend is consistent with data
published by IR that show anticipated heat recovery rates as a function of inlet fluid temperature (Figure
2-1). Heat recovery potential of the IR PowerWorks may be greater for facilities with lower fluid loop
temperatures, but the Grouse Community facility cannot operate for extended periods at these reduced
loop temperatures and still meet the critical DHW requirements of the facility. It is expected that major
heating loop design modifications would be necessary at this site in order to minimize the return loop
temperature and realize the maximum heat recovery potential of the IR PowerWorks.
Figure 2-1. Anticipated IR PowerWorks Heat Recovery Rates as a Function of Inlet Water
Temperature (Btu/hr) (figure provided by Ingersoll Rand)
2-4
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SRI/USEPA-GHG-VR-21
April 2003
2.1.2. Electrical and Thermal Energy Production and Efficiencies Over the Extended Test
Figure 2-2 presents a time series plot of power production and heat recovery during the six-day extended
verification period. The system was operating 24 hours per day and was producing as much electrical
power and heat as possible depending on ambient conditions. A total of 7,472 kWhe electricity and 6,070
kWhth of thermal energy were generated over an operating period of 132 hours. All of the electricity and
heat generated were used by the facility. Electrical, thermal, and total system efficiencies during the
extended period averaged 25.8, 21.0, and 46.8 respectively, percent and were consistent with the
efficiencies measured during the controlled test period.
The average power generated over the extended period was 56.6 kWe, and average heat recovery rate was
46.3 kWth. Power production showed variation that coincides with diurnal temperature variations. The
effect of ambient temperature on power output (and fuel consumption) is further illustrated in Figure 2-3.
The figure clearly shows that power output increases as the ambient temperature (intake air) drops below
75 °F. This trend is consistent with industry knowledge of turbine performance (i.e., electrical power
output generally decreases with increasing temperatures). Facility operators have reported power output
as high as 80 kW from this unit during periods of very cold weather.
140
Figure 2-2. Power and Heat Production During the Verification Periods
Periods of enhanced heat recovery
(boilers turned off)
8/14/02
(15:00)
8/15/02
(15:00)
8/16/02
(15:00)
8/17/02
(15:00)
8/18/02
(15:00)
8/19/02
(15:00)
8/20/02
(15:00)
8/21/02
(09:00)
2-5
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SRI/USEPA-GHG-VR-21
April 2003
Figure 2-3. Ambient Temperature Effects on Power Production During Extended Test Period
70
10
55
65
75
85
95
Ambient Temperature (°F)
Figure 2-4 plots electrical, thermal, and total system efficiency over the extended monitoring period as a
function of ambient temperature. Although electrical power production increased at lower temperatures,
electrical efficiency did not change significantly because fuel input increased proportionately to power
output, as shown in Figures 2-3 and 2-4. The change in electrical efficiency over the range of
temperatures (47 to 95 °F) observed during the extended period was less than 1.5 percent, with the highest
efficiencies occurring at the lowest ambient temperatures. Heat production did not change significantly
during the period (Figure 2-2), but Figure 2-4 shows that heat recovery efficiency increased slightly
during periods of higher ambient temperature.
Figure 2-4. Ambient Temperature Effects on System Efficiency During Extended Test Period
60
50
— 40
30
20
10
Total
Electrical
45
55
65
75
85
95
Ambient Temperature (°F)
2-6
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SRI/USEPA-GHG-VR-21
April 2003
2.2. POWER QUALITY PERFORMANCE
2.2.1. Electrical Frequency
Electrical frequency measurements (voltage and current) were monitored simultaneously for the IR
PowerWorks System. The 1-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 2-5 and summarized in Table 2-3. The average
electrical frequency measured was 60.001 Hz, and the standard deviation was 0.014 Hz.
Figure 2-5. IR PowerWorks System Electrical Frequency During Extended Test Period
60.08
60.06 -
59.92
8/14/02
(15:00)
8/15/02
(15:00)
8/16/02
(15:00)
8/17/02
(15:00)
8/18/02
(15:00)
8/19/02
(15:00)
8/20/02
(15:00)
8/21/02
(09:00)
Table 2-3. IR PowerWorks Electrical Frequency During Extended Period
Parameter
Average Frequency
Minimum Frequency
Maximum Frequency
Standard Deviation
Frequency (Hz)
60.001
59.945
60.058
0.014
2.2.2. Voltage Output
Traditionally, it is 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).
2-7
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SRI/USEPA-GHG-VR-21
April 2003
Voltage was monitored on the turbine using the 7600 ION electric meter. The meter was configured to
measure 0 to 600 VAC. The turbine was grid connected and operated as a voltage-following current
source. As a result, the voltage levels measured are more indicative of the grid voltage levels that the IR
PowerWorks tried to mimic (typically around 490 volts at the specific location).
Figure 2-6 plots 1-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.
Figure 2-6. IR PowerWorks System Voltage Output During Extended Test Period
520
510
460
8/14/02
(15:00)
8/15/02|
(15:00)
8/16/02
(15:00)
8/17/02
(15:00)
8/18/02
(15:00)
8/19/02
(15:00)
8/20/02
(15:00)
8/21/02
(09:00)
Table 2-4. IR PowerWorks Voltage During Extended Period
Parameter
Average Voltage
Minimum Voltage
Maximum Voltage
Standard Deviation
Volts
494.64
464.82
510.98
2.86
2.2.3. Power Factor
Having an induction generator, the IR PowerWorks power factors were expected to be in the range of 60
to 90 percent, as is common for this type of equipment. Figure 2-7 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. It is clear that the variation in power factor follows the variations seen
in the power output results shown earlier in Figure 2-2. During cooler periods, both power output and
2-S
-------
SRI/USEPA-GHG-VR-21
April 2003
power factor increased, particularly during the diurnal cycles that peaked during the evenings of the 18th,
19th, and 20th.
Figure 2-7. IR PowerWorks System Power Factors During Extended Test Period
75.92
73.92
59.92
8/14/02
(15:00)
8/15/02
(15:00)
8/16/02
(15:00)
8/17/02
(15:00)
8/18/02
(15:00)
8/19/02
(15:00)
8/20/02
(15:00)
8/21/02
(09:00)
Table 2-5. IR PowerWorks Power Factors During Extended Period
Parameter
Average Power Factor
Minimum Power Factor
Maximum Power Factor
Standard Deviation
%
67.49
62.71
73.91
1.76
2.2.4. Current and Voltage Total Harmonic Distortion
,rd
The turbine total harmonic distortion, up to the 63r harmonic, was recorded for current and voltage
output using the 7600 ION. The average current and voltage THDs were measured to be 4.76 percent and
2.05 percent, respectively (Table 2-6). Figure 2-8 plots the current and voltage THDs throughout the six
day extended verification period.
Table 2-6. IR PowerWorks THDs During Extended Period
Parameter
Average
Minimum
Maximum
Standard Deviation
Current THD (%)
4.76
3.71
6.30
0.61
Voltage THD (%)
2.05
1.50
4.36
0.33
2-9
-------
SRI/USEPA-GHG-VR-21
April 2003
Figure 2-8. IR PowerWorks System Current and Voltage THD During Extended Test Period
8.00
6.00
o
X
4.00
D)
ro
2.00
0.00
As shown in Figure 2-8, THDs for both current and voltage exhibited a diurnal trend in variation, with the
higher values occurring during the cool evening hours. These trends are consistent with the same diurnal
trends in power output and other monitored variables. The periods of higher current and power output
had higher levels of THDs.
2.3. EMISSIONS PERFORMANCE
2.3.1. IR PowerWorks System Stack Exhaust Emissions
IR PowerWorks System emissions testing was conducted to determine emission rates for criteria
pollutants (NOX, CO, and THC) and greenhouse gases (CO2 and CI^). Stack emission measurements
coincided with electrical power output and efficiency measurements. At each operating condition, three
replicate test runs were conducted, each approximately 30 minutes in duration. All testing was conducted
in accordance with EPA Reference Methods listed in Table 1-3. The IR PowerWorks System was
maintained in a stable mode of operation during each test run using PTC-22 variability criteria (Sections
2.1 and 3.2.2.1).
Emissions results are reported in units of parts per million corrected to 15 percent O2 (ppmvd @ 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
(Ib/kWhe). They were computed by dividing the mass emission rate by the electrical power generated.
2-10
-------
SRI/USEPA-GHG-VR-21
April 2003
To ensure the collection of adequate and accurate emissions data, sampling system QA/QC checks were
conducted in accordance with Test Plan specifications. These included analyzer linearity tests, sampling
system bias and drift checks, interference tests, and use of audit gases. Results of the QA/QC checks are
discussed in Section 3. The results show that DQOs for all gas species met the Reference Method
requirements. A complete summary of emissions testing equipment calibration data is presented in
Appendix A.
As described in the system efficiency performance discussion, the original set of IR PowerWorks System
performance tests were conducted on August 14, 2002 and were then repeated on August 15 after shutting
down the existing boiler. Table 2-7 summarizes the emission rates measured during each run and the
overall average emissions for each set of tests. In general, emissions of NOX, CO, and THCs were very
low during all test periods.
NOX emissions under normal system operations averaged less than 1 ppmvd corrected to 15 percent O2
and remained around 1 ppmvd after shutting down the existing boiler. The overall average NOX
emission rate, normalized to power output, was 0.000047 lb/kWhe. The benefits of lower NOX emissions
from the IR PowerWorks System are further enhanced when exhaust heat is recovered and used. Based
on annual published data by EIA, the measured IR PowerWorks System emission rate is well below the
average rate for coal and natural-gas-fired power plants in the U.S.-0.0074 and 0.0025 Ib/kWh,
respectively. The emission reductions are further increased when transmission and distribution system
losses are accounted for providing electricity to the end user.
Emissions of CO were also very low during all six test runs, averaging 0.64 ppmvd @ 15 percent O2, or
0.000021 lb/kWhe. It should be noted that these levels of NOX and CO emissions are below what is
typically considered to be the level of sensitivity of the sampling system (i.e., 2 percent of span, or about
1.28 ppmvd @ 15 percent O2). However, the average sampling system errors for NOX and CO
(determined using pre- and post-test calibrations) were 0.17 and 0.20 percent of span, respectively, during
these tests. This indicates that the sampling system sensitivity was lower than measured concentrations,
and therefore, the concentrations are reported as measured.
Emissions of THC were also very low during all test periods, averaging 1.46 ppm @ 15 percent O2, or
0.00028 lb/kWhe during the six tests conducted. Methane samples collected during these tests were
analyzed at the laboratory and results were below the detection limit (1 ppmvd) for all samples collected.
Concentrations of CO2 in the IR PowerWorks System exhaust gas averaged 1.21 percent during the three
normal site operation tests and 1.32 percent during the enhanced heat recovery tests. These
concentrations correspond to average CO2 emission rates of 1.60 lb/kWhe and 1.78 lb/kWhe, respectively.
The IR PowerWorks System CO2 emission rate 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). The U.S.
average emission factors reported here account for an estimated line loss of 5.1 percent between power
plant fence line to the end user.
2-11
-------
SRI/USEPA-GHG-VR-21
April 2003
Table 2-7. IR PowerWorks Emissions During Controlled Test Periods
Run 1
Run 2
Run3
AVG
Run 4
Run5
Run 6
AVG
c
o
1
55 O
Normal
Boilers Off
Oworall flVCS
8 1
1 | >-
ffi £ 0 !
51.69
49.8
50.37
50.62
51.95
51.76
53.31
52.34
51.48
Exhaust
02(%)
18.58
18.59
18.64
18.60
18.61
18.61
18.62
18.61
18.61
CO Emissio
(ppm@
15%02)
0.79
0.64
0.44
0.62
0.70
0.72
0.52
0.65
0.64
Ib/hr
0.0014
0.0011
0.0007
0.0011
0.0012
0.0012
0.0009
0.001 1
0.0011
IS
Ib/kWh „
2.62E-05
2.17E-05
1.48E-05
2.09E-05
2.32E-05
2.39E-05
1.71E-05
2.14E-05
2.12E-05
NO, Emissions
(ppm@
15% 02)
0.76
0.79
1.04
0.86
1.03
1.11
1.06
1.07
0.97
Ib/hr
0.0021
0.0022
0.0029
0.0024
0.0029
0.0031
0.0031
0.0030
0.0027
Ib/kWh „
4.14E-05
4.24E-05
5.62E-05
4.67E-05
5.61 E-05
6.03E-05
5.88E-05
5.84E-05
5.25E-05
THC Emissions
(ppm@
15%02)
3.69
2.60
0.85
2.38
0.38
0.49
0.76
0.54
1.46
Ib/hr
0.0036
0.0025
0.0008
0.0023
0.0004
0.0005
0.0008
0.0005
0.0014
Ib/kWh „
6.99E-05
4.85E-05
1.60E-05
4.48E-05
7.19E-06
9.25E-06
1.47E-05
1.04E-05
2.76E-05
CHi Emissions
(ppm@
15%02)
<1.00
<1.00
<1.00
<1.00
<1.00
<1.00
<1.00
1.00
<1.00
Ib/hr
< 0.0025
< 0.0025
< 0.0025
< 0.0025
< 0.0025
< 0.0025
< 0.0026
< 0.0026
< 0.0025
Ib/kWh „
<4.82E-05
<4.94E-05
<5.03E-05
<4.93E-05
<4.87E-05
<4.88E-05
<4.86E-05
<4.87E-05
<4.90E-05
CO? Emissions
%
1.22
1.19
1.21
1.21
1.31
1.32
1.32
1.32
1.26
Ib/hr
83.6
80.6
84.4
82.9
91.3
91.8
94.2
92.4
87.7
Ib/kWh „
1.62
1.56
1.63
1.60
1.76
1.77
1.81
1.78
1.69
to
K^
to
-------
SRI/USEPA-GHG-VR-21
April 2003
2.3.2. Estimation of Annual Emission Reductions for Grouse Community Center
The electricity and heat generated by the IR PowerWorks System will offset electricity supplied by the
utility grid and heat supplied by standard gas-fired boilers. As discussed in Section 1.4.5, annual emission
reductions are estimated for the Grouse Community Center with two key assumptions: first, that all
energy (power and heat) produced by the IR PowerWorks System is consumed on site; and second, that
the unit will have a 98 percent availability rate (the current availability rate quoted by site operators).
Table 2-8 summarizes estimated NOX and CO2 emissions and emission reductions from on-site
electricity production. As shown in the table, electricity production under the IR PowerWorks scenario
results in annual NOX emission reductions of 1,160 Ib. 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 IR PowerWorks. Conversely, the CO2 emission rate for the NY ISO is lower or
similar to the emission rate for the IR PowerWorks. As such, CO2 emissions increase may result when
the DG-CHP system is operated during ozone and non-ozone season weekdays. Annually, about 10,712
Ib CO2 may be reduced.
Table 2-9 summarizes estimated emissions and emission reductions for on-site heat production. IR
PowerWorks emission rates are assigned as zero because the heat recovered is otherwise waste heat, and
no emissions are associated with this process. As discussed in Section 1.4.5, boiler emission rates are
0.000538 lb/kWhth for NOX and 0.627 lb/kWhth for CO2. Annually, NOX reductions of 172 Ib and CO2
reductions of 201,031 Ib may be realized with the IR PowerWorks scenario.
Finally, Table 2-10 summarizes the annual emissions and emission reductions for both electrical and
thermal energy production systems. It is estimated that 34% reductions in NOX emissions may occur
with the DG-CHP system compared to the baseline scenario. The highest reduction is due to the
displacement of emissions from the electric utility. For CO2, an annual emission reduction of 7% may
occur. Over 95 percent of these reductions (201,031 Ib) 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.
2-13
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SRI/USEPA-GHG-VR-21
April 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 nigh!/wkend
IR CHP System Emission Rates (lb/kWhe)
NOx
0.0021
0.0028
0.0021
0.0028
Full Load
NOx
4.67E-05
CO2
1.37
1.67
1.46
1.61
CO2
1.60
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
271,581
234,674
334,977
330,492
1,171,724
271,581
234,674
334,977
330,492
1,171,724
Grid
Emissions
Ib
615
708
758
998
3,079
401,087
422,474
527,214
573,595
1,924,370
IR PowerWorks Scenario
Enerav Supplied Bv IR
Electricity
From IR
kWhe
103,847
65,219
181,882
112,038
462,987
103,847
65,219
181,882
112,038
462,987
IR
Emissions
Ib
5
3
8
5
22
166,156
104,351
291,012
179,261
740,779
Makeup Enerav
Electricity
From Grid
kWhe
103,847
65,219
181,882
112,038
462,987
103,847
65,219
181,882
112,038
462,987
Grid
Emissions
Ib
380
511
347
659
1,897
247,719
305,063
240,953
379,144
1,172,879
Total
Emissions
Ib
385
515
355
665
1,919
413,875
409,413
531,964
558,405
1,913,658
Emission
Reductions
Ib
230
194
403
333
1,160
(12,788)
13,061
(4,751)
15,190
10,712
2-14
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SRI/USEPA-GHG-VR-21
April 2003
Table 2-9. Emissions Offsets From On-Site Heat Recovery
On-Site Boiler Emission Rates (lb/kWhth)
NOX CO2
Full Load 0.000538 0.627
IR CHP System Emission Rates (lb/kWhth)
NOX CO2
Full Load 0 0
Emission Reduction Estimates From Heat Recovery
NOX
ozone season
non-ozone season
Annual Total
C02
ozone season
non-ozone season
Annual Total
Baseline Scenario
Heat From
Boiler
kWh,h
455,660
1,125,341
1,581,001
455,660
1,125,341
1.581.001
Boiler
Emissions
Ibs
245
605
851
285,899
706,083
991.982
IR PowerWorks Scenario
Energy Supplied Bv IR
Heat From IR
Cogen
kWh,h
145,458
174,942
320,400
145,458
174,942
320.400
IR
Emissions
Ib
-
-
-
-
-
Makeup Enerav
Heat from
Boiler
kWh,h
310,202
950,399
1,260,601
310,202
950,399
1.260.601
Boiler
Emissions
Ib
167
511
678
194,633
596,318
790.950
Total
Emissions
Ib
167
511
678
194,633
596,318
790.950
Emission
Reductions
Ib
78
94
172
91,266
109,765
201.031
Table 2-10. Estimated Annual Emission Reductions From DG-CHP System at Grouse
Community Center
Annual Total NOx Emissions
Annual Total COi Emissions
Baseline Scenario
Electricity
From Grid
Ib
3,079
1,924,370
Heat/DHW
from Boiler
Ib
851
991,982
Total
Baseline
Ib
3,930
2,916,352
IR PowerWorks Scenario
Enerav Su
Electricity
From IR
Ib
22
740,779
jlied Bv IR
Heat/DHW
From IR
Coaen
Ib
Makeup Enerav
Electricity
From Grid
Ib
1,897
1,172,879
Heat/DHW
from Boiler
Ib
678
790,950
Total IR Case
Ib
2,597
2,704,608
Estimated
Reductions
Ib %
1,333 34
211,744 7
2-15
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April 2003
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2-16
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SRI/USEPA-GHG-VR-21
April 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. 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. The next step is to identify all measured values which affect the verification
parameter and determine the levels of error which can be tolerated. The DQIs, most often stated in terms
of measurement accuracy, precision, and completeness, are used to determine if the stated DQOs are
satisfied. 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.
Table 3-1. Verification Parameter Data Quality Objectives
Verification Parameter
Original DQO Goal a
Relative (%) / Absolute (units)
Achieved b
Relative (%) / Absolute (units)
Power and Heat Production Performance
Electrical power output (kW)
Electrical efficiency (%)
Heat recovery rate (MBtu/hr)
Thermal energy efficiency (%)
CHP production efficiency (%)
±1.5% / 1.05 kW
±1.8%/0.51%c
±2.2% / 7.50 MBtu/hrc
±2.4%/1.00%c
±1.6% /1. 12%°
±1.5% 7 0.84 kW
±1.8%/0.46%c
±0.9%/1.37MBtu/hrc
±1.3%/0.31%c
±1.1%/0.55%C
Power Quality Performance
Electrical frequency (Hz)
Power factor (%)
Voltage and current total harmonic distortion
(THD) (%)
±0.01% 70.006 Hz
±0.50% 70.50%
±1.00% 7 0.05%
±0.01% 70.006 Hz
±0.50% 7 0.50%
±1.00% 7 0.05%
Emissions Performance
CO and NOX Concentration (ppmvd)
O2 and CO2 Concentration (%)
THC and CH4 Concentration (ppmv)
CO, NOX , CO2 and CH4 Emission Rates
THC Emission Rates
Estimated NOX emission reductions for Grouse
Community Center
Estimated GHG emission reductions for Grouse
Community Center
±2.0% of span 7 0.5 ppmvd
±2.0% of span 7 0.2%
±5.0 % of span 7 2.50 ppmvwd
±12.7%c
±13.5%c
±12.7%c
±12.7% c
±0.6% of span 70.15 ppmvd
±0.6% of span 7 0.1%
±1.4% of span 7 0.70 ppmvw
±1.66%c
±2.09% c
±1.66%c
±1.66%c
a Absolute errors based on anticipated values where applicable
0 Absolute errors based on average values measured during verification
0 Calculated composite error described in text
Parts per million by volume, wet (ppmvw)
3-1
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SRI/USEPA-GHG-VR-21
April 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 discussion
illustrates that all DQI goals were achieved and, thus, all DQOs were met or exceeded for all verification
parameters.
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 and emission rate data for three test runs conducted at different load
conditions. As stated earlier, the Test Plan specified a total of four loads. Since this was not possible, the
only two conditions tested were full power turbine operation with normal site heat recovery operations
and full power with enhanced heat recovery potential. Completeness results for controlled test periods are
reported here based on these two operating conditions.
Completeness goals for the extended tests were to obtain 90 percent of 5 days of power quality, power
output, fuel input, and ambient measurements. This goal was exceeded, and nearly six complete days of
valid data were collected (a total of 10 minutes of data were invalidated when the microturbine shut down
momentarily). As discussed in Section 2, these data were useful in establishing trends in power and heat
performance capability at varying ambient temperatures.
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-21
April 2003
Table 3-2. Summary of Data Quality Goals and Results
Measurement Variable
IR
PowerWorks
System
Power Output
and Quality
IR
PowerWorks
System Heat
Recovery
Rate
Ambient
Conditions
Power
Voltage
Frequency
Current
Voltage THD
Current THD
Power Factor
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
Controlotron
Model 1010EP
GC/FID
RTD/Vaisala
Model HMD
60YO
Vaisala Model
PTB220 Class B
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%
37 to 356 °F
37 to 356 °F
1 to 300,000
gpm
PGConc: 10 to
20%
-50 to 150°F
13.80 to 14.50
psia
0 to 100% RH
Range
Observed in
Field
0 to 60 kW
0 to 220 V
59.908 to 60.070
Hz
0 to 80 A
0 to 100%
0 to 100%
0 to 100%
134 to 176 °F
156 to 195 °F
15.7 to 16.5 gpm
PGConc: 15.7-
16.5 %
25 to 65 ° F
13.90 to 14.20
psia
27 to 98% RH
Accuracy a
Goal
±1.50% reading*
±0.1% reading
±0.0% reading
±0.1% reading
±% FSC
±1%FS
±0.5% reading
Temps must be
±1.5°Fofref.
Thermocouples
±1.0% reading
PGConc: ±3%
relative error
±0.2 °F
±0.1% FS
±2%
Actual
±1.50% reading"
±0.1% reading
±0.01% reading
±0.1% reading
±1%FS
±1%FS
±0.5% reading
±0.4 °F
±0.33% reading
PGConc: ±2.6%
relative (0.39%
absolute)
±.0.2 °F
±0.05% FS
±0.2%
How Verified /
Determined
Instrument calibration
from manufacturer just
prior to testing
Independent check
with calibrated
thermocouples
Instrument calibration
from manufacturer just
prior to testing
Independent check
with one blind sample
Instrument calibration
from manufacturer just
prior to testing
Completeness
Goal
controlled
tests: three
valid runs per
load meeting
PTC 22
criteria
extended test:
90% of one-
minute
readings for
five days
controlled
tests: three
valid runs at
each load
extended test:
90% of one-
minute
readings for
five days
controlled
tests: three
valid runs at
each load
extended test:
90% of one-
minute
readings for
five days
Actual
controlled
tests: six
valid runs at
full load
only
extended
test: 99.9 %
of one-
minute
readings for
six days
controlled
tests: six
valid runs at
full load
only
extended
test: 99.9 %
of one-
minute
readings for
six days
controlled
tests: six
valid runs at
full load
only
extended
test: 99.9 %
of one-
minute
readings for
six days
(continued)
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SRI/USEPA-GHG-VR-21
April 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 Levels
CO2 Levels
O2 Levels
Instrument Type /
Manufacturer
Mass Flow Meter /
Rosemount 3095 w/
1195 orifice
Pressure Transducer
/ Rosemount or
equiv.
RTD / Rosemount
Series 68
Gas Chromatograph
/HP 589011
Chemiluminescent/
TEI Model 10
NDIR / TEI Model
48
FID /TEI Model 51
NDIR / IR Model
703
NDIR / IR Model
2200
Instrument
Range
0 to 20 scfm
0 to 100 psig
-58 to 752 °F
0 to 100% CH4
0 to 25 ppmvd
0 to 25 ppmvd
0 to 50 ppmv
0 to 10%
0 to 25%
Measurement
Range
Observed
0 to 13 scfm
69 to 7 1 psig
30 to 70 °F
90 to 95% CFL,
907to916Btu/ft3
0 to 3 ppmvd
0 to 5 ppmvd
0 to 5 ppmvd
1.0 to 1.5%
18 to 19%
Accuracy
Goal
1.0% of
reading
±0.75% FS
±0.10% reading
±0.2% forCH,
concentration
±0.2% for
LHV
± 2% FS or
± 0.5 ppmvd
± 2% FS or
±0.5 ppmvd
± 5% FS or
±2.5 ppmvd
± 2% FS or
± 0.2%
± 2% FS or
± 0.5%
Actual
±1.0% of
reading
±0.75% FS
±0.09% reading
±0.20% forCH,
concentration
±0.01%
overall average
LHV
< 0.6% FS or
±0.15ppmvdd
< 0.6% FS or
±0.15ppmvdd
< 1.4%FSor
± 0.8 ppmvd d
< 0.6% FS or
± 0.06% d
< 0.4% FS or
±0.10%d
How Verified /
Determined
Factory calibration of
differential pressure sensor
and orifice plate bore
Instrument calibration
from manufacturer prior to
testing
Analysis of NIST-
traceable CFLt audit gas
Conducted duplicate
analyses on 1 sample
Calculated following EPA
Reference Method
calibrations (Before and
after each test run)
Completeness
Goal
controlled
tests: one
minute
readings for
all runs
extended
test: 99.9 %
of one-
minute
readings for
six days
controlled
tests: one
valid sample
per load
controlled
tests: three
valid runs
per load
Actual
Controlled
tests: one
minute
readings
for all
runs
extended
test: 99.9
% of one-
minute
readings
for six
days
Controlled
tests: one
valid
sample per
load
Controlled
tests: six
valid runs
at full load
only
Accuracy goal represents the maximum error expected at the operating range. It is defined as the sum of instrument and sampling errors.
Includes instrument, 1.0% current transformer (CT), and 1.0% potential transformer (PT) errors.
f'k: full scale
Values represent the maximum system error observed throughout the controlled test periods.
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SRI/USEPA-GHG-VR-21
April 2003
3.2.1. Power Output
Precise determination of electric power generated by the IR PowerWorks System is required because it is
a key verification parameter for the turbine. 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. To determine if the power output DQO was met, the Test Plan specified factory calibration of
the ION 7600 with a NIST-traceable standard. The Test Plan also required the GHG Center to perform
several reasonableness checks in the field to ensure that the meter was installed and operating properly.
The following summarizes the results.
The meter was factory calibrated by Power Measurements approximately one month prior to being used
at the test site. Calibrations were conducted in accordance with Power Measurements strict standard
operating procedures (in compliance with ISO 9002:1994) and are traceable to NIST standards. The
meter was 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 meter indicated that its 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, the error during all testing is determined to be ±0.84 kW.
After installation of the meters at the site and prior to the start of the verification test, additional QC
checks were performed in the field to verify the operation of the electrical meter. 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.
Based on these results, it was concluded 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-21
April 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
Comparison with in-line
facility gas meter
Calibration with gas
standards by laboratory
Independent
performance check with
blind audit sample
Meter zero check
Fluid index check
Independent
performance check of
temperature readings
When
Performed/Frequency
Beginning and end of test
Throughout test
Beginning and end of test
During controlled tests
Prior to analysis of each
lot of samples submitted
One time during test
period
Prior to testing
Each day of testing
Beginning of test period
Expected or Allowable
Result
Voltage and current checks
within ± 1 % reading
Readings should be between
63 and 70 kW at full load
Pass
Difference of ±3% between
the two meters differential
pressures
±1 .0% for each gas
constituent
±3.0% for each gas
constituent
Reported heat recovery
< 0.5 Btu/min
±5.0% of reference value
Difference in temperature
readings should be < 1 .5 °F
Results Achieved
±0.43% voltage
±1.2% current
Readings were 50 to 60
kW, due to extremely warm
weather
Passed all diagnostic
checks
Meters agreed within
+0.3%
Results satisfactory, see
Section 3. 2. 2. 4
Reported heat recovery was
< 0.5 Btu/min
Index check was within
±0.5% of reference value
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 ±1.50
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 ±0.84 kW.
3-6
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SRI/USEPA-GHG-VR-21
April 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. In this case, the specifications were satisfied, and therefore the ±1 percent of reading DQI was met.
The average flow rate at full load was 12.49 scfm, and the measurement error is then determined to be
±0.12 scfm. A second assessment of measurement accuracy was conducted in the field by comparing the
integral orifice meter reading with a calibrated, in-line, dry-gas meter. The comparison between the
orifice meter and the dry-gas meter readings resulted in an overall average difference of ±0.3 percent
during the test periods. Complete documentation of data quality results is provided in Section 3.2.2.3.
The Test Plan specified using the results of analysis of a blind audit gas and duplicate analysis to
reconcile the accuracy of LHV determination. The primary gas composition DQI is the accuracy of the
methane portion of the blind audit sample (methane represents about 95 percent of the gas composition).
Methane results of the blind audit sample were within 0.2 percent of the certified concentration. The
percent difference between the original and duplicate analyses was ±0.01 percent (Section 3.2.2.4). As
such, the LHV goal of ±0.2 percent was met. During testing, the average LHV was verified to be 915
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 = ^(flowmetererrorf + (LHVerrorf (Eqn. 9)
(0.002Y = 0.0102
At the average measured heat input of 683.7 MBtu/hr, the measurement error amounts to approximately
±697 Btu/hr, or 1.02 percent relative error.
For the electrical efficiency determination, the errors in the divided values compound similarly. The
electrical power measurement error is ±1.5 percent relative (Table 3-2) and the heat input error is ±0.36
percent relative. Therefore, compounded relative error for the electrical efficiency determination is:
Error in Elec. Power Efficiency = ^(powermetererror^ + (heatinputerror^ (Eqn. 10)
+
(0.0102^ = 0. 0181
This means that for the controlled test periods, electrical power efficiency was 25.3±0.46 percent, or a
relative compounded error of 1.81 percent. This compounded relative error is the data quality objective
for this verification parameter.
3.2.2.1. PTC-22 Requirements for Electrical Efficiency Determination
Per PTC-22 guidelines, 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
3-7
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SRI/USEPA-GHG-VR-21
April 2003
temperature during each test run. As shown in the table, the requirements for all parameters were met for
all test runs. Thus, it can be concluded that the PTC-22 requirements were met and the efficiency
determinations are representative of stable operating conditions.
Table 3-4. Variability Observed in Operating Conditions
Maximum Allowable
Variation
Runl
Run 2
Run 3
Run 4
Run 5
Run 6
Maximum Observed Variation" in Measured Parameters
Power
Output (%)
±2
2.0
1.3
2.0
1.0
0.7
0.8
Power Factor
(%)
±2
.3
.3
.9
0.9
.3
.4
Fuel Flow
Rate (%)
±2
1.1
1.2
1.4
0.8
0.7
0.5
Inlet Air
Press. (%)
±0.5
0.03
0.08
0.02
0.02
0.01
0.01
Inlet Air
Temp. (°F)
±4
0.3
2.0
2.4
2.3
2.0
1.2
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 prior to the verification testing using reference materials traceable to NIST standards.
Results of these calibrations indicate that the ±2 °F accuracy goal for temperature, ±0.1 percent for
pressure, and ±2 percent 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 IR PowerWorks 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, and 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
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 IR PowerWorks Operators Manual.
Finally, a dry gas meter (Roots Model 2M175 SSM Series B3 rotary positive displacement meter
manufactured by DMD-Dresser), installed in series with the GHG Center's orifice meter, was used to
independently verify the Rosemount flow meter output. The dry gas meter was calibrated by the local
utility (NYSEG) using a volume prover, and the meter calibration proof was within 99.0 percent at full
3-8
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SRI/USEPA-GHG-VR-21
April 2003
scale. During the field testing, dry gas meter readings were obtained and compared with the Rosemount
flow data. The dry gas meter flow rates were computed by taking manual dry gas meter readings over a
period of time [in units of actual cubic feet (acf)], and then correcting the dry gas meter readings to
standard conditions. Actual gas pressure and temperature measurements were used to make these
corrections as shown in Equation 11.
Dry Gas Meter Reading (scf) = Gas Volume Measured (acf) * (Tstd/Tg) * (Pg/Pstd) * Cm (Eqn. 11)
where:
Tstd = standard temperature (519.67 °R)
Tg = measured gas temperature (°R)
Pg = measured gas pressure (psia)
Pstd = standard pressure (14.696 psia)
Cm = meter calibration coefficient (1.00)
The standardized gas volume was then divided by the duration of the sampling interval to yield average
gas flow in scfm. These values were then compared to the average gas flow rate recorded by the integral
orifice meter during the same period. The results of these field comparisons between the integral orifice
meter and the in-line dry gas meter are presented in Table 3-5. On average, the integral orifice flows
were 0.3 percent lower than dry gas meter readings.
Table 3-5. Comparison of Integral Orifice Meter With Dry Gas Meter During Controlled Testing
Test
Condition
(% of
Rated
Power)
100
Run
ID
1
2
3
Integral
Orifice
Meter
(scfm)
12.59
12.39
12.48
Gas
Pressure
(psia)
15.92
15.94
15.94
Gas
Temp.
(°F)
77.30
80.90
84.50
Dry Gas
Meter
(acfm)
11.97
11.83
12.03
Dry Gas
Meter
(scfm)
12.62
12.41
12.54
Overall Average
Absolute
Difference"
(scfm)
-0.03
-0.02
-0.06
-0.04
Relative
Difference1"
(%)
-0.27
-0.15
-0.44
-0.29
a Integral Orifice Reading - Dry Gas Reading
b ( Integral Orifice Reading - Dry Gas Reading ) /Dry Gas Reading ] x 100
3.2.2.4. Fuel Lower Heating Value
Fuel gas samples were collected no less than once per test condition. 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 Core Laboratories
of Houston for compositional analysis and determination of LHV per ASTM test methods D1945 (ASTM
2001a) and D3588 (ASTM 2001b), respectively. A total of four valid samples were collected and
analyzed, three during the controlled test periods and one during the six-day extended monitoring period.
The DQI goals were to measure methane concentration that was within ±0.2 percent of a NIST-traceable
calibration gas and a certified audit gas and to achieve less than ±0.2 percent difference in LHV duplicate
analyses results.
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The GC/FID was calibrated daily using a continuous calibration verification standard (NIST-traceable)
and upper and lower control limits maintained by Core Laboratory. Copies of the GC/FID calibration
records are maintained at the GHG Center and indicate that instrument responses were well within the
control limits for all analyses conducted. A certified natural gas audit sample was submitted to Core
Laboratory, and its results were reviewed to determine analytical error and repeatability for major gas
components. Results of the audit sample, summarized in Table 3-6, show acceptable accuracy for major
gas components. High levels of error were evident only on components that were present in very low
concentrations (e.g., n-butane and n-hexane) and carbon dioxide. The results also show that the ±0.2
percent goal for methane concentration was achieved.
Table 3-6. 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 (%)
5.01
1.12
70.27
8.87
5.99
2.95
2.99
0.97
0.96
Combined Sampling
and Analytical Error
(%)•
0.2
10.9
0.2
1.6
0.7
2.0
0.7
4.0
5.0
a Calculated as: Error = (certified cone. - analytical result) / certified cone. * 100
Duplicate analyses were conducted on one of the samples collected during the control test periods (the
sample collected during Run 3 on August 14). Duplicate analysis is defined as the analyses performed by
the same operating procedure and using the same instrument for a given sample volume. Results of the
duplicate analyses showed an analytical repeatability of 0.06 percent for methane (results were 96.40 and
96.34 mol % CFL,), and 0.01 percent for LHV (results were 911.7 and 911.6 Btu/scf). The results
demonstrate that the ±0.2 percent LFfV accuracy goal was achieved.
3.2.3. Heat Recovery Rate
Heat recovery efficiency is the heat recovered divided by the turbine fuel heat input. Precise
determination of the heat recovery rate is required because it is a key performance parameter for the CHP
system. A Controlotron heat meter was used that determines the heat recovery rate by measuring the
glycol solution heat exchanger temperature difference (delta T) and the flow rate. It then multiplies delta
T, flow rate, glycol solution specific heat, and density to yield the heat recovery rate. Earlier, Tables 3-2
and 3-3 showed that the DQIs achieved for delta T and PG flow rate were achieved (0.4 °F temperature
accuracy for each sensor (0.8 °F for temperature differential) and 0.33 percent accuracy for flow rate. For
a given glycol concentration (volume percent), the manufacturer specifies an overall heat recovery rate
accuracy of ±2.0 percent. The meter obtains specific heat and density data from an internal "look up"
table, based on ASHRAE data (Appendices A-9, A-10; ASHRAE 1997) and the measured glycol solution
volume percent as input by the Field Team Leader at the beginning of the test campaign.
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April 2003
The Test Plan specified that the GHG Center would collect and analyze glycol solution samples from the
CHP system prior to and during the testing. Using results of the preliminary analyses, the Field Team
Leader computed the average volume percent glycol and programmed this into the heat meter. As shown
in Table 3-2, the laboratory's relative analytical error for the glycol concentration was ±2.6 volume
percent. This means that, for the average percent glycol solution of 15.0 percent, actual concentration
could range between 15.4 and 14.6 percent. This range is based on a measured absolute error of ±0.39
percent, which was determined using the analytical results of a blind audit sample submitted to the
laboratory by the Center. Because specific heat and density vary with different glycol compositions, the
laboratory analytical error will introduce additional error into the heat meter's heat recovery rate
determination. However, example calculations in the Test Plan showed that an absolute PG analytical
error of 3 percent contributed a combined density and specific heat error of only 0.79 percent. Since
analytical accuracy was much better during this test (absolute error of only 0.39 percent on PG
concentration), the error introduced into the heat recovery calculation is considered negligible and not
included in propagation of the overall error in heat recovery rate.
With this, the overall error in heat recovery rate is then the combined error in PG temperature and flow
rate measurements. This error compounds multiplicatively as follows:
Overall Heat Meter Error = ^(Flowrateerrorf + (temperatureerrorf (Eqn. 12)
= A/(0.0033)2+(0.008)2 = 0.0087
Given this, the average heat recovery rate was 157,982±1374 Btu/hr, or a relative compounded error of
±0.87 percent.
For the heat recovery efficiency determination, the errors in heat recovery rate and heat input compound
similar to Equation 10 as follows:
Error in Heat Re cov ery Efficiency = ^(G.0087)2+(0.0102)2 =0.0134 (Eqn. 13)
This means that for the controlled test periods, average heat recovery rate (thermal) efficiency was
23.0±0.31 percent, or a relative compounded error of 1.34 percent. This compounded relative error meets
the quality objective for this verification parameter.
3.2.4. Total Efficiency
Total efficiency is the sum of the electrical power and heat recovery efficiencies. Continuing from the
determined errors in electrical and thermal efficiency, average total efficiency is defined as 25.3±0.46
percent (±1.81 percent relative error) plus 23.0±0.31 percent (±1.34 percent relative error). For additive
errors, the absolute errors compound as follows (EPA 1999):
err , =
V erri
= V0.462+0.312 =0.55 percent absolute error
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April 2003
Relative error, then, is:
errc,rel = —j ^~, (ECP. 15>
Valuel + Value2
0.55
25.3 + 23.0
where:
= 1.14 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 average total efficiency is 48.3±0.55 percent, or 1.1 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
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 accuracy occur
throughout the emissions tests. The DQOs specified in the Test Plan were based on the requirements of
the Reference Methods. Specifically, these include overall accuracies of ±0.50 ppmvd for NOX and CO,
±2.50 ppmvd for THC and CH/t, and ±0.4 percent for CO2 and O2. The data quality indicator goals
required to meet the DQO consisted of an assessment of sampling system error (bias) and drift for NOX
and THC and of bias and drift for CO, CO2, and O2.
NOX and THC
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.
As shown in Table 3-2, the system calibration error goal for NOX was ±0.50 ppmvd, and the maximum
actual measured error was ±0.15 ppmvd, which indicates the goal was met. For THC, the maximum
system error was determined to be ±0.8 ppmvw, which is within the ±2.50 ppmvw goal. The system error
and drift are calculated only for the mid-level calibration gas based on following Method 25A
requirements.
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The NOX analyzer used for all tests had a full-scale range of 0 to 25. The NOX analyzer was calibrated
with certified concentrations 0, 6.26, 12.9, and 23.0 ppmvd NOX at the beginning of each day to establish
linearity. Results of these calibrations (Appendix A-l) indicate excellent instrument linearity with
calibration errors of 1.6 percent of span or less.
At the conclusion of each test, zero and mid-level calibration gases were again introduced to the sampling
systems at the probe and the response recorded. System response was compared to the initial system
calibration error to determine sampling system drift. The maximum sampling system drift was
determined to be 0.1 ppmvd for NOX and 0.7 ppmvw for THC, which were both 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.
Two additional QC checks were performed to better quantify the NOX data quality. In accordance with
Method 20, an interference test was conducted once on the NOX analyzer before the testing started. This
test confirms that the presence of other pollutants in the exhaust gas do not interfere with the accuracy of
the NOX analyzer. This test was conducted by injecting the following calibration gases into the analyzer
and recording the response of the NOX analyzer, which must be zero ±2 percent of span (or 0.50 ppmvd).
• CO - 602 ppmvd in balance nitrogen (N2)
• SO2 - 251 ppmvd in N2
• CO2 - 9.9 percent in N2
• O2 - 20.9 percent in N2
As shown in Table 3-7, the maximum measured value was well below the 0.50 ppmvd required by the
Method.
The NOX analyzer converts any NO2 present in the gas stream to NO prior to gas analysis. The second
QC check consisted of determining NO2 converter efficiency prior to beginning of emissions 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. If the NO2 to NO conversion is 100 percent
efficient, the response will be stable at the highest peak value observed. If the response decreases by
more than 2 percent from the peak value observed during the 30-minute test period, the converter is faulty
and the analyzer must be either repaired or replaced prior to testing. As shown in Table 3-7, the converter
efficiency was measured to be 100 percent.
As an additional QC check for low-range NOX measurements, the GHG Center provided an EPA
Protocol mixture of 2.49 ppmvd NOX in N2 as an audit of ENSR International's sampling system. The
gas was introduced to the sampling system as a blind audit, and the system response was recorded by
Center personnel. A stable system response of 2.56 ppmvd was recorded, corresponding to a system error
of 0.28 percent of span.
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Table 3-7. Additional QA/QC Checks for Emissions Testing
Parameter
NOX
CO, C02,
O2
THC
QA/QC Check
Blind audit sample
NO2 converter
efficiency
Sampling system
drift checks
Analyzer calibration
error test
Calibration drift test
System calibration
drift test
When
Performed/Frequency
Once during testing
Once before testing
begins
Before and after each
test run
Daily before testing
After each test
After each test
Expected or
Allowable Result
±2% of analyzer
span or less
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
System error was 0.28% of span
100.0%
0.4% of span or 0. 10 ppmvd
CO: 1 .2% of span or 0.30 ppmvd
CO2: 1 .2% of span or 1 .2 % absolute
O2: 0.8% of span or 0.2 % absolute
CO: 0.5% of span or 0. 1 3 ppmvd
CO2: 0.9% of span or 0.09 % absolute
O2: 0.3% of span or 0.08 % absolute
1 .4% of span or 0.70 ppmvd
a See Appendix A for individual test run results
CO. COZ. and Oz
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: zero, 40 to 60 percent of span, and 80
to 100 percent of span. Four gases were used for CO: zero and approximately 30, 60, and 90 percent of
span. The analyzer calibration errors for all gases were below the allowable levels, as shown in Table 3-
7.
Before and after each test run, zero and mid-level calibration gases were introduced to the sampling
system at the probe, and the response was recorded. System bias was calculated by comparing the system
responses to the calibration error responses recorded earlier. As shown in Table 3-2, the system bias goal
for all gases was achieved: ±0.50 ppmvd for CO, ±0.40 percent (absolute) for CO2, and ±0.15 percent
(absolute) for O2. Consequently, the DQO was satisfied.
The pre- and post-test system bias calibrations were also used to calculate sampling system drift for each
pollutant. As shown in Table 3-7, the maximum drift measured was 0.5 percent of span for CO, 0.9
percent for CO2, and 0.3 percent for O2. In conclusion, the drift goals were also met for all pollutants.
Results of each of the analyzer and sampling system calibrations conducted, including linearity tests and
sampling system bias and drift checks, are presented in Appendix A.
Determination of Error in Emission Rate Determinations
Error in determination of emission rates in units of Ib/kWh is derived from the errors in each of the
contributing measurements including pollutant concentrations, oxygen concentrations, and power output.
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April 2003
The Test Plan specified an emission rate DQO for NOX, CO, and CO2 collectively of 12.7 percent
relative error and a THC DQO of 13.5 percent relative error. The highest concentration error in the NOX,
CO, and CO2 measurements was 0.6 percent of full scale (0.15 ppmvd absolute,) and the error in THC
concentration measurements was 1.4 percent of full scale, or 0.8 ppmv absolute. Compounding these
errors with the error in measurement of O2 concentrations (0.4 percent of full scale, or 0.10 percent
absolute), and the power output error (1.50 percent), the emission rate compounded error then computed
as:
Error in EmissionRates = ^(C.006)2 +(0.004) + (0.0150)2 = 0.0166 (Eqn. 16)
The error in NOX, CO, and CO2 emission rate determinations is then 1.66 percent. The error in THC
emission rates is 2.09 percent. Both are well within the goals set for emission rate determinations.
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4.0 TECHNICAL AND PERFORMANCE DATA SUPPLIED BY INGERSOLL-RAND
ENERGY SYSTEMS
Ingersoll-Rand (IR) appreciates the comprehensive and thorough testing effort evident in this report and
the well-qualified insights it yields into various aspects of the performance of the PowerWorks 70kW
microturbine. As the report shows, the electrical generation and heat recovery performance of the unit
under test do not match our production criteria, but other performance metrics such as emissions and
electrical power quality are favorable.
4.1. SYSTEM CONFIGURATION
First we would like to note that the unit tested at the Grouse Community Center was an early pre-
production model that has not been updated to the production units we manufacture today. As with its
other industrial and commercial products, IR continues to improve its microturbine line and expand its
capability to meet the needs of its customers. Therefore, a continuous program of improvements in
capability, performance, and quality is always underway and this effort addresses the kinds of issues
raised in the report as described below.
4.2. ELECTRICAL PERFORMANCE
During the ETV tests, the microturbine was producing about 53 to 50 kW of power under ambient
conditions ranging from 76 to 86 °F. The tests also revealed an electricity generating efficiency in the
range of 25.8 to 25.1 percent LHV. With a production machine we would expect typical ranges of 65 to
60 kW and 27.2 to 26.6 percent efficiency for ambient temperatures in this range (gas turbine power and
efficiency drop with increased ambient temperature).
IR's production acceptance criteria for power output are ±5 kW and ±2 points efficiency respectively.
Therefore, the measurements represent performance below the criteria we would normally allow. This
was due to three factors.
• The testing occurred at ambient pressures that were measured at 14.01 to 14.07 psia.
Gas turbine engine power varies directly in proportion to ambient pressure.
Therefore, a comparison of measured power output to rated power output at ISO
conditions must also account for ambient pressure. In this case, the ratio of the
average value (14.035 versus 14.696) equates to a 0.955 drop in power or around 4.5
percent or 3 kW.
• The tested configuration included a compressor diffuser with substandard
performance. IR has since switched to a new design whose net effect is to increase
system power output by about 6 kW.
• We have found measurement errors of the Turbine Inlet Temperature (TIT) operating
point in earlier machines. These errors would result in the microturbine producing up
to 5 kW less power.
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April 2003
4.3. COGENERATION PERFORMANCE
The ETV test revealed that approximately 140 MMBtu/hr (170MMBtu/hr when the facility boilers were
turned off) of heat was captured for cogeneration use. The higher heat capture rate reflects the expected
additional gain when inlet water temperature lowers. With a production unit we would expect higher heat
capture rates, more in the range of 200 MMBtu/hr at 170.8 °F entering water temperature and 240
MMBTU/hratl36°F.
The Heat Recovery Unit (HRU) used in the tested system had a supplier defect which allowed fin
separation from the water passage tubes. This separation significantly reduced heat transfer capability
from the exhaust to the water, which lead to less heat capture in the water. The HRUs now employed in
our production units have resolved this issue.
4.4. ELECTRICAL POWER QUALITY
Since this machine employs an induction generator, it completely relies on the utility grid to regulate
frequency and voltage. Therefore, the variations shown in the test data are completely controlled by the
power quality of the electrical power in the facility.
With regards to power factor and Total Harmonic Distortion (THD), the measured values fall within the
typical range expected in this kind of application.
4.5. EMISSIONS AND THE FUEL SYSTEM
The ETV report shows that PowerWorks NOX, CO, and THC emissions are quite low both from an input
basis (ppmv corrected to 15% O2) and an output basis (Ibs/kWh). For example, the average measured full
load NOX values of 0.000047 Ib/kWh are an order of magnitude below the newly enacted California Air
Resources Board (CARB) limits of 0.0005 Ibs/kWh (2003 limits) for Distributed Generation systems,
even without accounting for NOX reduction when operating in part load conditions.
Another important element of the PowerWorks design is the fully integrated fuel gas booster. As noted in
the report, the booster design is based on a fully sealed industrial screw compressor. Since the fuel
booster system is included in the microturbine enclosure, no high-pressure gas lines are required between
the microturbine and an outside component. This enhances safety and eliminates potential sources of
leaks. In addition, special attention has been paid to the ventilation design of the microturbine enclosure
and the venting design of the fuel system to avoid potentially dangerous concentrations of fuel gas.
Therefore, the PowerWorks microturbine is fully qualified for indoor use.
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April 2003
5.0 REFERENCES
40CFR60. Standards of Performance for Stationary Gas Turbines. Title 40 of the Code of Federal
Regulations, Part 60, Subpart GG. United States Environmental Protection Agency. Washington, DC.
1999.
ANSI 1996. 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.
ANSI/ASHRAE Standard 125. Method of Testing Thermal Energy Meters for Liquid Streams in HVAC
Systems. ANSI/ASHRAE 125. American National Standards Institute/American Society of Heating,
Refrigerating and Air-Conditioning Engineers, Atlanta, GA. 1992.
American National Standards Institute / 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.
ASHRAE 1997. Physical Properties of Secondary Coolants (Brines), F20IP, Chapter 20, American
Society of Heating, Refrigerating, and Air-Conditioning Engineers, Atlanta, GA. 1997.
ASME PTC-22. Performance Test Code on Gas Turbines. PTC-22-1997. American Society of
Mechanical Engineers, New York, NY. 1997.
ASTM 200 la. Standard Test Method for Analysis of Natural Gas by Gas Chromatography. ASTM
D1945-9GRI. American Society for Testing and Materials, West Conshohocken, PA. 2001.
ASTM 200Ib. Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative
Density of Gaseous Fuels. ASTM D3588-98. American Society for Testing and Materials, West
Conshohocken, PA. 2001.
CBEC 2000. Commercial Buildings Energy Consumption Survey - 1995. DOE/EIA. Department of
Energy, Washington, DC. October 1998.
DOE 1995. The Final Report on Fuel Cells for Building Cogeneration Applications - Cost/Performance
Requirements and Markets. United States Department of Energy, Office of Building Technologies.
Washington, DC. 1995.
DOE/EPA 2000. Carbon Dioxide Emissions From the Generation of Electric Power in the United States.
http://www.eia.doe.gov/cneaf/electricity. U.S. Department of Energy/U.S. Environmental Protection
Agency, Washington, DC. July 2000.
EIA2000a. Electric Power Annual 1999, Volume II. DOE/EIA-0348(99)/2. U.S. Department of Energy,
Washington, DC. October 2000.
EIA 2000b. Energy Information Administration, Annual Electric Utility Data (EIA-861 data file),
http://www.eia.doe.gov/cneaf/electricity. 2000.
5-1
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SRI/USEPA-GHG-VR-21
April 2003
EPA 1995. Compilation of Air Pollutant Emission Factors, AP-42, Fifth Edition, Volume 1. Stationary
Point and Area Sources. United States Environmental Protection Agency. Washington, B.C. 1995.
IEEE 519. Recommended Practices and Requirements for Harmonic Control in Electrical Power
Systems. Standard 519-1992. Institute of Electrical and Electronics Engineers. New York, NY. April
1993.
ISO 9002:1994. Quality systems - Model for quality assurance in production, installation and servicing.
International Organization for Standardization, Geneva, Switzerland. June 30, 1994.
OTC 2002. The OTC Emission Reduction Workbook 2.1: Description and User's Manual. Ozone
Transport Commission, Washington, B.C. November 2002.
SRI 2002. Test and Quality Assurance Plan 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. March 2002.
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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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April 2003
Appendix A-l. Summary of Daily Reference Method Calibration Error Determinations
Range Value
Date Gas (ppm for NOX, CO, and
8/14/02 NOX 25 0.00
(Runsi -3) 6.26
12.90
23.00
CO 25 0.00
6.00
14.00
24.30
CO2 10 0.00
4.42
9.11
O2 25 0.00
11.09
20.90
THC 50 0.00
14.82
23.94
48.00
8/15/02 NOX 25 0.00
(Runs 4 -6) 6.26
12.90
23.00
CO 25 0.00
6.00
14.00
24.30
CO2 10 0.00
4.42
9.11
O2 25 0.00
11.09
20.90
THC 50 0.00
14.82
23.94
48.00
Response
THC; % for O2
na
na
na
na
0.02
5.85
14.00
24.60
0.12
4.40
9.05
0.03
11.07
20.70
na
na
na
na
na
na
na
na
0.03
5.92
13.90
24.50
0.11
4.43
9.04
0.04
11.12
20.70
na
na
na
na
Response
and CO2)
0.01
6.27
13.2
23.4
na
na
na
na
na
na
na
na
na
na
0.14
15.6
24.2
48.9
0.02
6.22
13.2
23.3
na
na
na
na
na
na
na
na
na
na
0.14
14.55
23.3
47.8
Calibration
Error (% of Span)
0.04
0.04
1.2
1.6
0.08
0.6
0.0
1.2
1.2
0.2
0.6
0.1
0.08
0.8
na
2.96
1.06
na
0.08
0.02
1.2
1.2
0.1
0.3
0.4
0.8
1.1
0.1
0.7
0.16
0.1
0.8
na
2.02
2.62
na
A-2
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Appendix A-2. Summary of Reference Method System Bias and Drift Checks
Analyzer Spans: NOX = 25 ppm, CO = 25 ppm, THC = 50 ppm, CO2 = 10%, O2 = 25%
NOX Zero System Response (ppm)
System Error (% span)
Drift (% span)
NOX Mid System Response (ppm)
System Error (% span)
Drift (% span)
CO Zero System Response (ppm)
System Error (% span)
Drift (% span)
CO Mid System Response (ppm)
System Error (% span)
Drift (% span)
CO2 Zero System Response (ppm)
System Error (% span)
Drift (% span)
CO2 Mid System Response (ppm)
System Error (% span)
Drift (% span)
O2 Zero System Response (ppm)
System Error (% span)
Drift (% span)
O2 Mid System Response (ppm)
System Error (% span)
Drift (% span)
THC Zero System Response (ppm)
System Error (% span)
Drift (% span)
THC Mid System Response (ppm)
System Error (% span)
Drift (% span)
Initial
Cal
0.01
0.00
na
6.27
-0.10
na
0.10
0.30
na
5.84
0.00
na
0.11
-0.20
na
4.35
-0.40
na
0.10
0.30
na
11.15
0.30
na
0.14
0.30
na
15.64
1.60
na
Run Number
1
0.03
0.10
0.10
6.24
-0.20
-0.10
-0.30
-0.20
-0.50
5.86
0.00
0.10
0.15
0.20
0.40
4.38
-0.20
0.30
0.10
0.20
0.00
11.14
0.20
-0.10
0.19
0.40
0.10
15.62
1.60
-0.10
2
0.00
-0.10
-0.10
6.24
-0.20
0.00
0.00
-0.10
0.10
5.78
-0.30
-0.30
0.11
-0.20
-0.40
4.43
0.30
0.50
0.06
0.10
-0.10
11.12
0.20
-0.10
0.15
0.30
-0.10
15.62
1.60
0.00
3
0.03
0.00
0.10
6.14
-0.60
-0.40
-0.02
-0.10
-0.10
5.70
-0.60
-0.40
0.12
0.00
0.10
4.34
-0.60
-0.90
0.11
0.30
0.20
11.09
0.00
-0.20
0.12
0.20
-0.10
15.51
1.40
-0.20
4,5,6
0.03
0.10
0.00
6.20
-0.30
-0.10
-0.07
-0.40
-0.30
5.91
0.00
0.40
0.11
-0.20
-0.20
4.34
-0.60
0.00
0.15
0.40
0.20
11.19
0.30
0.30
0.15
0.30
0.10
14.61
0.00
-1.40
A-3
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