GVP - DG CHP Field Testing Protocol September 2005
Version 1.0
SRI/USEPA-GHG-GVP-04
September 2005
Generic Verification Protocol
Distributed Generation and Combined Heat
and Power Field Testing Protocol
Version 1.0
Prepared by:
Greenhouse Gas Technology Center
Southern Research Institute
Under a Cooperative Agreement With
U.S. Environmental Protection Agency
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GVP - DG CHP Field Testing Protocol September 2005
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EPA REVIEW NOTICE
This document 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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Greenhouse Gas Technology Center
A U.S. EPA Sponsored Environmental Technology Verification (ETr ) Organization
Generic Verification Protocol
Distributed Generation and Combined Heat and Power Field
Testing Protocol
Version 1.0
This Generic Verification Protocol has been reviewed and approved by the Greenhouse Gas Technology
Center director and quality assurance manager, the U.S. EPA APPCD project officer, and the U.S. EPA
APPCD quality assurance manager.
Signed by Tim Hansen
Tim A. Hansen
Director
Greenhouse Gas Technology Center
Southern Research Institute
9/22/05 Signed by David Kirchgessner
Date David Kirchgessner
APPCD Project Officer
U.S. EPA
9/23/05
Date
Signed by Richard Adamson
Richard Adamson
Quality Assurance Manager
Greenhouse Gas Technology Center
Southern Research Institute
9/22/05 Signed by Robert Wright
Date Robert Wright
APPCD Quality Assurance Manager
U.S. EPA
9/23/05
Date
GVP Version 1.0: September 2005
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Foreword
The U.S. Environmental Protection Agency (EPA) has created the Environmental Technology
Verification (ETV) program to facilitate the deployment of promising environmental technologies. Under
this program, third-party performance testing of environmental technology is conducted by independent
verification organizations under strict EPA quality assurance guidelines. Southern Research Institute
(SRI) is one of six independent verification organizations operating under ETV, and operates the
Greenhouse Gas Technology Center (GHG Center). With full participation from technology providers,
purchasers, and other stakeholders, the GHG Center develops testing protocols and conducts technology
performance evaluation in field and laboratory settings. The testing protocols are developed and peer-
reviewed with input from a broad group of industry, research, government, and other stakeholders. After
their development, the protocols are field-tested, often improved, and then made available to interested
users via Generic Verification Protocols (GVPs) such as this.
Distributed generation (DG) technologies are emerging as a viable supplement to centralized power
production. Many DG systems can be utilized in combined heat and power (CHP) applications, in which
waste heat from the generator unit is used to supply local heating, cooling, or other services. This
provides improved energy efficiency, reduced energy costs, and reduced use of natural resources. Current
and developing DG technologies include microturbines (MTGs), internal combustion generators, small
turbines, and Stirling engines. Independent evaluations of DG technologies are required to assess
performance of systems, and, ultimately, the applicability and efficacy of a specific technology at any
given site. A current barrier to the acceptance of DG technologies is the lack of credible and uniform
information regarding system performance. Therefore, as new DG technologies are developed and
introduced to the marketplace, methods of credibly evaluating the performance of a DG system are
needed. This GVP was developed to meet that need.
In December 2004 the Association of State Energy Research and Technology Transfer Institutions
(ASERTTI) issued the Interim Distributed Generation and Combined Heat and Power Performance
Protocol for Field Testing. This GVP is based largely on the ASERTTI protocol, with some additional
quality assurance/quality control procedures included as required by ETV. The ASERTTI protocol was
developed as part of the Collaborative National Program for the Development and Performance Testing
of Distributed Power Technologies with Emphasis on Combined Heat and Power Applications, co-
sponsored by the U.S. Department of Energy and members of ASERTTI. The ASERTTI sponsoring
members are the California Energy Commission, the Energy Center of Wisconsin, the New York State
Energy Research and Development Authority, and the University of Illinois-Chicago. Other sponsors are
the Illinois Department of Commerce and Economic Opportunity and the U.S. Environmental Protection
Agency Office of Research and Development.
The protocol development program was directed by several guiding principles specified by the ASERTTI
Steering Committee:
• The development of protocols uses a stakeholder driven process.
• The protocols use existing standards and protocols wherever possible.
• The protocols are cost-effective and user-friendly, and provide credible, quality.
• The interim protocols will become final protocols after review of validation efforts
and other experience gained in the use of the interim protocols.
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The field protocol was developed based on input and guidance provided by two stakeholder committees,
the ASERTTI Stakeholder Advisory Committee (SAC) and the ETV program's Advanced Energy
Stakeholder Group, managed by the Southern Research Institute (Southern). The SAC consisted of 27
stakeholders representing manufacturers, end-users, research agencies, regulators, trade organizations,
and public interest groups.
This GVP addresses the performance of MTG and reciprocating internal-combustion engine generators in
field settings. The protocol is not intended for small turbines. The purpose of this GVP is to describe
specific procedures for evaluation and verification of DG/CHP systems. A significant effort has been
devoted to their development, field trial, and improvement; and this experience and data are recognized as
potentially valuable to others. Instrument descriptions and recommendations presented in this document
do not constitute an endorsement by the GHG Center or the EPA. Readers should be aware that use of
this GVP is voluntary, and that the GHG Center is not responsible for liabilities that result from its use.
Finally, the GHG Center continues to conduct verifications, and will update this GVP with new findings
as warranted. Updates can be obtained online at the GHG Center (www.sri-rtp.com) or ETV
(www.epa.gov/etv) Web sites.
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TABLE OF CONTENTS
1.0 INTRODUCTION 1-1
1.1. SCOPE 1-1
1.2. SYSTEM BOUNDARIES 1-3
1.3. FIELD TEST SUMMARY 1-4
2.0 ELECTRICAL PERFORMANCE 2-1
2.1. SCOPE 2-1
2.1.1. Parameters and Measurements 2-1
2.1.2. System Boundary 2-2
2.2. INSTRUMENTS 2-3
2.2.1. Permissible Variations 2-4
3.0 ELECTRICAL EFFICIENCY 3-1
3.1. SCOPE 3-1
3.1.1. Parameters and Measurements 3-1
3.1.2. System Boundary and Measurement Locations 3-2
3.2. INSTRUMENTS AND FUEL ANALYSES 3-3
4.0 CHP THERMAL PERFORMANCE 4-1
4.1. SCOPE 4-1
4.1.1. Parameters and Measurements 4-1
4.1.2. System Boundary 4-3
4.2. INSTRUMENTS AND FLUID PROPERTY ANALYSES 4-4
5.0 ATMOSPHERIC EMISSIONS PERFORMANCE 5-1
5.1. SCOPE 5-1
5.1.1. Emission Parameters & Measurements 5-1
5.1.2. Additional Emission Tests 5-1
5.1.3. System Boundary 5-2
5.2. INSTRUMENTS 5-2
5.2.1. Analyzer Span Selection 5-3
6.0 FIELD TEST PROCEDURES 6-1
6.1. ELECTRICAL PERFORMANCE TEST (LOAD TEST) PROCEDURES 6-1
6.1.1. Pre-test Procedures 6-1
6.1.2. Detailed Test Procedure 6-1
6.2. ELECTRICAL EFFICIENCY TEST PROCEDURES 6-3
6.3. CHP TEST PROCEDURES 6-3
6.3.1. Pretest Activities 6-3
6.3.2. Detailed Test Procedure 6-3
6.4. ATMOSPHERIC EMISSIONS TEST PROCEDURES 6-4
6.4.1. Gaseous Pollutant Sampling 6-4
6.4.2. Total Particulate Matter Sampling 6-5
6.4.3. Exhaust Gas Flow Rate 6-5
6.4.4. Emission Rate Determination 6-6
7.0 QA/QC AND DATA VALIDATION 7-1
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7.1. ELECTRICAL PERFORMANCE DATA VALIDATION 7-1
7.1.1. Uncertainty Evaluation 7-1
7.2. ELECTRICAL EFFICIENCY DATA VALIDATION 7-2
7.2.1. Uncertainty Evaluation 7-3
7.3. CHP PERFORMANCE DATA VALIDATION 7-4
7.3.1. Uncertainty Evaluation 7-5
7.4. EMISSIONS DATA VALIDATION 7-6
7.4.1. Uncertainty Evaluation 7-6
7.5. TQAP QA/QC REQUIREMENTS 7-8
7.5.1. Duties and Responsibilities 7-8
7.5.2. Data Quality Objectives 7-8
7.5.3. Reviews, Assessments, and Corrective Action 7-8
8.0 REPORTS 8-1
8.1. ELECTRICAL PERFORMANCE REPORTS 8-2
8.2. ELECTRICAL EFFICIENCY REPORTS 8-2
8.3. CHP THERMAL PERFORMANCE REPORTS 8-3
8.4. ATMOSPHERIC EMISSIONS REPORTS 8-3
9.0 REFERENCES 9-1
VI
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Figure 1-1
Figure 1-2
Figure 1-3
Figure 2-1
Figure 3-1
Figure 4-1
Figure 4-2
Table 2-1
Table 2-2
Table 3-1
Table 3-2
Table 4-1
Table 5-1
Table 5-2
Table 7-1
Table 7-2
Table 7-3
Table 7-4
Table 7-5
Table 7-6
Table 7-7
Table 7-8
LIST OF FIGURES
Page
Performance Parameters and Data Collected for DG and CHP Testing 1-2
Generic System Boundary Diagram 1-3
Test Phase Summary 1-5
Electrical Performance Instrument Locations 2-2
Electrical Efficiency Instrument Locations 3-2
CHP Configurations: Hot Fluid- or Exhaust-fired 4-2
Example Hot Fluid-driven CHP System Schematic and Instrument
Locations 4-3
LIST OF TABLES
Page
Electrical Performance Instrument Accuracy Specifications 2-3
Permissible Variations 2-4
Electrical Efficiency Instrument Accuracy Specifications 3-3
Supplemental Equipment for SUT< 500 kW 3-3
CHP Thermal Performance Instrument Accuracy and Analysis Errors 4-4
Recommended Air Toxics Evaluations 5-2
Summary of Emissions Test Methods and Analytical Equipment 5-2
Electrical Generation Performance QA/QC Checks 7-1
Power Parameter Maximum Allowable Errors 7-2
Electrical Efficiency QA/QC Checks 7-3
Electrical Efficiency Accuracy 7-3
CHP Thermal Performance and Total Efficiency QA/QC Checks 7-4
Individual Measurement, AT, Qout, r|th, and r|tot Accuracy 7-5
Compounded Maximum Emission Parameter Errors 7-6
Summary of Emission Testing Calibrations and QA/QC Checks 7-6
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APPENDICES
Page
Appendix A Acronyms and Abbreviations Al
Appendix Bl Power Meter Commissioning Procedure Bl
Appendix B2 Distributed Generator Installation Data B3
Appendix B3 Load Test Run Log B5
Appendix B4 Fuel Consumption Determination Procedure B6
Appendix B5 External Parasitic Load Measurement Procedure and Data Log B7
Appendix B6 Fuel and Heat Transfer Fluid Sampling Procedure and Log Sheet B9
Appendix B7 Sample Chain-of-Custody Record Bll
Appendix B 8 Flow Meter and Temperature Sensor Commissioning and Data Log B12
Appendix C1 Generic IC-Engine Hot Fluid-driven CHP Chiller System
with Exhaust Diverter Cl
Appendix C2 Generic MTG Hot Fluid-driven CHP System in Heating Service C2
Appendix D Definitions and Equations Dl
Appendix Dl Electrical Performance Dl
Appendix D2 Electrical Efficiency Equations D4
Appendix D3 CHP Thermal Performance D6
Appendix D4 Emission Rates D8
Appendix D5 References D9
Appendix E Often Overlooked Emission Testing Requirements El
Appendix F Sample Implementation Fl
Appendix Fl Scope Fl
Appendix F2 Electrical Measurements and Datalogging F2
Appendix F3 Electrical Efficiency Measurements F5
Appendix F4 Thermal Performance and Efficiency Measurements F8
Appendix F5 Example Equipment F9
Appendix F6 References F10
Appendix G Uncertainty Estimation Gl
Appendix Gl Scope Gl
Appendix G2 Measurement Error G2
Appendix G3 Examples G4
Appendix G4 Total Efficiency Uncertainty G9
Appendix G5 References G10
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1.0 INTRODUCTION
Distributed generation (DG) utilizes small-scale electric generation technologies located near the
electricity point-of-use. Many DG systems can be utilized in combined heat and power (CHP)
applications, in which waste heat from the generator unit is used to supply local heating, cooling, or other
services. This provides improved energy efficiency, reduced energy costs, and reduced use of natural
resources. Current and developing DG technologies include microturbines (MTGs), internal combustion
(1C) generators, small turbines, and Stirling engines.
1.1. SCOPE
This generic verification protocol (GVP) was developed for the evaluation of MTG and 1C engine DG
units with up to 2500 kilowatt (kW) electrical generation capacity and in CHP service. The GVP
specifies procedures for evaluation of both gaseous- and liquid-fueled units. For ETV verifications, this
GVP should be accompanied by an approved verification specific Test and Quality Assurance Plan
(TQAP). The TQAP must include details and information specific to a technology verification that is not
included in this GVP including:
• technology description
• technology specific verification parameters
• organizational chart
• deviations from the GVP
• site specific measurement instrumentation and specifications
• identification and oversight of subcontractors
• verification specific data quality objectives
• verification specific audits and data reviews
• health and safety requirements
Electrical and thermal performance, including electrical efficiency evaluation is described at three power
command settings. Thermal and total efficiency procedures are included for CHP heating service. For
heat driven cooling systems, overall net performance is determined without resorting to characterization
of Coefficient of Performance (CoP), as this is beyond the scope of this GVP. No attempt is made to
evaluate the effectiveness of utilization of recovered heat or cooling at the host site.
Some CHP systems incorporate auxiliary heat sources (such as duct burners) to maintain CHP
performance when the DG prime mover's heat output is insufficient. Such systems can have many
configurations, all with different potential impacts on CHP and overall performance. A single testing
protocol which would consider all situations would be extremely lengthy. These systems are therefore
beyond the scope of this GVP.
CHP systems produce more than one energy stream, each with a different value. Electricity is the highest
value product of such a system. Chilling and heating streams have a value that is a function of the
temperature at which the energy is delivered. High temperature hot water and very low temperature
chilling loops provide higher value than more moderate temperatures. It is important, therefore, that in
addition to simple efficiency figures, each energy stream is individually characterized.
All performance data must be evaluated in the context of the site conditions because system performance
may vary with facility demands, ambient conditions and other site-specific conditions. This GVP is not
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intended to evaluate performance of the System Under Test (SUT) over a wide range of conditions or
seasons outside of those found during testing.
This document, including appendices, details the following performance testing elements, with
prescriptive specifications for:
• system boundaries
• definitions of important terms
• measurement methods, instruments, and accuracy
• test procedures
• data analysis procedures
• data quality and validation procedures
• reporting requirements
• other considerations (completeness, etc.)
This GVP addresses the performance parameters outlined in Figure 1-1.
Electrical
Generation
D)
0- .9
S*
O 0)
X
Hot Water
CHP Chilling
Exhaust-fired
CHP Chilling
Supplementary
Fuel:
Consumption, analysis,
temperature, pressure
Power:
Setpo nt, real power,
reactive power, power
factor, frequency,
voltage, current, total
harmon c distortion
Ambient Conditions:
Pressure, temperature
Emissons:
CH4, CO, C02, NOx,
SO2, THC, TPM
Acoustic Emissions:
Sound intensity, sound
power
Heated water loop:
Tsupply, Treturn, heat
transfer fluid flow rate
Cooling module (if
present):
Tsupply, Treturn, heat
transfer fluid flow rate
Chilled water loop:
Tsupply, Treturn, heat
transfer fluid flow rate
Heat transfer fluid:
density, specific heat
/External parasitic i
load(s)fS/fe-spec/f/c): /
Circulating pump /
Cooling tower loop and
cooling module loop(s):
Tsupply, Treturn, heat
transfer fluid flow rate
Supply Heat (for
optional CoP
determination):
Tsupply; Treturn;
Flow Rate
Heat transfer fluids:
density, specific heat
/External parasitic /
loads(s)(site specific): /
Circulating pump, chiller /
unit fan, cooling tower fan /
Chilled water loop:
Tsupply, Treturn, heat
transfer fluid flow rate
Cooling tower loop:
Tsupply, Treturn, heat
transfer fluid flow rate
Site documentation:
Physical plan & elevation, one-line
electrical diagram, plumbing and
mechanical interconnection, service
modes, etc.
Heat transfer fluids:
density, specific heat
/External parasitic i
loads(s)(site specific): /
Circulating pump, chiller /
unit fan , cooling tower fan /
/External parasitic /
load(s)(site specific : /
Fuel compressor, fue i
circulating pump, fuel i
heaters, coolers, in ake i
air treatment, etc. /
Figure 1-1. Performance Parameters and Data Collected for DG and CHP Testing
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1.2. SYSTEM BOUNDARIES
The verification TQAP and its report should clearly identify the equipment included as part of the system
being tested. Figure 1-2 shows a generalized boundary diagram which includes internal and external
components, fuel, heat transfer fluid, exhaust gas, and ambient air flows. The figure indicates two distinct
boundaries:
• device under test (DUT) or product boundary
• system under test (SUT) or system boundary
Electric Power
System (EPS)
Point of Common
Coupling (PCC)
Disconnect
Switch/
Breaker
Induced Draft
Exhaust Fan
(External
Parasitic Load) A
Heated or Chilled
Heat Transfer
Fluid Loop
Cooled
Exhaust
CHP *
Heat Recovery Unit
(or Exhaust-Fired Chiller)
Pump
Chiller
(or Medium Grade
Heat Load)
Cooling Tower
(or Low Grade
Heat Load)
Compressor
Motor
(internal parasitic load)
SUT or
System Boundary
Figure 1-2. Generic System Boundary Diagram
In general, laboratory tests will use the product boundary to evaluate DG performance. Field tests
conducted according to this GVP will incorporate the system boundary into performance evaluations.
The DUT boundary should incorporate components that are part of standardized offerings by
manufacturers or distributors. If the seller's product consists of multiple skids which require field
assembly, all such skids should fall within the DUT boundary.
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The SUT boundary includes the DUT and those essential external parasitic loads or auxiliary equipment,
such as fuel gas compressor, induced-draft (ID) fan, heat transfer fluid pump, etc., required to make the
product fully functional. For example, if a product includes a heat recovery heat unit but not a circulating
pump for the circulating heat transfer fluid, the circulating pump would fall within the SUT boundary but
not the DUT boundary.
Auxiliary equipment that serves multiple units in addition to the test DG (such as large gas compressors)
should be documented, but should not be included within the SUT boundary.
Figure 1-2 is not comprehensive because DG and CHP installations vary greatly from site to site and
across applications. For example, individual parasitic loads may be included in some packages while
others may require separate specification and installation. Appendix C provides additional boundary
diagram examples.
1.3. FIELD TEST SUMMARY
Sections 2.0 and 3.0 describe the tests required for DG electrical performance and efficiency. This GVP
requires these two sections and Section 4.0 for CHP thermal performance tests. Section 5.0 describes the
required and optional atmospheric emissions tests.
Field tests include the following phases:
• burn-in
• setup or pretest activities
• load tests
electrical performance
electrical efficiency
CHP performance
atmospheric emissions
This GVP specifies three complete test runs at each of three power command settings (50, 75, and 100
percent) for the load test phases. Note that if the DUT cannot operate at these three power commands,
three test runs at 100 percent power is an acceptable option. Each microturbine test run should last 1A
hour; each 1C generator test run is one hour.
Section 6.0 provides step-by-step test procedures. Test personnel should take the individual
measurements in the order specified in Section 6.0 during each test run, depending on the performance
parameters to be evaluated.
Section 7.0 provides all quality assurance/quality control (QA/QC) checks for instruments and procedures
for data validation. If each measurement meets the minimum accuracy specification, analysts can report
the overall estimated accuracy as cited in this GVP. The actual achieved parameter uncertainty may be
calculated directly according to the detailed accuracy estimation methods presented in Appendix G.
Section 8.0 describes reporting requirements.
Figure 1-3 illustrates the test runs, test conditions, and parameter classes evaluated during each phase.
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V
Q-
"S
Q-
-~) t
0
1
0.
0
1
0.
O
O
^0
Electrical Perfor-
mance and Efficiency
(§)
CHP Performance
(Heating and Chilling)
(§4.0 J
Atmospheric Emissions
Performance
©
/" Begin Performance Test - Data Collection A
V_ (After Burn-in) J
1
r
( Gather Heat Transfer Fluid Samples (other than water) Q
^ r
/ Gather EPS-only /
\ V, THD Data [
J
1
J^
I §7.0 for All \
Test
\ Procedures /
'
Set output to 50%
30 minutes to stabilize
±
(Collect Electrical, Efficiency, CHP, and Emissions Performance Data /
Three Runs, MTG: 30 minutes each; IC-engine: 60 minutes each
Gather One Fuel Sample During a Valid Test Run \
/ Gather EPS-only 1
\ V, THD Data \
1
T
Set output to 75 %
30 minutes to stabilize
(Collect Electrical, Efficiency, CHP, and Emissions Performance Data /
Three Runs, MTG: 30 minutes each; IC-engine: 60 minutes each
Gather One Fuel Sample During a Valid Test Run \
^
/ Uather bPS-only /
1 V, THD Data \
1
1
t
Set output to 100%
30 minutes to stabilize
t
/ Collect Electrical, Efficiency, CHP, and Emissions Performance Data /
Three Runs, MTG: 30 minutes each; IC-engine: 60 minutes each
\ Gather One Fuel Sample During a Valid Test Run I
/ Gather EPS-only /
\ V, THD Data \
,
1
^ '
Acoustic Emissions
Performance
( §6.0 )
f Begin Acoustic A
^Data Collection^
\
Build Measurement
Surface
1 Log Measurement Surface, 1
Test Environment
\
1 Collect Baseline /
\ Acoustic Data Scan \
!
r
/ Set output to 50 % 1
\ 10 minutes to stabilize I
J
1 Scan Measure- 1
\ ment Surface \
i
r
/ Set output to 75 % /
^ 10 minutes to stabilize ^
;
r
/ Scan Measure- /
\ ment Surface \
r
1 Set output to 100% 1
1 10 minutes to stabilize \
I
1 Scan Measure- /
\ ment Surface \
( Data Collection Complete J
/ §8.0 for QA/QC and \
| Data Validation 1
Procedures 1
\ §9.0 for Reporting /
Figure 1-3. Test Phase Summary
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2.0 ELECTRICAL PERFORMANCE
2.1. SCOPE
This section specifies the test procedures for electrical generation performance evaluation, including
generating capacity and power quality. Appendix D provides definitions, equations, and useful
relationships.
This GVP is designed for grid-parallel DG field operations of 480 volts or less. All instruments should be
capable of measuring such voltages without a potential transformer (PT). The protocol can be applied to
higher system voltages if the instruments have the capability or are used in conjunction with suitable PTs.
Data analysts must account for the effects that PT accuracy has on overall measurement error (see
Appendix G).
Grid-independent DG systems may also be evaluated with minor changes. For example, the test
procedures which involve total harmonic distortion performance comparisons with the electric power
system (EPS) may be omitted for grid-independent systems. The ability to use all generated power
should be available for testing of grid independent systems.
2.1.1. Parameters and Measurements
A suitable measurement instrument and sensors, installed at the specified place in the electrical wiring,
will measure the following parameters at each of the three power command settings:
• real power, kilowatts (kW)
• apparent power, kilovolt-amperes (kVA)
• reactive power, kilovolt-amperes reactive (kVAR)
• power factor, percent (PF)
• voltage total harmonic distortion (THD), percent
• current THD, percent
• frequency, Hertz (Hz)
• voltage, volts (V)
• current, amperes (A)
The following measurements (in addition to real power) will allow analysts to verify DG operating
stability as compared to permissible variations, evaluate ambient conditions, and quantify external
parasitic loads:
• fuel consumption, actual cubic feet per hour (acfh) for gas-fueled or pounds per hour
(Ib/h) for liquid-fueled equipment
• ambient air temperature, degrees Fahrenheit (°F)
• ambient barometric pressure, pounds per square inch absolute (psia)
• external parasitic load power consumption, kVA (apparent power) or kW (real
power)
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Note that "ambient conditions" may require careful consideration depending on site characteristics. For
example, interior installations require consideration of the combustion air intake location, whether it is
under negative or positive pressure, exhaust induced draft (ID) fan effects (if present), and system cooling
conditions. The ambient air sensors should be placed at a location which is representative of the air
actually used by the SUT for the prime mover.
2.1.2. System Boundary
Figure 2-1 is a generalized instrument location schematic diagram for electrical performance
measurements. The figure shows power meter locations with respect to the DUT and the point of
common coupling (PCC). The PCC is the point at which the electric power system (EPS), other users,
and the SUT have a common connection.
Electric Power SystemJ
(EPS)
Point of Common Coupling
Testers should quantify external parasitic loads with a clamp-on
digital voltmeter (DVM), clamp-on real power meter, or
semi-permanently installed real power meters (one for each load)
~ x_
Supply
Figure 2-1. Electrical Performance Instrument Locations
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Figure 2-1 shows a fuel gas compressor, an ID fan, and a prime mover cooling module which are not
connected internally to their electric power source. These components are outside the product boundary
(or DUT) but inside the system boundary (or SUT). Testers must inventory such external parasitic loads
and plan to measure their power consumption as apparent power (kVA) with a clamp-on digital volt meter
(DVM) or as kW with real power meters (one for each load). Accounting for external parasitic loads in
terms of kVA is based on the assumption that real and apparent powers are approximately equal (power
factor « 1.0). Appendix G discusses the impact of this approximation on the electrical generation
efficiency accuracy.
2.2. INSTRUMENTS
The power meter that measures the electrical parameters listed in Section 2.1.1 must meet the general
specifications for electronic power meters in ANSI C12.20-2002 [1]. The meter must incorporate an
internal datalogger or be able to communicate with an external datalogger via digital interface (RS-485,
RS-232, LAN, telephone, etc.). The current transformer (CT) must conform to IEC 61000-4-30 Metering
Class specifications [2]. Table 2-1 summarizes electrical performance and supplemental instrument
specifications. Appendix F contains more detailed specifications and installation procedures.
Table 2-1. Electrical Performance
Instrument Accuracy Specifications"
Parameter
Voltage
Current
Real Power
Reactive power
Frequency
Power Factor
Voltage THD
Current THD
CT
CT
Temperature
Barometric pressure
DVM voltage
DVM current
Fuel consumption
Real power meter kW
Accuracy
+ 0.5 %
+ 0.4 %
+ 0.6 %
+ 1.5 %
+ 0.01 Hz
+ 2.0 %
+ 5.0 %
+ 4.9% to 360 Hz
+ 0.3% at 60 Hz
+ 1.0 % at 360 Hz
± 1°F
±0.1 in. Hg (±0.05psia)
+ 1.0 %
+ 2.0 %
+ 1.0 %
+ 1.0 %
"All accuracy specifications are percent of reading, provided by
manufacturers, and subject to the calibrations and QC checks
described in Section 7.0.
felf used for external parasitic load determinations.
The power meter and supplemental instruments must be accompanied by a current (within 6 years)
National Institutes of Standards and Technology (NIST)-traceable calibration certificate prior to
installation. The calibrations must include the internal data logger if used, or the external data logger
should carry a NIST-traceable calibration of the analog to digital signal converter. The CTs must be
accompanied by a manufacturer's accuracy certification.
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The datalogger (internal or external) must have the capability to poll the power meter for each electrical
parameter at least once every five seconds, then compute and record the one-minute averages. Additional
channels will be required to perform CHP testing (see Section 4.0).
2.2.1. Permissible Variations
SUT operations should be reasonably stable during testing. PTC-22 [3] and PTC-17 [4] specify the
maximum permissible variations. Key parameter variations should be less than those summarized in
Table 2-2 during each test run. Test personnel will use only those time periods that meet these
requirements to compute performance parameters.
Table 2-2. Permissible Variations
Measured Parameter
Ambient air temperature
Ambient pressure
(barometric station
pressure)
Fuel flow
Power factor
Power output (kW)
Gas pressure*
Gas temperature6
MTG Allowed Range
+ 4°F
+ 0.5 %
+ 2.0 %a
± 2.0 %
+ 2.0 %
n/a
n/a
1C Generator Allowed
Range
+ 5°F
+ 1.0 %
n/a
n/a
+ 5.0 %
+ 2.0 %
+ 5°F
"Not applicable for liquid-fueled applications < 30 kW.
*Gas-fired units only
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3.0 ELECTRICAL EFFICIENCY
3.1. SCOPE
Electrical generation efficiency (r|e) can also be termed the "fuel-to-electricity conversion efficiency." It
is the net amount of energy a SUT produces as electricity compared to the amount of energy input to the
system in the fuel, with both the outputs and inputs stated in common units. Heat rate expresses electrical
generation efficiency in terms of British thermal units per kW-hour (Btu/kWh). Definitions and equations
appear in Appendix C.
Efficiency can be related to the fuel's higher heating value (HHV) or its lower heating value (LHV). The
HHV is typically (approximately) 10% higher than the LHV and represents maximum theoretical
chemical energy from combustion. Appendix D, Equation DIG shows the relationship between the two
efficiency statements. With few exceptions (such as condensing boilers) the full HHV of the fuel is not
available for recovery. Therefore this GVP specifies determinations for rje,LHv, or the electrical
conversion efficiency referenced to fuel LHV.
3.1.1. Parameters and Measurements
Testers will quantify electrical generation efficiency and heat rate at each of the three power commands.
Required measurements include the following:
• real power production, kW
• external parasitic load power consumption, kVA (apparent power) or kW (real
power)
• ambient temperature, °F
• ambient barometric pressure, psia
• fuel LHV, Btu per standard cubic foot (Btu/scf) for gaseous fuels or Btu per pound
(Btu/lb) for liquid fuels
• fuel consumption, standard cubic feet per hour (scfh) for gaseous fuels or pounds per
hour (Ib/h) for liquid fuels
Note that the definition of "ambient" conditions, while simple for outdoor installations, may require
careful consideration for indoor applications. Air conditioning or ventilation equipment can substantially
alter combustion air properties at the SUT air intake and therefore its performance. For example, the SUT
may draw its combustion air from an interior room which is under negative pressure. The ambient
pressure and temperature sensors should therefore be located in that room.
Fuel heating value determinations require gaseous or liquid fuel sample collection and laboratory heating
value analysis. Fuel analyses provided by the fuel supplier are an acceptable alternative to fuel sampling
so long as the analyses are current (within approximately one month of testing) and traceable (proper
analytical procedures are documented). Fuel consumption determinations require the following
measurements:
Gaseous Fuels
• fuel flow rate, acfh
• fuel absolute temperature, degrees Rankine (R)
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• fuel absolute pressure, psia (which can be stated as the sum of ambient barometric
pressure plus fuel gauge pressure)
• fuel compressibility (dimensionless) obtained from fuel sample laboratory analysis
Liquid Fuels
• fuel mass consumption, Ib/h
During electrical efficiency test runs, the SUT and ambient conditions must conform to the permissible
variations outlined in Table 2-2.
3.1.2. System Boundary and Measurement Locations
Figure 3-1 is a generalized instrument location schematic diagram. The figure shows measurement
instrument locations with respect to the SUT and the PCC.
Electric Power SystemJ
(EPS)
Point of Common Coupling
Testers should quantify external parasitic loads with a clamp-on
digital voltmeter (DVM), clamp-on real power meter, or
semi-permanently installed real power meters (one for each load)
Compressor Motor
(external parasitic load)
Cumulative Supply
Fuel Flow
Figure 3-1. Electrical Efficiency Instrument Locations
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3.2. INSTRUMENTS AND FUEL ANALYSES
Table 3-1 summarizes the required instruments, laboratory analyses, and accuracy specifications.
Appendix F provides more detailed specifications, installation, and analysis procedures.
Table 3-1. Electrical Efficiency
Instrument Accuracy Specifications
Fuel
Gaseous fuel
Liquid fuel
Measurement
Gas flow
Gas temperature
Gas pressure
LHV analysis by ASTM D1945 [8]
andD3588[9]
Platform scale (< 500 kW)
Temperature-compensated flow
meter (> 500 kW)
Density analysis by ASTM D1298
[10] (> 500 kW)
LHV analysis by ASTM D4809 [11]
Maximum Allowable Error"
+ 1.0% [5,6/7]
±4.5°F
± 0.2 psia
+ 1.0%
+ 0.01 % of reading, + 0.05 Ib scale resolution
Single flow meter (MTG): + 1.0 %
Differential flow meter (diesel 1C generator): +
1.0 % of differential reading (achieved by approx.
+ 0.2 % for each flow sensor)
+ 0.05 %
+ 0.5%
"All accuracy specifications are percent of reading unless otherwise noted, provided by manufacturers, and
subject to the calibrations and QC checks described in Section 7.0.
Gaseous or liquid fuel consumption instruments and their readouts or indexes should be specified to
ensure that their resolution is < ± 0.2 percent of the total fuel consumed during any test run. For example,
if a MTG uses 100 ft3 during a test run at 50 percent power command, the gas meter's index resolution
must be less than 0.2 ft3.
Table 3-2 presents supplemental equipment for SUT less than about 500 kW capacity.
Table 3-2. Supplemental Equipment for SUT <
500 kW
Description
Day tank
Secondary containment
Return fuel cooler
(diesel 1C generator
only)
Capacity
100 gallon
100 gallon, minimum
Approximately 14000 -
22000 Btu/h for 500 kW
engine
Equipment may include diesel fuel line heater or day tank heater in colder climates. These represent
additional internal or external parasitic loads which test personnel should consider.
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4.0 CHP THERMAL PERFORMANCE
4.1. SCOPE
This section presents test methods for determining thermal performance of CHP systems in heating or
chilling service. Applicable CHP devices use a circulating liquid heat transfer fluid for heating or
chilling. The CHP equipment itself is considered to be within the SUT boundary. The balance of plant
(BoP) equipment, which employs the heating or chilling effect, is outside the system boundary. This
GVP does not consider how efficiently the BoP uses the heating or chilling effect.
4.1.1. Parameters and Measurements
The field tests described in this GVP are intended to quantify the following CHP performance parameters:
• actual thermal performance in heating service, Btu/h
• actual SUT efficiency in heating service as the sum of electrical efficiency and
thermal efficiency, percent
• maximum thermal performance, or maximum energy available for recovery, Btu/h
• maximum thermal efficiency in heating service, percent
• maximum SUT efficiency in heating service, percent
• actual thermal performance in chilling service, Btu/h or refrigeration tons (RT)
• maximum secondary heat in chilling service, Btu/h
• heat transfer fluid supply and return temperatures, °F, and flow rates, gallons per
minute (gpm)
Actual thermal performance is the heat transferred out of the SUT boundary to the BoP for both CHP
heaters and chillers. Actual thermal efficiency in heating service is the ratio of the thermal performance
to total heat input in the fuel.
Refer to Figures 4-1 and 4-2 regarding maximum thermal performance, maximum thermal efficiency, and
maximum SUT efficiency. Figure 4-1 shows simplified schematics for hot fluid- and exhaust-fired CHP
systems. A CHP system in heating service may incorporate cooling modules for removal of excess heat
from the CHP device, the prime mover (shown in Figure 4-2), and other sources during periods of low
heat demand. The sum of the actual thermal performance, cooling tower rejected heat, and prime mover
cooling module rejected heat represents the maximum available thermal energy. The ratio of the
maximum available thermal energy to the fuel heat input is the maximum thermal efficiency in heating
service. Similarly, maximum SUT efficiency is the ratio of the sum of the rejected heat, actual heat
transferred, and the electric power produced divided by the system's fuel heat input.
Maximum secondary heat in chilling service is that available from secondary systems such as low-grade
heat from cooling towers (Figure 4-1) or medium-grade heat from prime mover cooling modules (Figure
4-2). Actual or maximum thermal efficiency in chilling service is not meaningful because chiller system
coefficient of performance (CoP) is not included in the scope of this document.
Note that throughout this document the "cooling tower" or "prime mover cooling module" could be
replaced by any means of waste heat rejection, such as fan-coil unit or other heat exchanger.
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Cooled Exhaust
BoP Heating
(or chilling) Loads
Cooling Fluid C°°lin9 Tower
Circulation Pump (Or Low Grade
Heat Load)
CHP Heat Recovery Unit
(May be incorporated into
either the DUTorSUT)
Exhaust from
Prime Mover
Hot Fluid-driven CHP
- Cooling tower fluid loop may provide heat to low grade loads
such as swimming pools
- Hot fluid loop may also provide heat to intermediate loads such
as domestic hot water, reheat coils, or process hot water
BoP Heating
(or chilling) Loads Coo|ed Exhaus(
Heat Transfer
^J Fluid Circu-
lation Pump
Exhaust-Driven
CHP
Cooling Fluid Cooling Tower
Circulation (OrLowGrade
Pump Heat Load)
Exhaust from
Prime Mover
Exhaust-fired CHP
- Cooling tower fluid loop may provide heat to low grade loads
such as swimming pools
Figure 4-1. CHP Configurations: Hot Fluid- or Exhaust-fired
In either heating or chilling applications, thermal performance determination requires the following
measurements and determinations at each of the three power commands:
• heat transfer fluid flow rate at the SUT boundary
• heat transfer fluid supply and return temperatures at the SUT boundary
• heat transfer fluid specific heat and density
• heat transfer fluid flow rate at each cooling tower
• heat transfer fluid supply and return temperatures at each cooling tower
• SUT heat input, as determined from the fuel consumption rate and heating value
(Section 3.0)
• electrical efficiency (Section 3.0)
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4.1.2. System Boundary
Figure 4-2 provides a sample system schematic which depicts a CHP system, instrument locations,
internal and external parasitic load examples, and heat transfer fluid flow paths. The figure also shows
the cooling tower's fan and circulation pump as a combined external parasitic load. The figure provides
instrument locations for testing CHP systems in both heating and chilling service because the heat transfer
schemes are similar.
Electric Power
System (EPS)
Point of Common
Coupling (PCC)
Emissions
Analyzers &
Sample Handling
System
Cooled
Exhaust
Chilling
(or heating)
Loop
Cumulative
Fuel Flow
Figure 4-2. Example Hot Fluid-driven CHP System Schematic and Instrument Locations
The heat transfer fluid loop marked "Chilling (or heating) Loop" in Figure 4-2 represents the primary
useful energy product in either heating or chilling service. Various combinations of heat transfer fluid
loops can provide secondary energy to the BoP, such as:
• In a hot fluid-driven chiller, part or all of the hot fluid energy may be supplied to BoP
thermal loads. In this case, thermal performance should be assessed while operating
in the heating mode in addition to the chilling mode.
• In either hot fluid- or exhaust-fired chillers, the cooling tower loop fluid may be
warm enough for low grade heat applications such as swimming pool heating. In this
case, heat delivered to the useful loads should be measured.
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Testers should therefore specify instrument placement on a site-specific basis, and create a SUT
schematic which includes the instruments as part of the report.
4.2. INSTRUMENTS AND FLUID PROPERTY ANALYSES
CHP measurement equipment includes that listed in Sections 2.0, 3.0 and:
• heat transfer fluid flow meter(s) and transmitter(s)
• matched Tsuppiy and Treturn sensors, thermowells, and transmitters
• suitable multi-channel datalogger
Determination of thermal performance requires one complete flow meter and temperature sensor set for
each heat transfer loop.
CHP performance determinations also require heat transfer fluid density (p) and specific heat (cp). These
values may be obtained from standard tables for water [12]. Laboratory analysis for density is required
for propylene glycol (PG) solutions. Analysts will then use the density result to interpolate specific heat
from ASHRAE standard tables for PG [13] or equivalent tables for other fluids.
Table 4-1 provides instrument and analysis accuracy specifications. Appendix F suggests specific
instruments and installation procedures.
Table 4-1. CHP Thermal Performance
Instrument Accuracy and Analysis Errors"
Parameter
Heat transfer fluid flow (including
transmitter)
Tsuppiy, Treturn temperature sensors
(including transmitters)
Heat transfer fluid density by
ASTMD1298[14]
Heat transfer fluid specific heat
from ASHRAE tables [13]
Accuracy
+ 1.0 %
+ 0.6 °F at expected
operating temperature
+ 0.2 %b
+ 0.2 %*
"All accuracy specifications are percent of reading unless otherwise
noted, provided by manufacturers, and subject to the calibrations
and QC checks described in Section 7.0.
*PG or other non-water heat transfer fluids only
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5.0 ATMOSPHERIC EMISSIONS PERFORMANCE
5.1. SCOPE
This GVP considers emissions performance tests to be optional. If performed, the following subsection
cites the appropriate Title 40 CFR 60, Appendix A [15] reference methods. This GVP highlights
reference method features, accuracies, QA/QC procedures, and other issues of concern. The individual
test methods contain detailed test procedures, so they are not repeated here.
5.1.1. Emission Parameters & Measurements
The gaseous emissions and pollutants of interest for all DG systems are:
• nitrogen oxides (NOX) • methane (CFL^ • total hydrocarbons (THC)
• carbon monoxide (CO) • sulfur dioxide (SO2) • TPM (diesel or other distillate fuel)
• oxygen (O2) • carbon dioxide (CO2)
The reference methods to be used for each parameter are specified in Table 5-2. Note that systems firing
gaseous fuels need not evaluate TPM emissions except in special cases such as those supplied by certain
biogas sources. These may include landfill gas- or human waste digester gas-fired units that do not
incorporate effective siloxane gas removal equipment. Most systems firing commercial natural gas need
not evaluate SO2 unless the fuel sulfur content is elevated.
In CHP systems with low temperature heat recovery loops (such as where condensation may occur) the
emissions profile when recovering heat may differ from when exhaust gas bypasses the heat recovery
unit. In this case emissions testing should take place in the worst case configuration. This is typically
with the diverter in the bypass position.
Measurements required for emissions tests, if performed, include:
• electrical power output, kW (Section 2.0)
• fuel heat input, Btu/h (Section 3.0)
• pollutant, greenhouse gas (GHG), and O2 concentration, parts per million (ppm),
grains per dry standard cubic foot (gr/dscf), or percent
• stack gas molecular weight, pounds per pound-mole (Ib/lb.mol)
• stack gas moisture concentration, percent
• stack gas flow rate, dry standard cubic feet per hour (dscfh)
Each of these measurements require sensors, contributing determinations, calibrations, sample collection,
or laboratory analysis as specified in the individual reference methods.
5.1.2. Additional Emission Tests
Air toxic emissions can be evaluated depending primarily on fuel type, SUT design, and the needs of the
site operator or test program manager. Table 5-1 lists the recommended test methods.
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Table 5-1. Recommended Air Toxics Evaluations
Test Method
Fuel Type or
System Design
Natural Gas
LPG
Biogas (digester)
Landfill gas
Petroleum (diesel)
System with NOX
Emission Controls
Pollutant
Formaldehyde
Method 323
(Proposed)
Metals
Method 29
Ammonia
(NH3)
Conditional Test
Method CTM-
027
Sulfur
Compounds
(TRS)
Method 16 A
•/
S
•/
S
•/
•/
•/
S
S
•/
S
Ammonia testing should also be considered for DG systems with NOX catalytic or non-catalytic emission
controls. Ammonia slip is a potential concern in such systems.
5.1.3. System Boundary
Figure 1-2 shows a generalized system boundary for emissions testing. Although most DG systems have
a single exhaust stack, some CHP designs may utilize separated high temperature and low temperature
exhaust streams with an exhaust diverter. The test manager should review SUT design to ensure that
emissions tests incorporate all potential emission points.
5.2. INSTRUMENTS
The reference methods provide detailed instrument, sampling system components, and test procedure
specifications. Table 5-2 summarizes the fundamental analytical principle for each method.
Table 5-2. Summary of Emission Test Methods and Analytical Equipment
Parameter or
Measurement
CH4
CO
C02
NOX
02
S02
THC
TPM
Moisture
Exhaust gas
volumetric flow
rate
U.S. EPA
Reference Method
18
10
3A
20,7E
3A
6C
25A
5,202
4
2, 19
Principle of Detection
Gas chromatograph with flame ionization detector (GC/FID)
Non-dispersive infrared (NDIR)-gas filter correlation
NDIR
Chemiluminescence
Paramagnetic or electrochemical cell
Pulse fluorescence, ultraviolet or NDIR
Flame ionization detector (FID)
Gravimetric
Gravimetric
Pitot traverse or F-factor calculation
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5.2.1. Analyzer Span Selection
The test manager should evaluate the system's emissions prior to the test campaign because experience
has shown that DG emissions can vary widely at the specified power command settings (50, 75, and 100
percent). In general, expected stack gas concentrations should be between 30 and 100 percent of the
analyzer span. Concentrations outside this range can cause a test run to be deemed invalid. Testers
should plan to modify the analyzer spans as needed to prevent this.
It may be impossible, however, for a NOX analyzer to meet this specification at low NOX emission rates.
It is acceptable in this case to adjust the analyzer span such that the expected NOX concentrations fall
between 10 and 100 percent of span.
Ambient (high sensitivity) analyzers will be required to perform these measurements at the specified
accuracy due to extremely low emission rates of some DG sources. Care should be taken to match the
instrumentation to manufacturer-specified or well-documented emission rates.
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6.0 FIELD TEST PROCEDURES
6.1. ELECTRICAL PERFORMANCE TEST (LOAD TEST) PROCEDURES
The objectives of the load test phase are to:
• obtain site information and system specifications
• measure the DUT electrical generation performance at three power command
settings: 50, 75, and 100 percent
• provide a stable test environment for acquisition of reliable electrical efficiency
(Section 3.0), CHP performance (Section 4.0), or atmospheric emissions (Section
5.0).
6.1.1. Pre-test Procedures
The DUT should have completed a burn-in phase of at least 48 hours at 100 percent of power command
for rebuilt equipment or new installations. At a minimum new DG units must have completed the
manufacturer's recommended break-in schedule.
Log the site's DG installation data on the form provided in Appendix B2 and ensure that test instruments
described in Section 2.2 have been properly selected, calibrated, and installed. Identify external parasitic
loads to be evaluated during the test. Equipment for this evaluation should be documented on the
Distributed Generator Installation Data form (Appendix B2). External parasitic loads that serve multiple
users in addition to the DUT (such as large gas compressors serving several units) need not be measured.
Note such common loads on the Appendix B2 log form and describe them in the test report.
6.1.2. Detailed Test Procedure
A 30 minute monitoring period with the SUT off or disconnected will precede and follow each test period
to establish EPS baseline voltage and THD performance. Record the electrical parameters listed in
Section 2.1.1.
Each test period will consist of:
• a period for SUT equilibration at the given power command, followed by
three test runs
• Test runs will be !/2-hour each for microturbine generators and 1-hour each for 1C
generators
If emission tests are being performed, each test run should be preceded and followed by the appropriate
emission measurement equipment calibration and drift checks. Figure 1-3 shows a test run schematic
timeline.
The step-by-step load test procedure is as follows:
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1. Ensure all instruments are properly installed and calibrated in accordance with the Section 7.1
requirements and that field QC checks have been conducted and met acceptance criteria.
2. Initialize the datalogger to begin recording one-minute power meter data.
3. Synchronize all clocks with the datalogger time display. Disconnect the DG unit and shut it
down for the one-hour baseline monitoring period. Record the time on a load test run log form
(Appendix B3).
4. Enter the power command setting (beginning with 50% of full power), manufacturer, model
number, location, test personnel, and other information onto the load test run log form (Appendix
B3). Specify a unique test run ID number for each test run and record on the load test run log
form.
5. If necessary, coordinate with other testing personnel to establish a test run start time. Record the
test run start time and initial fuel reading on the log form in Appendix B4. Transfer the test run
start time to the load test run log form (Appendix B3).
6. Record one set of ambient temperature and pressure readings on the load test run log form
(Appendix B3) at the beginning; at least two at even intervals during; and one at the end of each
test run.
7. Operate the unit at 50 percent of capacity for sufficient time to acquire all data and samples as
summarized in Figure 1-3. Record the required data on the load test run log and fuel flow log
forms (Appendix B3, B4) during each test run. If additional parameters are being evaluated
during the load test phase (electrical efficiency, thermal efficiency, emissions), ensure that the
data required in the applicable sections is documented.
8. Acquire and record external parasitic load data on the external parasitic load data log form in
Appendix B5. Use a new log form for each test run.
9. If fuel analyses are needed for electrical efficiency determinations (Section 3.0), acquire at least
one fuel sample during a valid test run at each of the three power command settings1. Use the
procedure and log form in Appendix B6.
10. For CHP performance determinations (Section 4.0), acquire at least one1 heat transfer fluid
sample from each heat transfer fluid loop (fluids other than water only; do not sample pure water
heat transfer fluids). Use the procedure and log form in Appendix B6.
11. At the end of each test run, review the electrical performance data recorded on the datalogger for
completeness. Also review all other datalogger records as appropriate for completeness and
reasonableness. Enter the maximum and minimum kW, ambient temperature, ambient pressure,
etc. on the load test run log form and compare them with the maximum permissible variations
listed in Table 2-2. If the criteria are not met repeat the test run until they are satisfied.
12. Repeat steps 4 through 11 at 75 percent of capacity. Use new fuel flow and load test run log
forms.
13. Repeat steps 4 through 11 at 100 percent of capacity. Use new fuel flow and load test run log
forms.
14. Disconnect the unit for at least one hour for EPS baseline monitoring.
15. Complete all field QA/QC activities as follows:
• Ensure that all field data form blanks have the appropriate entry
• Enter dashes or "n/a" in all fields for which no data exists
• Be sure that all forms are dated and signed
16. Archive the datalogger files in at least two separate locations (floppy disk and computer hard
drive, for example). Enter the file names and locations on the load test run log forms (Appendix
B3).
If the testing organization has had good experience with the analytical laboratory historically then one sample at each power
command setting (for fuel) or one sample during the test campaign (for each heat transfer fluid) will suffice. Otherwise
redundant samples should be taken to confirm analysis repeatability.
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17. Forward the fuel & fluid samples to the laboratory under a signed chain of custody form
(Appendix B7).
6.2. ELECTRICAL EFFICIENCY TEST PROCEDURES
Electrical efficiency test runs should occur simultaneously with the electrical performance test runs.
Electrical efficiency determinations include all the tasks listed in Section 6.1 and:
• fuel consumption determination (Section 6.1.2, Step 7)
• fuel sampling and analysis (Section 6.1.2, Step 9)
• submit fuel samples for laboratory analysis at the conclusion of testing as needed.
6.3. CHP TEST PROCEDURES
6.3.1. Pretest Activities
All fluid loops should have been circulating for a period of at least 48 hours with no addition of chemical
or makeup water to ensure well-mixed fluid throughout the loop.
Test personnel should log the heat recovery unit information in the Appendix B8 log form. The test
manager should document CHP heat transfer fluid loop(s) and thermal performance instrument location(s)
on a summary schematic diagram.
Immediately before the first test run, site operators should stop the heat recovery fluid flow or isolate the
fluid flow meter from the SUT. Test operators will record the zero flow value on the Appendix B8 log
form and make corrections if the zero flow value is greater than ±1.0 percent, full scale.
6.3.2. Detailed Test Procedure
CHP performance test runs should occur simultaneously with the electrical performance and electrical
efficiency test runs. The CHP system should be activated during testing at operating levels which are
appropriate for the power command setting. CHP performance determinations include the tasks listed in
Section 6.1 and the following data and sample collection activities:
• Ensure all instruments are properly installed and calibrated in accordance with the Section 7.1
requirements and that field QC checks have been conducted and met acceptance criteria.
• record one-minute average Vi (heat transfer fluid flow rate), Tsuppiy, and Treturn data
during each of the three test runs at each power command (50, 75, and 100 percent)
using the datalogger
• log fuel consumption and collect fuel samples (Section 6.1.2, Step 7)
• for heat transfer fluids other than water, collect at least one fluid sample during the
load tests (Section 6.1.2, Step 9). Appendix B6 provides the sampling procedure and
log form.
• at the conclusion of the load tests, forward any required fuel and fluid samples to the
laboratory under a signed chain of custody form (Appendix B7)
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6.4. ATMOSPHERIC EMISSIONS TEST PROCEDURES
Testers should plan to conduct three test runs at each of three power command settings (50, 75, and 100
percent) simultaneously with the electrical performance, electrical efficiency, or CHP performance test
runs. Use of experienced emissions testing personnel is recommended because of the complexity of the
methods.
Emissions performance determinations include the tasks listed in Section 6.1 and the following
measurement and data collection activities:
• three instrumental analyzer test runs, 30 minutes each for MTG and 60 minutes each
for 1C generators, at each power command setting for each emission parameter. Each
test run incorporates pre- and post-test calibration, drift, and other QA/QC checks
• instrumental analyzer determination of CO2, CO, O2, NOX, SO2 (if required), and
THC emission concentrations as specified in the reference methods during each test
run
• one Method 2 or Method 19 exhaust gas flow rate determination for each
instrumental analyzer test run
• one Method 4 determination of exhaust gas moisture content at each power
command setting during a valid test run
• exhaust gas sample collection during each test run at each power command and
analysis for CH4 in accordance with EPA Method 18
• TPM sample collection during one 120-minute test run for liquid-fueled MTGs or
one 60-minute test run for liquid-fueled 1C generators at each load condition in
accordance with EPA Methods 5 and 202
• all QA/QC checks required by the EPA Reference Methods
Throughout the testing, operators will maintain SUT operations within the maximum permissible limits
presented in Table 2-2. The field test personnel or emissions contractor will provide copies of the
following records to the test manager:
• analyzer makes, models, and analytical ranges
• analyzer calibration records
• QA/QC checks
• field test data
• copies of chain-of-custody records for gas samples (for THC and TPM)
• analytical data and laboratory QA/QC documentation
• field data logs that document sample collection, and appropriate QA/QC
documentation for the sample collection equipment (gas meters, thermocouples, etc.)
• calibration gas certificates
The following subsections present procedural concerns for the emissions tests. Appendix E summarizes
operational concerns which are often overlooked during emissions testing.
6.4.1. Gaseous Pollutant Sampling
This GVP specifies analyzers for the majority of the emission tests. A heated probe and sample line
conveys the exhaust gas sample to the appropriate pumps, filters, conditioning systems, manifolds, and
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then to the analyzers. Analysts report the CO2, CO, O2, NOX, and SO2 concentrations in parts per million
volume (ppmv) or percent on a dry basis.
The THC analyzer reports concentrations in ppmv on a wet basis. Analysts should use the results of the
Method 4 test to correct the concentrations to a dry basis.
Method 18 CH4 analysis requires the collection of time-integrated exhaust samples with a suitable probe
and evacuated stainless steel cylinders or a probe, sample pump, and Tedlar bags. An orifice or valve
regulates the sampling rate to correspond to the test run's duration. Test personnel should document the
samples in the field and transfer them to an analytical laboratory under signed chain-of-custody forms.
The laboratory will analyze the samples for CH4 with an FID-equipped gas chromatograph.
6.4.2. Total Particulate Matter Sampling
TPM sampling should be completed for diesel- or other oil-fired DGs. The Method 5 sampling system
collects stack gas through a nozzle and probe inserted in the stack. The test operator adjusts the velocity
of the stack gas which enters the nozzle to be the same as the stack gas velocity ("isokinetic sampling").
This minimizes TPM inertial effects and allows representative sampling.
The sample passes through a heated particulate filter whose weight gain, correlated with the sample
volume, yields the particulate concentration. Following the filter, a series of water-filled impingers
collects condensable particulate which, when dried and weighed according to Method 202, yields the
condensable particulate concentration. For this GVP, each test run should be followed by an N2 purge to
remove dissolved gases. Analysts should stabilize potential H2SO4 in the sample using the NF^OH
titration. The sum of the probe wash, nozzle wash, and the two particulate catches yields the TPM
concentration.
Sampling should occur at a series of traverse points across the area of the duct, with points selected
according to EPA Reference Method 1 [15]. On small diameter exhausts, the method allows sampling at
a single-point which represents the average gas velocity.
Testers should collect a large enough sample to allow a quantitative filter weight gain. For reciprocating
1C generators, 32 scf collected over one hour is adequate. The longer recommended test run (120
minutes) and larger sample volume (64 scf) for MTGs increases the method's sensitivity. This is because
MTG emissions are generally lower than 1C generators. The TPM test run should occur during the
instrumental analyzer test runs.
6.4.3. Exhaust Gas Flow Rate
Testers may employ either Method 2 or Method 19 for exhaust gas flow rate determinations. Method 2
measurements require a traverse of the exhaust duct with a pitot and manometer and correlation with the
Method 3 (stack gas composition) and Method 4 (stack gas moisture content) determinations.
Method 19 employs "F-Factors" to estimate the combustion gas volume based on the fuel composition.
This GVP recommends use of the F-factors in Table 19-2 of the method for natural gas, propane, or diesel
fuel.
Analysts should calculate a site-specific F-factor for other fuels. This requires the fuel's ultimate carbon,
hydrogen, oxygen, nitrogen, and sulfur elemental composition. Testers should collect one fuel sample at
each power command (three samples total) during a valid emission test run and forward the samples to the
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laboratory for analysis. The laboratory should use accepted analytical procedures (not specified here)
which yield ±1.0 percent accuracy for each constituent. Analysts should use the mean analysis of the
three samples in the Method 19 F-factor calculation. Appendices B6 and B7 provide the sampling
procedure, log form, and chain of custody form.
The estimated exhaust gas flow rate uncertainty from use of Method 19 is approximately ±3.2 percent,
based on the ±1.0 percent analytical accuracy. This GVP assumes that use of standard F-factors results
in the same uncertainty level.
6.4.4. Emission Rate Determination
Emission testing provides exhaust gas concentrations as percent CO2 and O2, ppmvd CO, CFi4, NOX, SO2,
and THCs, and gr/dscf TPM. Analysts first convert the measured pollutant concentrations to pounds per
dry standard cubic foot (Ib/dscf) and correlate them with the run-specific exhaust gas flow rate to yield
Ib/h. The report will include the mean of the three test results at each power command as the average
emission rate for that setting. The report will also cite the normalized emission rates in pounds per
kilowatt-hour (Ib/kWh).
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7.0 QA/QC AND DATA VALIDATION
7.1. ELECTRICAL PERFORMANCE DATA VALIDATION
After each test run, analysts should review the data and classify it as valid or invalid. All data will be
considered valid once demonstration of all equipment QA/QC checks is completed. Data will only be
invalidated if there is a specific reason for its rejection (such as process upsets or equipment malfunction),
and the report will cite those reasons.
Each test run, to be considered valid, must include:
• at least 90 percent of the one-minute average power meter data
• data and log forms that show the DG operation conformed to the permissible
variations throughout the run
• ambient temperature and pressure readings at the beginning and end of the run
• gas meter or liquid fuel day tank scale readings at the beginning and end and at least
5 readings during the run
• at least 3 complete kW or kVA readings from each external parasitic load
• completed field data log forms with accompanying signatures
• data that demonstrates all equipment met the allowable QA/QC criteria summarized
in Table 7-1
Table 7-1. Electrical Generation Performance
QA/QC Checks
Measurement
kW, kVAR, PF, I, V,
f(Hz), THD
V,I
All power parameters
Ambient temperature
Ambient barometric
pressure
QA/QC Check
Power meter NIST-
traceable calibration
CT documentation
Field QC sensor function
checks
( Appendix Bl)
Cross check against meter
of similar accuracy
Data logger function check
NIST-traceable calibration
NIST-traceable calibration
When
Performed
6-year intervals
At purchase
Beginning of
load tests
Before or during
field testing
Beginning of
load tests
18-month period
18-month period
Allowable Result
See Table 2-1
ANSI Metering Class 0.3 %;
+ 1.0% to 360 Hz (6th
harmonic)
V: +2.0%
I: +3.0%
V: +2.0%
I: +2.0%
Data records within ± 2 % of
meter display
+ 1°F
+ O.lpsia
7.1.1. Uncertainty Evaluation
CT and power meter errors compound together to yield the measurement uncertainty for most of the
electrical parameters. Table 7-2 shows the maximum allowable error for each electrical parameter based
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on this GVP's power meter and CT accuracy specifications. The table also includes references to
applicable codes and standards from which these errors were derived.
Table 7-2. Power Parameter
Maximum Allowable Errors"
Parameter
Voltage
Current
Real power
Reactive power
Frequency
Power factor
Voltage THD
Current THD
Accuracy
+ 0.5 % (class B)
+ 0.5 % (class B)*
+ 0.7 % overall*
+ 1.5% overall*
+ 0.01 Hz (class A)
+ 2.0 %*
+ 5.0 %
+ 5.0 % (to 360
Hz)*
Reference
IEC 6 1000-4-30 [2]
IEC 6 1000-4-30 [2]
IEC 6 1000-4-30 [2]
n/a
IEC 6 1000-4-30 [2]
IEEE 929 [5]
IEC 6 1000-4-7 [6]
IEC 6 1000-4-7 [6]
"All accuracy specifications are percent of reading except for frequency.
*Power meter and CT compounded uncertainty.
If the CTs and power meter calibration accuracies meet the Table 7-1 accuracy specifications, analysts
may report the Table 7-2 values as the achieved accuracy. If the power meter and CT accuracy is less
than specified in Table 7-1, analysts should estimate and report achieved accuracy according to the
Appendix G procedures for estimating compounded error.
If measurement accuracy is better than the Table 7-1 specifications, analysts may either report the Table
7-2 values or calculate and report the achieved accuracies using the Appendix G procedures. Note that
analysts may also use the Appendix G procedures to calculate and report achieved accuracy for THD for
harmonic frequencies higher than 360 Hz if CT (and power meter) accuracy data are available for those
frequencies.
7.2. ELECTRICAL EFFICIENCY DATA VALIDATION
After each test run and upon receipt of the laboratory results, analysts will review the data and classify it
as valid or invalid. All invalid data should be associated with a specific reason for its rejection, and the
report should cite those reasons.
Each test run, to be considered valid, must include:
• at least 90 percent of the one-minute average power meter data
• log forms that show the DG operation conformed to the permissible variations
throughout the test run (Table 2-2)
• ambient temperature and pressure readings at the beginning and end of the run
• gas meter or day tank scale readings at the beginning, end, and at least one reading
during the run
• completed field data log forms with accompanying signatures
• at least one fuel sample collected at each of the three power command settings, with
log forms that show sample collection occurred during a valid test run.
• data that demonstrates all equipment met the allowable QA/QC criteria summarized
in Table 7-1 (power meter, CTs, ambient temperature, and ambient pressure sensors)
and Table 7-3.
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Table 7-3. Electrical Efficiency
QA/QC Checks
Measurement /
Instrument
Gas meter
Gas pressure
Gas temperature
Weighing scale (DG
< 500 kW)
Flow meter(s) (DG >
500 kW)
Gas LHV, HHV:
ASTMD1945,
D3588
Liquid fuel LHV,
HHV: ASTMD4809
QA/QC Check
NIST-traceable calibration
Field QC check - Differential
rate test for gaseous fuel meters
NIST-traceable calibration
NIST-traceable calibration
NIST-traceable calibration
Field QC check - challenge scale
with reference standard weights
NIST-traceable calibration
NIST-traceable standard gas
calibration
ASTM D1945 duplicate sample
analysis and repeatability
Benzoic acid standard calibration
When Performed
Upon purchase or
after repairs
Beginning of test
2-year period
2-year period
2-year period
Beginning and end of
test
Upon purchase or
after repairs
Weekly
Once per lot of
samples
Weekly
Allowable Result
+ 1.0% of reading
± 10 % of expected differential
pressure from calibration curve
+ 0.5%FS
+ 4.5 °F
+ 0.1% of reading
± 2 % of reference standard
Single flow meter: + 1.0 %,
compensated to 60 °F
Differential flow meter (diesel 1C
generators only): differential value +
1.0 %, compensated to 60 °F
+ 1.0% of reading
Within D 1945 repeatability limits for
each gas component
+ 0.1 % relative standard deviation
7.2.1. Uncertainty Evaluation
Table 7-4 shows the estimated r|e uncertainty for electrical efficiency for gaseous and liquid fuels if each
of the contributing measurements and determinations meet this GVP's accuracy specifications.
Table 7-4. Electrical Efficiency
Uncertainty
Gaseous
Fuels
Liquid
Fuels
Parameter
Real Power, kW
Fuel Heating Value (LHV
orHHV),Btu/scf
Fuel Rate, scfh
Efficiency, ne
Real Power, kW
Fuel Heating Value (LHV
orHHV),Btu/scf
Fuel Rate, Ib/h
Efficiency, i\e
Relative Accuracy, %
External Parasitic
Loads Measured
askVA
+ 2.2
+ 1.0
+ 1.8
±3.0
+ 2.2
+ 0.5
+ 2.8
±3.6
External Parasitic
Loads Measured
askW
+ 0.7
+ 1.0
+ 1.8
2.2
+ 0.7
+ 0.5
+ 2.8
±2.9
The uncertainty evaluation is conducted using the procedures in Appendix G. If the contributing
measurement errors and the resulting real power, fuel heating value, and fuel consumption rate
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determinations meet this GVP's accuracy specifications, analysts may report the appropriate table entries
as the T|e uncertainty. Otherwise use procedures outlined in Appendix G to determine the actual
uncertainty.
7.3. CHP PERFORMANCE DATA VALIDATION
After each test run and upon receipt of the laboratory results, analysts should review the data and classify
it as valid or invalid. All invalid data will be associated with a specific reason for its rejection, and the
report will cite those reasons.
Each CHP performance test run, to be considered valid, must include:
• at least 90 percent of the one-minute average Vi, Tsuppiy, and Treturn data
• completed field data log forms with accompanying signatures
• appropriate NIST-traceable calibrations and successful sensor function checks for the
measurement instruments
• laboratory results for at least one heat transfer fluid sample (if other than water)
collected during the load test phase
• data and field log forms that demonstrate all equipment and laboratory analyses meet
the QA/QC criteria summarized in Table 7-5.
Table 7-5. CHP Thermal Performance and Total Efficiency
QA/QC Checks
Description
Heat transfer fluid flow
meter
Tsuppiy and Treturn sensor
and transmitter
Heat transfer fluid density
v/aASTMD 1298 (for
fluids other than water)
QA/QC Check
NIST-traceable calibration
Field QC check - sensor
function checks
Field QC check - Zero
flow response check
NIST-traceable calibration
Field QC check - Sensor
function check
Laboratory analysis
temperature set to Tava
Hydrometer NIST-
traceable verification
Thermometer NIST-
traceable verification
When Performed
2-year period
at installation
at installation;
immediately prior to the
first test run
18-month period
at installation
each sample
2-year period
2-year period
Allowable Result
+ 1.0% of reading
See Appendix B8
Less than +1.0% of FS
+ 1 °F between 100 and
210 T
See Appendix B8
+ 1°F
Maximum error + 0.5
kg/m3
Maximum error + 0.2 °C
(+ 0.5 °F)
For actual and maximum total system efficiency determinations (in heating service), each thermal
efficiency one-minute average must have a contemporaneous electrical efficiency one-minute average.
This will allow analysts to determine the one-minute total efficiencies and subsequently the run-specific
average efficiencies. The permissible variations within each test run should conform to the Table 2-2
specifications.
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7.3.1. Uncertainty Evaluation
Assuming that all instruments and measurements conform to this GVP's accuracy specifications
(including the stipulation that actual AT equals or exceeds 20 °F), Table 7-6 shows the contributing errors
and estimated uncertainty for:
• thermal performance (Qout) in heating and chilling service
• T|th and T|tot in heating service.
Table 7-6. Individual Measurement
AT, Qout, nth, and %,t Accuracy
Description
Heat transfer fluid flow, Vi, gph
AT, °F
cp, Btu/lb.°F
p, Ib/gal
Qout, Btu/h
Gaseous Fuels
Liquid Fuels
Heating Value, Btu/scf
Fuel rate, scfh
Qm, Btu/h
Tlth (Qout/Qin*100), %
Tie, %
Tltot, %
Heating Value, Btu/scf
Fuel rated, scfh
Qm, Btu/h
Tlth (Qou,/Qin*100), %
Tie, %
lltot, %
Relative Error
+ 1.0 %
+ 4.3 % when AT > 20 °F
+ 0.1%
+ 0.2 %
± 4.4 %
+ 1.0 %
+ 1.8 %
+ 2.1%
+ 4.9 % (+ 2.6 % absolute error)
+ 3.0 % (+ 0.8 % absolute error)
± 3.5 % (+ 2.8 % absolute error)"
+ 0.5 %
+ 2.8 %
+ 2.8 %
+ 5.2 % (+ 2.8 % absolute error)
+ 3.6 % (+ 0.9 % absolute error)
± 3.7 % (+ 2.9 % absolute error)2
CHP Service
Heating and
chilling
service
Heating
service
"Assumed r\^ is 53 %, TT.e is 26 %, TT.tot is 79 %;
estimation procedures.
See Appendix T for absolute versus relative error
Overall uncertainty can deteriorate significantly if the given measurement accuracy specifications are not
met. For example, if AT is 5 °F, its relative accuracy (given the specified ± 1 °F temperature sensor
accuracy) will be ± 17.0 percent. This is much less accurate than the ±4.3 percent when AT is 20 °F or
more. The resulting overall r|tot relative uncertainty for a gas-fired MTG-CHP would be ± 11.5 percent
instead of the ±3.5 percent shown in Table 7-6
If measurement accuracies and determination uncertainties exceed the Table 7-6 specifications, analysts
should estimate and report achieved uncertainty according to the Appendix G procedures.
If measurement accuracies and determination uncertainties are better than the Table 7-6 specifications,
analysts may either report the Table 7-6 estimated parameter uncertainties or calculate and report the
achieved uncertainties using the Appendix G procedures.
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7.4. EMISSIONS DATA VALIDATION
The reference methods specify detailed sampling methods, apparatus, calibrations, and data quality
checks. The procedures ensure the quantification of run-specific instrument and sampling errors and that
runs are repeated if the specific performance goals are not met. Table 7-8 summarizes relevant QA/QC
procedures. Satisfaction and documentation of each of the calibrations and QC checks will verify the
accuracy and integrity of the measurements.
The field test personnel or emissions testing contractor will be responsible for all emissions data, QA log
forms, and electronic files until they are accepted by the test manager. The test manager should validate
that:
• each of the QA/QC checks noted in Table 7-8 are completed satisfactorily
• all instrumental analyzer results are in the form of chart recorder records or directly-
recorded electronic data files. Each directly-recorded data file should consist of a
series of one-minute averages, and each one-minute average should include at least
ten data points taken at equal intervals during that minute
• all field data are at least 90 percent complete
• all paper field forms, chart records, calibrations, etc. are complete, dated, and signed
• emission testers have reported their results in ppmv for NOX, SO2, THC, QrU and
CO, percent for O2 and CO2, or gr/dscf for TPM, all concentrations corrected to 15
percent O2, and run-specific emission rates (Ib/hr)
7.4.1. Uncertainty Evaluation
Table 7-7 specifies the compounded maximum parameter uncertainties for the test results if the
calibrations and QA/QC checks specified in this GVP and the EPA Reference Methods 5 and 202 are
achieved. In such cases, the compounded maximum measurement error can be cited as the parameter
uncertainty.
Table 7-7. Compounded Maximum Emission Parameter Errors
Parameter
CO, NOX ,
or %)
CH4, THC,
CO, NOX ,
CH4, THC,
CO2, O2, and SO2 concentration (ppmv
and TPM concentration (ppmv)
CO2 and SO2 emission rates (Ib/kWh)
and TPM emission rates (Ib/kWh)
Maximum Error, %
2.0
5.0
4.4
6.3
If the QC checks or calibration specifications are not met, or if measurement errors are greater than those
specified in Table 7-7, testers must repeat test runs.
Each of the instrumental methods includes performance-based specifications for the gas analyzer. These
performance criteria cover analyzer span, calibration error, sampling system bias, zero drift, response
time, interference response, and calibration drift requirements. EPA Methods 4 and 5 include detailed
performance requirements for moisture and TPM determinations. Instruments and equipment should
meet the quality control checks specified in Table 7-8 as well as the more detailed Reference Method
specifications.
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Table 7-8. Summary of Emission Testing
Calibrations and QA/QC Checks
Parameter"
CO,
C02,
O2,
S02
NOX
THC
CH4
TPM
Calibration/QC
Check*
Analyzer calibration
error test
System bias checks
System calibration drift
test
Analyzer interference
check
NO2 converter
efficiency
Sampling system
calibration error and
drift checks
System calibration error
test
System calibration drift
test
Duplicate analysis
Calibration of GC with
gas standards by
certified laboratory
Minimum sample
volume
Percent isokinetic rate
Analytical balance
calibration
Filter and reagent
blanks
Sampling system leak
test
Dry gas meter
calibration
Sampling nozzle
calibration
When
Performed/F requeue
y
Daily before testing
Before each test run
After each test run
Once before testing
begins
Before and after each
test run
Daily before testing
After each test run
For each sample
Immediately prior to
sample analyses
and/or at least once
per day
After each test run
After each test run
Daily before analyses
Once during testing
after first test run
After each test
Once before and once
after testing
Once for each nozzle
before testing
Allowable
Result
± 2 % of
analyzer span
± 5 % of
analyzer span
± 3 % of
analyzer span
± 2 % of
analyzer span
98 % minimum
± 2 % of
analyzer span
± 5 % of
analyzer span
± 3 % of
analyzer span
± 5 % difference
±5%
Corrected Vol. >
64dscf(MTG)
or32dscf(IC
generator)
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Table 7-8. Summary of Emission Testing
Calibrations and QA/QC Checks
Parameter"
Calibration/QC
Check*
When
Performed/F requeue
y
Allowable
Result
Response to Check Failure
or Out of Control
Condition
" EPA reference methods are used to determine each parameter as listed in Table 5-2.
" Definitions and procedures for each of the calibration and QC checks specified here are included in the applicable
reference method and not repeated here.
7.5. TQAP QA/QC REQUIREMENTS
The following sections describe additional QA/QC requirements that are specified in the ETV quality
management plan (QMP). These QA components should be presented in a TQAP on a verification
specific basis. These requirements are specified in the GHG Center's Quality Management Plan [16].
7.5.1. Duties and Responsibilities
The TQAP must include an organizational chart identifying a project manager, field team leader, GHG
Center QA manager, the EPA QA manager, and key representatives for vendors, verification host
facilities, and subcontractors. The TQAP will also identify the responsibilities and duties of each person
identified in the organization chart including the following:
• Overall project management and coordination
• Management of field testing staff and subcontractors
• Data review and validation
• QA/QC review at both the GHG Center and EPA levels
7.5.2. Data Quality Objectives
For each of the verification parameters specified in a TQAP, the document should also specify data
quality objectives (DQOs). It is expected that the DQOs will generally be to meet and demonstrate the
methods, procedures, and QA/QC checks of this GVP. For some verifications however, there may be
need to deviate from the GVP requirements based on technology or facility specific variables. For each
of the DQOs, the TQAP should also specify data quality indicators (DQIs) that will be used to
demonstrate achievement of the DQOs. For qualitative DQOs that reference the procedures and QA/QC
checks in this GVP, the QA/QC checks of this section will represent the DQIs.
7.5.3. Reviews, Assessments, and Corrective Action
Following QMP guidelines, the TQAP should specify what types of reviews and assessments are planned
for the verification and who will conduct these activities. These can include the following:
• Vendor, peer, and QA document reviews
• Audits of data quality
• Field readiness reviews
• Technical systems audits
• Performance evaluation audits
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The TQAP will also include a plan for corrective action. Corrective action must occur when the result of
an audit or quality control measurement is shown to be unsatisfactory, as defined by the DQOs or by the
measurement objectives for each task. The corrective action process involves the field team leader,
project manager, and QA manager.
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8.0 REPORTS
Each report should group the results for the valid test runs at each power command setting together. The
report for each tested parameter should cite:
• run-specific mean, maximum, minimum, and standard deviation
• run-specific assessment of the permissible variations within the run
• overall mean, maximum, minimum, and standard deviation for all valid test runs
Each test report should also contain the following:
• SUT block diagram which shows:
major components
internal and external parasitic loads
electrical interconnections (one line diagram)
fuel and CHP heat transfer fluid flows
- measurement equipment locations
• maximum short-circuit current ratio
• ambient conditions (temperature, barometric pressure) observed during each test run
and a comparison between the observed conditions and the standard conditions at
which the manufacturer rated the DG (usually ISO standard of 60 °F, 14.696 psia)
• description of measurement instruments and a comparison of their accuracies with
those specified in the GVP (distinguish between accuracy estimated from
specifications and accuracy determined by measurement).
• summary of data quality procedures, results of QA/QC checks, the achieved accuracy
for each parameter, and the method for citing or calculating achieved accuracy
• copies of laboratory QA documentation, including calibration data sheets, duplicate
analysis results, etc.
• results of data validation procedures including a summary of invalid data and the
reasons for its invalidation
• information regarding any variations from the procedures specified in this GVP
• narrative description of the DG installation, site operations, and field test activities
including observations of site details that may impact performance. These include
thermal insulation presence, quality, mounting methods that may cause parasitic
thermal loads etc.
• copies of all completed field data forms and calibration certificates
Reports may optionally contain trend analyses and commentary. Extrapolation to different operating
conditions (such as ISO conditions, SUT performance during other seasons, or part-load performance for
CHP systems) may be included if they are supported by we 11-documented laboratory-based performance
curves. Such extrapolations should be flagged as approximations only.
Testers should archive all original field data forms and maintain records for at least two years. They or
the database managers will store all one-minute data, valid and invalid, as ASCII comma-separated-value
(CSV) text files in at least two locations (CD-ROM and secure web server hard disk, for example). Text
headers for all CSV data files should include, at minimum:
• test site name
• test site location
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• test site business / mailing address, telephone number, and contact person
• DG system make, model, serial number, commissioning date, and hours of runtime at
the beginning of the test campaign
• test manager name, title, company, address, and telephone number
The printed report should note the data file names and locations and should specify how readers may
obtain copies.
The following subsections itemize the reported parameters.
8.1. ELECTRICAL PERFORMANCE REPORTS
Electrical performance test reports, as conducted according to Section 6.1, for each power command and
test run should include:
• total real power (all three phases) without external parasitic loads, kW
• total reactive power (all three phases), kVAR
• total power factor (all three phases), percent
• voltage (for each phase and average of all three phases), V
• current (for each phase and average of all three phases), A
• frequency, Hz
• Voltage THD (for each phase and average of all three phases), percent
• Current THD (for each phase and average of all three phases), percent
• apparent power consumption for each external parasitic load, kVA
• total real power including debits from all external parasitic loads, kW. Also, include
information regarding external parasitic loads that serve multiple sources and that
were not included in the net power evaluation
• electrical one-line diagram for the SUT
8.2. ELECTRICAL EFFICIENCY REPORTS
Electrical efficiency test reports, as conducted according to Section 6.2, for each power command and test
run, should include:
• electrical generation efficiency (TI^LHY) without external parasitic loads
• electrical generation efficiency (TI^LHY) including external parasitic loads
• heat rate (HRLHV) without external parasitic loads
• heat rate (HRLHv) including external parasitic loads
• total kW
• heat input (Qm,LHv), Btu/h
• fuel input (Vg std for gas, m for liquid), scfh or Ib/h
• electrical one-line for the SUT
The report should quote all laboratory analyses for:
• fuel heating value (LHV) for each power command setting, Btu/scf or Btu/lb
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Note that electrical generation efficiency uncertainty should be reported in absolute terms. For example,
if T|e,LHv for gaseous fuel is 26.0 percent and all measurements meet the accuracy specifications in this
GVP, the relative error is ± 3.0 percent (see Table 7-4). The absolute error is 26.0 times 0.030, or ± 0.78
percent. The report, then, should state rjeLHv as "26.0 ±0.8 percent". This will prevent confusion
because, for efficiency, both relative and absolute errors can be reported as percentages.
8.3. CHP THERMAL PERFORMANCE REPORTS
Thermal performance test reports for CHP systems in heating service, as conducted according to Section
6.3, for each power command setting and test run, should include:
• actual thermal performance (Qout), Btu/h
• actual thermal efficiency (r|th LHv)
• actual total system efficiency (r|tot LHv)
• maximum thermal energy available for recovery (sum of actual thermal energy
transferred and thermal energy available from cooling towers), Btu/h
• maximum thermal efficiency (r|th,LHv)
• maximum SUT efficiency (r|tot LHv)
• heat transfer fluid supply and return temperatures, °F, and flow rates, gpm for each
heat transfer fluid loop measured
This GVP recommends reporting r|th and r|tot and their achieved accuracies in absolute terms because
efficiency and relative accuracies are both percentages. Refer to the previous subsection for a discussion
on avoiding potential confusion due to terminology.
Test reports for CHP systems in chilling service should include:
• actual thermal performance, Btu/h and refrigeration tons (RT)
• heat transfer fluid supply and return temperatures, °F, and flow rates, gpm for each
heat transfer fluid loop measured
• thermal energy available for recovery from cooling tower(s), Btu/h
Reports for all CHP systems should include:
• heat transfer fluid type(s)
• laboratory heat transfer fluid density results for each sample analyzed
• average cp for each heat transfer fluid analyzed
• average p for each heat transfer fluid analyzed
• summary piping and heat flow schematic diagram for the SUT
8.4. ATMOSPHERIC EMISSIONS REPORTS
The testing contractor should provide a final emissions testing report for tests conducted according to
Section 6.4. Reported parameters for each test run at each power command should include the following:
emission concentrations for CO, CFU, NOX, SO2, THCs, and other pollutants
evaluated in ppmv, % for O2, CO2, and gr/dscf for TPM as measured and corrected to
15%O2
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• emission rates for CO2, CO, CH4, NOX, SO2, THCs, TPM, and other pollutants
evaluated as Ib/hr and Ib/kWh electrical generation
• exhaust gas dry standard flow rate, actual flow rate, and temperature
• exhaust gas composition, moisture content, and molecular weight
• isokinetic sampling rate (TPM tests only)
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9.0 REFERENCES
[1] ANSI C'12.20-2002: Code for Electricity Meter—0.2 and 0.5 Accuracy Classes. National Electrical
Manufacturers' Association, American National Standards Institute, Rosslyn, VA. 2001, www.ansi.org.
[2] IEC 61000-4-30: Electromagnetic Compatibility (EMC)—Part 4-30: Testing and Measurement
Techniques-Power Quality Measurement Methods. International Electrotechnical Commission, Geneva,
Switzerland. 2003, www.iec.ch.
[3] ASME PTC 22-1997—Performance Test Code on Gas Turbines. American Society of Mechanical
Engineers, New York, NY. 1997, www.asme.org.
[4] ASME PTC 17-1997—Reciprocating Internal-Combustion Engines. American Society of Mechanical
Engineers, New York, NY. 1997, www.asme.org.
[5] IEEE Std. 929-2000—IEEE Recommended Practice for Utility Interface of Photovoltaic (PV)
Systems. Institute of Electrical and Electronics Engineers, New York, NY. 2000, www.ieee.org.
[6] IEC 61000-4-7: Electromagnetic Compatibility (EMC) - Part 4-7: Testing and Measurement
Techniques - General Guide on Harmonics and Interharmonics Measurements and Instrumentation for
Power Supply Systems and Equipment Connected Thereto. International Electrotechnical Commission,
Geneva, Switzerland. 2002, www.iec.ch.
[7] MTG Test Protocol, Ver. 1.0. Advanced Power and Energy Program (APEP), University of
California, Irvine. Irvine, CA. 2003, www.apep.uci.edu/.
[8] ASTM D1945-98—Standard Test Method for Analysis of Natural Gas by Gas Chromatography.
American Society for Testing and Materials, West Conshohocken, PA. 2001, www.astm.org.
[9] ASTM D3588-98—Standard Practice for Calculating Heat Value, Compressibility Factor, and
Relative Density of Gaseous Fuels. American Society for Testing and Materials, West Conshohocken,
PA. 2001.
[10] ASTM D1298-99—Standard Test Method for Density, Relative Density (Specific Gravity), or API
Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method. American Society
for Testing and Materials, West Conshohocken, PA. 1999, www.astm.org.
[11] ASTM D4809-00—Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by
Bomb Calorimeter (Precision Method). American Society for Testing and Materials, West
Conshohocken, PA. 2001, www.astm.org.
[12] CRC Handbook of Chemistry and Physics. Robert C. Weast, Ph.D., editor, CRC Press, Inc., Boca
Raton, FL. 1980.
[13] ASHRAE Fundamentals Handbook—Chapter 21: Physical Properties of Secondary Coolants
(Brines). American Society of Heating, Refrigeration, and Air-Conditioning Engineers, Inc., Atlanta,
GA. 2001, www.ashra.org.
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[14] ASTM Dl 298-99 Standard Test Method for Density, Relative Density (Specific Gravity), or API
Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method. American Society
for Testing and Materials, West Conshohocken, PA. 1999, www.astm.org.
[15] Code of Federal Regulations (Title 40 Part 60, Appendix A) Test Methods (Various), U.S.
Environmental Protection Agency, Washington, DC, www.gpoaccess.gov/cfr/.
[16] Southern Research Institute. Environmental Technology Verification Greenhouse Gas Technology
Verification Quality Management Plan, Version 1.2, Research Triangle Park, NC, January 2001,
www.sri-rtp.com.
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Appendix A
Acronyms and Abbreviations
A ampere h
acfh actual cubic feet per hour HHV
ASERTTI Association of State Energy Hz
Research and Technology 1C
Transfer Institutions
ASTM American Society for ID
Testing and Materials ISO
Btu British thermal unit
Btu/h Btu per hour kAIC
Btu/kWh Btu per kiloWatt-hour kVA
Btu/lb Btu per pound
Btu/scf Btu per standard cubic foot kVAR
BoP balance of plant
cp specific heat (constant kW
pressure) kWh
CARB California Air Resources LHV
Board Ib
CH4 methane Ib/gal
CHP combined heat and power Ib/h
cm centimeter Ib/kWh
CO carbon monoxide Ib/lb.mol
CO2 carbon dioxide mA
CoP coefficient of performance ml
CSV comma-separated value mph
CT current transformer m/s
DG distributed generation MTG
DOE US Department of Energy MTG-CHP
OUT device under test NDIR
DVM digital volt meter NIST
dscfh dry standard cubic feet per
hour NO*
EPA US Environmental O2
Protection Agency PC
EPS electric power system PCC
ETV Environmental Technology PF
Verification PG
FID flame ionization detector ppm
FS full scale ppmvd
GC/FID gas chromatography with psia
flame ionization detector
GHG greenhouse gas psig
gph gallons per hour
gpm gallons per minute PT
gr/dscf grains per dry standard QA/QC
cubic foot
GVP Generic Verification rms
Protocol RT
hour
higher heating value
Hertz
reciprocating internal-
combustion engine
induced draft
International Organization
for Standardization
kiloampere interrupt current
kilovolt-ampere (apparent
power)
kilovolt-ampere reactive
(reactive power)
kilowatt (real power)
kilowatt-hour
lower heating value
pound
Ib per gallon
Ib per hour
IbperkWh
Ib per Ib-mole
milliamp
milliliter
miles per hour
meters per second
microturbine generator
MTG with CHP
non-dispersive infra-red
National Institute of
Standards and Technology
nitrogen oxides
oxygen
personal computer
point of common coupling
power factor
propylene glycol
parts per million
ppm, volume basis, dry
pounds per square inch,
absolute
pounds per square inch,
gage
potential transformer
quality assurance /
quality control
root-mean-square
refrigeration ton
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scf standard cubic feet
scfh scf per hour
SO2 sulfur dioxide
SUT system under test
THC total hydrocarbons
THD total harmonic distortion
THCD total harmonic current
distortion
THVD total harmonic voltage
distortion
TPM total particulate matter
UIC University of Illinois at
Chicago
V volt
September 2005
VA
VAR
w
°C
OF
°R
AT
volt-ampere (apparent
power)
volt-ampere reactive
(reactive power)
Watt
degree Centigrade
degree Fahrenheit
degree Rankine, absolute
absolute temperature
difference, °R or °F
efficiency, percent
density, Ib/gal
Notation for References, Tables etc.
All Figures and Tables in the GVP document are numbered using the Section number followed by a
sequential digit. Appendices replace the Section number with the Appendix letter. Example references
within the test are:
Figure 3-2 The second figure in Section 3
Table 6-1 The first table in Section 6
Eqn. D18 The 18th equation occurring in Appendix D
References within the main text appear as a sequential number within square brackets, or [4] (fourth
reference in the document) and may be found at the back of the document. References within the
appendices appear as[D4] (fourth reference in Appendix D) and may be found at the back of the indicated
appendix.
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Appendix B
Bl. Power Meter Commissioning Procedure
1. Obtain and read the power meter installation and setup manual. It is the source of the items
outlined below and is the reference for detailed information.
2. Verify that the power meter calibration certificate, CT manufacturer's accuracy certification,
supplementary instrument calibration certificates, and supporting data are on hand.
3. Mount the power meter in a we 11-ventilated location free of moisture, oil, dust, corrosive vapors,
and excessive temperatures.
4. Mount the ambient temperature sensor near to but outside the direct air flow to the DG
combustion air inlet plenum but in a location that is representative of the inlet air. Shield it from
solar and ambient radiation.
5. Mount the ambient pressure sensor near the DG but outside any forced air flows.
6. Ensure that the fuel consumption metering scheme is in place and functioning properly.
7. Verify that the power meter supply source is appropriate for the meter (usually 110 VAC) with
the DVM and is protected by a switch or circuit breaker.
8. Connect the ground terminal (usually the "Vref' terminal) directly to the switchgear earth ground
with a dedicated AWG 12 gauge wire or larger. Refer to the manual for specific instructions.
9. Choose the proper CTs for the application. Install them on the phase conductors and connect them
to the power meter through a shorting switch to the proper meter terminals. Be sure to properly
tighten the phase conductor or busbar fittings after installing solid-core CTs.
10. Install the voltage sensing leads to each phase in turn. Connect them to the power meter terminals
through individual fuses.
11. Trace or color code each CT and voltage circuit to ensure that they go to the proper meter
terminals. Each CT must match its corresponding voltage lead. For example, connect the CT for
phase A to meter terminals IAi and IA2 and connect the voltage lead for phase A to meter terminal
VA.
12. Energize the power meter and the DG power circuits in turn. Observe the power meter display (if
present), datalogger output, and personal computer (PC) display while energizing the DG power
circuits.
13. Perform the power meter sensor function checks. Use the DVM to measure each phase voltage
and current. Acquire at least five separate voltage and current readings for each phase. Enter the
data on the Power Meter Sensor Function Checks form and compare with the power meter output
as displayed on the datalogger output (or PC display), power meter display (if present), and
logged data files. All power meter voltage readings must be within 2% of the corresponding
digital volt meter (DVM) reading. All power meter current readings must be within 3% of the
corresponding DVM reading.
14. Verify that the power meter is properly logging and storing data by downloading data to the PC
nnrl rfM/ipix/ina it
J A
and reviewing it.
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Bl. Power Meter Sensor Function Checks
Project Name:_
Date:
DUT Description:
Nameplate kW:
Type (delta, wye):_
Power Meter Mfr:
Last NISTCal. Date:
Current (at expected max. kW):_
Current Transformer (CT) Mfg:_
CT Accuracy: (0.3 %, other): _
Location (city, state):_
Signature:,
Expected max. kW:_
Voltage, Line/Line:_
Model:
Line/Neutral:
Serial No.:
.Conductor type & size:
Model:
Ratio (100:5, 200:5, other):_
Sensor Function Checks
Note: Acquire at least five separate readings for each phase. All power meter voltage readings must be within 2%
of the corresponding digital volt meter (DVM) reading. %Diff = (\PowerMeter'/DVM\ -1) * 100
Voltage
Date
Time
(24 hr)
Phase A
Power
Meter
DVM
%Diff
Phase B
Power
Meter
DVM
%Diff
Phase C
Power
Meter
DVM
%Diff
Note: Acquire at least five separate readings for each phase. All power meter current readings must be within 3% of
the corresponding DVM reading.
Current
Date
Time
(24 hr)
Phase A
Power
Meter
DVM
%Diff
Phase B
Power
Meter
DVM
%Diff
Phase C
Power
Meter
DVM
%Diff
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B2: Distributed Generator Installation Data
Project Name:
Compiled by: (Company)
Date:
Signature:
Address 1:
Address 2:
Site Information
Owner Company:
Contact Person:
City, State, Zip:
Op'r or Technician:
Site Phone:
Address (if different):
Company Phone:
Utility Name:
Fax:
Modem Phone (if used):
Altitude (feet; meters)
Contact Person:
Utility Phone:
Installation (check one): Indoor Outdoor Utility Enclosure Other (describe)
Sketch of HVAC systems attached (if Indoor) Controls: Continuous Thermostatic
Other
Primary Configuration, Service Mode, and CHP Application
(check all that apply; indicate secondary power and CHP application information with
an asterisk, * )
Delta
Single Phase
Inverter
Grid Parallel
Demand
Management
Hot water
Indirect chiller
Wye
Three Phase
Induction
Grid Independent
Prime Power
Backup Power
Steam
Grounded Wye
Synchronous
Peak Shaving
Load Following
VAR Support
Direct-fired chiller
Other DG or CHP (describe)
Date:
Generator Nameplate Data
_Local Time (24-hour): Hour meter:
Commissioning Date:
Manufacturer:
Model:
Site Description
(Check one)
Hospital
University
Resident' 1
Industrial
Utility
Hotel
Other (desc.)
Fuel
(Check one)
Nat'l Gas
Biogas
Landfill G
Diesel #2
Other (desc.)
Serial #:
Prime mover (check one): 1C generater_
MTG
Range:
to
(kW; kVA) Adjustable? (y/n) Power Factor Range: to
Adjustable? (y/n)
Nameplate Voltage (phase/phase):
Amperes: Frequency:
Hz
Controller (check one): factory integrated 3rd-party installed custom (describe)_
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Maximum Short Circuit Current Ratio (Appendix B13):
B2: Distributed Generator Installation Data (cont.)
CHP Nameplate Data
BoP Heat Transfer Fluid Loop
Describe:
Nominal Capacity:
(Btu/h) Supply Temp.
(°F) Return Temp.
Low Grade Heat loop
Describe:
Nominal Capacity:
Chilling loop
Describe:
Nominal Capacity:
(Btu/h) Supply Temp.
(Btu/h) Supply Temp.
(°F) Return Temp. (°F)
(°F) Return Temp. (°F)
Other loop(s): Describe:
Nominal Capacity:
(Btu/h) Supply Temp.
(°F) Return Temp.
Parasitic Loads
Enter nameplate horsepower and estimated power consumption. Check whether internal or external. Internal
parasitic loads are on the DG-side of the power meter. External parasitic loads are connected outside the system
such that the power meter does not measure their effects on net DG power generation.
Description
Fuel Gas Compressor
CHP Heat Transfer Fluid Pump - Hot Fluid
CHP Heat Transfer Fluid Pump - Low Grade
CHP Heat Transfer Fluid Pump - Chilling
Fans (describe)
Name-
plate Hp
Est. kVA
orkW
Internal
(*)
External
(")
Function"
Other: Transformers, etc. (describe)
"Describe the equipment function. Also note whether the equipment serves multiple units or is dedicated to the test DG.
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Project Name:_
Date:
September 2005
B3: Load Test Run Log
Location (city, state):.
Signature:,
Run ID:
Load Setting: %_
kW
Run Start Time:
End Time:
SUT Description:
Clock synchronization performed (Initials):,
Data file names/locations (incl. path): File:
IMPORTANT: For ambient temperature and pressure, record one set of readings at the beginning and one at the
end of each test run. Also record at least two sets of readings at evenly spaced times throughout the test run.
B3-1. Ambient Temperature and Pressure
Time (24-hr)
Average
Amb. Temperature,
°F
Ambient Pressure
"Hg
PSIA = " Hg * 0.491
Permissible Variations
1. Each observation of the variables below should differ from the average of all observations by less than the maximum
permissible variation.
2. Acquire kW and Power Factor data from the power meter data file at the end of the test run. Transfer fuel flow data
from the Fuel Flow Log form. Obtain ambient temperature and pressure from Table A3-2 below. Obtain gas
temperature and pressure from Appendix B4.
3. Choose the maximum or minimum with the largest difference compared to the average for each value.
4. Use the maximum or minimum to calculate the %Diff for kW, Power Factor, Fuel Flow, and Ambient Pressure:
%Diff = ((MalorMin)-Averag/Average)*lOO Eqn. B3-1
5. For Ambient Temperature, Difference = (Max or Min)-Average
Variable
Ambient air temperature
Ambient pressure
Fuel flow
Power factor
Power output (kW)
Gas pressure
Gas temperature
Average
Maximum
Minimum
%Diffor
Difference
Acceptable?
(see below)
Permissible Variations
Measured Parameter
Ambient air temperature
Ambient pressure (barometric
station pressure)
Fuel flow
Power factor
Power output (kW)
Gas pressure
Gas temperature
MTG Allowed Range
+ 4 °F
+ 0.5 %
+ 2.0%"
+ 2.0%
+ 2.0%
n/a
n/a
1C Generator Allowed Range
+ 5°F
+ 1.0%
n/a
n/a
+ 5.0%
+ 2.0%*
+ 5°F*
"Not applicable for liquid-fueled applications < 30 kW.
*Gas-fired units only
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B4: Fuel Consumption Determination Procedure
1. Start the test ran by starting a stopwatch or timer at an integer gas meter or weighing scale reading. Log the
initial meter reading, M0, when the timer is started on the Fuel Flow Log Form below.
2. Collect each meter reading by holding the stopwatch or timer next to the meter index. Log the meter reading on
the log form every 5 minutes at the instant that the stopwatch or timer shows the required elapsed time. If a meter
reading is missed, collect a reading at the next integer minute. Cross out the missed "Stopwatch Elapsed Time"
entry and note the corrected elapsed time in the table's first column.
3. Compute the elapsed time for each interval and enter it in the "ti" column on the Fuel Flow Log Form below.
4. Record at least one 5-minute interval within 10 minutes of the start, one within 10 minutes of the end, and one
near the middle of each test ran. Other recording intervals are optional.
5. End the test ran after at least 30 minutes for MTGs or 60 minutes for 1C generators at the next integer gas meter
or weighing scale reading. Log the final meter reading, Mf, and the exact elapsed time on the Fuel Flow Log Form.
6. Perform all applicable calculations and transfer the minimum, maximum, and average to the Load Test Log
Form.
IMPORTANT: Ensure that the meter index or scale readout resolution is < 0.2 % during any complete test ran.
For example, if a MTG uses 100 ft3 of gas during a test ran, the meter index resolution must be less than 0.2 ft3.
While testing liquid-fueled units < 500 kW, the day tank may be replenished only with a common batch of fuel.
Fuel Flow Log Form
Project Name:_
Date:
Location (city, state):_
Signature:
SUT Description:,
Flow Meter Mfr.:_
Signature:
Run ID:
Model:
Load Setting: %_
Serial #:
kW
Run Start Time (24-hr):
Stopwatch
Elapsed Time
(min)
ti = (Stopwatch
Elapsed Time)
minus (Previous
Interval Elapsed
Time)
Meter or Scale Reading
Initial
Meter.
Reading,
Mo
Diff;
M.-M,.!
Hourly
Flow Rate:
Diff*60/t,
Fuel °F
Gas PSIG
(not needed
for liquid
fuel)
M.
10
M,
15
20
M,
25
M5
30
Mf
Average
Hourly Rate
Minimum
Maximum
Ambient Pressure (from Load Test Run Log):_
Gas = Average + Amb. Pressure:
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B5: External Parasitic Load Measurement Procedure
This procedure is intended to measure apparent or real power consumption for external parasitic loads.
Apparent power in volt-amperes (VA) is root-mean-square (rms) voltage times rms current, or V * A.
Apparent power equals real power in watts if the power factor is 1.00.
External parasitic loads are those located outside the SUT boundary and connected such that the power
meter cannot measure their net effect on power generation. Internal parasitic loads (control systems,
internal pumps and compressors, etc. within the SUT) draw their power from the system before the power
meter and need not be measured separately.
1. Obtain at least one set of voltage and current (or real power) measurements for each external
parasitic load at each power setting (50, 75, and 100 percent) during load tests. Each
measurement consists of a set of three readings.
2. Enter the name and description of each external parasitic load on the External Parasitic Load
Data log form (Appendix B5). They should be the same as those that appear on Installation Data
log sheet (Appendix B2).
3. Open the connection panel nearest to each parasitic load to give access to power conductors for
measurement. Conduct all measurements while SUT is operating at the prescribed load setting.
4. For three-phase loads, three phase combinations are possible: A-B, B-C, and C-A. Note that
only one phase combination (A-B) is possible for single-phase loads. With a true-rms clamp-on
DVM, probe the A-B phase combination for three seconds to read the voltage. Record the
highest reading on Appendix B5. Probe and record the next two phase combinations in turn.
This constitutes one complete voltage reading.
5. Place the meter clamp around the phase A conductor for three seconds to read the current.
Record the highest reading on Appendix B5 and proceed to the B and C phase conductors in
turn. The three readings constitute one complete current reading.
6. Repeat steps 4 and 5 until three complete voltage and current readings are recorded for each
external parasitic load.
Note that testers may also use hard-wired real power meter(s), one for each external parasitic load, or a
single clamp-on real power meter for this purpose. The real power meters may be wired to suitable
dataloggers, thus eliminating the need for manual measurements and may result in slightly more accurate
readings than achieved with the DVM method.
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Project Name:_
Date:
B5: External Parasitic Load Data
Location (city, state):_
Signature:
SUT Description:,
Run ID:
Load Setting: % kW_
Load Description:
Reading
1
2
3
Average
Volts
A-B
Volts
B-C
Volts
C-A
Apparent Power, per phase:
Amps A
VAB
AmpsA
Amps B
VBC
AmpsB
Amps C
VCA
Ampsc
kW
A-B
kW
B-C
kW
C-A
V V V
Total Apparent Power: Stot = -^Ampsa + -j=Ampsb + -j= Ampsc Stot:
V3 V3 V3
Total Real Power: kWM = - +
V3 V3
- kWtot:
kW
kVA
kWtot:
kW
kVA
kWtot:
kW
kVA
Load Description:
Reading
1
2
3
Average
Volts
A-B
Volts
B-C
Volts
C-A
Apparent Power, per phase:
AmpsA
VAB
AmpsA
Amps B
VBC
AmpsB
Amps C
VCA
Ampsc
kW
A
kW
B
kW
C
Load Description:
Reading
1
2
3
Average
Volts
A-B
Volts
B-C
Volts
C-A
Apparent Power, per phase:
AmpsA
VAB
Amps A
Amps B
VBC
AmpsB
Amps C
VCA
Ampsc
kW
A
kW
B
kW
C
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B6: Fuel and Heat Transfer Fluid Sampling Procedure
Gaseous Fuel Samples
1. Collect at least one fuel gas sample at each power command setting during a valid test run into an
evacuated sample cylinder
2. Attach a leak free vacuum gauge to the sample canister inlet. Open the canister inlet valve and
verify that the canister vacuum is at least 15 "Hg. Record the gage pressure on the Fuel Sampling
Log form (Appendix A6).
3. Close the canister inlet valve, remove the vacuum gauge, and attach the canister to the fuel line
sample port.
4. Open the fuel line sample port valve and check all connections for leaks with bubble solution or a
hand-held analyzer. Repair any leaks, then open the canister inlet valve. Wait 5 seconds to allow
the canister to fill with fuel.
5. Open the canister outlet valve and purge the canister with fuel gas for at least 15, but not more
than 30 seconds. Close the canister outlet valve, canister inlet valve, and fuel line sampling port
valve in that order.
6. Obtain the fuel gas pressure and temperature from the gas meter's pressure and temperature
instrumentation. Remove the canister from the sampling port. Enter all required information
(date, time, canister ID number, etc.) on the Fuel Sampling Log.
7. Fill out the Chain of Custody form (Appendix B7) and sample labels. Forward the samples to the
analytical laboratory accompanied by the form. Retain a copy for inclusion with the other field
data forms.
Liquid Fuels and Heat Transfer Fluid (for all fluids other than water)
IMPORTANT: Ensure that SUT operators do not add, withdraw, or otherwise modify heat transfer fluid
composition(s) within 48 hours of testing. The heat transfer fluid circulation pump(s) should operate
during the 48 hours prior to testing to ensure fluid homogeneity.
1. Collect at least one liquid fuel sample at each power command setting during a valid test run.
Collect at least one heat transfer fluid sample from each heat transfer fluid loop tested at any time
during the load test phase. All sample volumes should be between 200 and 300 milliliters (ml).
Do not sample pure water heat transfer fluids.
2. Attach a suitable tube to the sampling valve or petcock if required.
3. Open the sampling petcock to purge about 50 ml of fuel or fluid from the sampling valve and
tube into a suitable waste container.
4. Fill the sampling bottle with fuel or fluid. Cap it securely and enter all required information
(date, time, Tavg, sample bottle ID number, etc.) on the Fuel Sampling Log (Appendix A6).
5. Fill out the Chain of Custody form (Appendix B7) and sample labels. Forward the samples to the
analytical laboratory accompanied by the form. Retain a copy for inclusion with the other field
data forms.
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B6: Fuel and Heat Transfer Fluid Sampling Log
IMPORTANT: Use separate sampling log and Chain of Custody forms for each sample type (gas fuel, liquid fuel,
heat transfer fluid). Record heat transfer fluid TAvg on Chain of Custody form for laboratory reference.
Project Name:_
Date:
Location (city, state):_
Signature:
SUT Description:,
Run ID:
Load Setting: %_
kW
Fuel Source (pipeline, digester):_
Sample Type (gas fuel, liquid fuel, heat transfer fluid):
Fuel Type (natural gas, biogas, diesel, etc.):
Note: Obtain fuel gas sample pressure and temperature from gas meter pressure and temperature sensors. Obtain
heat transfer fluid temperatures from datalogger display.
Gas Fuel Samples Only
Date
24-hr
Time
Run ID
Canister
ID
Initial
Vacuum, "
Hg
Sample Pressure
(from gas meter
pressure sensor)
Sample Temperature
(from gas meter
temperature sensor)
Liquid Samples Only
Date
24-hr
Time
Run ID
Sample
ID
Heat Transfer Fluid Temperatures (for CHP applications;
from datalogger display)
A supply
Treturn
IT + T }
rp \C supply return /
g 2
Notes:
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B7: Sample Chain-of-Custody Record
Important: Use separate Chain-of-Custody Record for each laboratory and/or sample type.
Project Name: Location (city, state):
Test Manager/Contractor Phone: Fax:
Address:
City,State / Zip:
Originator's signature:.
JJnit description:.
Sample description & type (gas, liquid, other.):_
Laboratory:
Address:
Phone:_
City:_
Fax:_
State:
Zip:_
Sample ID
Bottle/Canister ID
Sample Pressure
Sample Temp, or
TAvg, (°F)
Analyses Req'd
Relinquished by:_
Received by:
Relinquished by:_
Received by:
Relinquished by:_
Received by:
Date:_
Date:_
Date:_
Date:_
Date:_
Date:
Time:.
Time:
Time:
Time:
Time:
Time:
Notes: (shipper tracking #, other)_
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B8: CHP Unit Information
Flow Meter Commissioning
Test personnel should perform the following flow meter commissioning and sensor function checks:
1. Record the flow meter specifications and calibration information on the Temperature and Flow
Meter Commissioning Data log form.
2. Install flow meter, transmitter, and wiring.
3. Open the flow meter isolation valves or start the fluid circulation pump to ensure the meter is
charged, leak free, and producing 4-20 milliamp (mA) output to the datalogger.
4. Stop the fluid circulation pump or close the flow meter isolation valves to stop all flow through
the meter.
5. Record the datalogger zero flow result on the log form. The display should show 0.0 ±1.0
percent of full scale, or 4 mA ± 0.2 mA.
6. Start the fluid circulation pump or open the isolation valves. Record reading on the log form and
compare to the pump manufacturer's or installer's specifications for reasonableness.
7. Perform steps 2 through 5 at least once again immediately prior to the first test run.
Temperature Sensor Commissioning
Test personnel should complete the following temperature meter commissioning procedures and sensor
function checks:
1. Upon receipt, apply a permanent ID number to the temperature sensor and its transmitter.
2. After initial NIST calibration, review the certificate. It must be current (within 18 months), and
readings must be accurate to within ± 0.3 °F at 32 °F and ± 0.6 °F at 212 °F. The calibration
certificate must specifically reference each sensor and transmitter pair as a unit. Calibration
temperatures shown on the certificate should bracket the expected Tsuppiy and Treturn temperatures.
Maintain a copy of the calibration certificate.
3. Record the temperature meter specifications and calibration information on the Temperature and
Flow Meter Commissioning Data log form.
4. Connect each sensor to its transmitter. Install the signal wiring to the loop power supply and
datalogger, but leave enough slack signal wire to allow the two sensors to be immersed in the
same water bath. Immerse the two sensors in an agitated ice water bath. Record the readings from
the power meter or datalogger monitor on the log form. Both readings should be within 1 °F of 32
°F and within ± 0.6 °F of each other.
5. Immerse the two sensors in an agitated hot water bath. Hot tap water is satisfactory. Record the
readings from the power meter or datalogger monitor on the Temperature and Flow Meter
Commissioning Data log. Readings should be within ± 1.2 °F of each other.
Integrated heat Flow Meters
Where a single transmitter incorporates inputs from two temperature sensors and a flow meter for the
purpose of measuring heat flow is used, it is recommended that internal calculations not be used. The
individual temperature and flow readings should be recorded as for separate meters.
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B8: CHP Unit Information; Flow Meter and Temperature Meter Commissioning Data
Project Name: Location (city, state):
Date:
SUT Description:,
Manufacturer:
Nominal Btu/h:
Manufacturer:
Description:
Signature:,
CHP Unit
Model #:
Serial #:
at expected Ts
supply
T
_? J-return^
Thermal Application or BoP Equipment
Model #: Serial #:
Note: Enter the following information for each heat transfer fluid loop tested.
Temperature Sensor Manufacturer: Model #:
Tsuppiy: Sensor ID #: Transmitter ID #: NIST Cal. Date:
Tretum: Sensor ID #: Transmitter ID #: NIST Cal. Date:
1mA = °F
Bath
Description
Ice water
Hot water
T
A supply
I
T
A return*
»F
ligh span, 20
Allowable
Value
32 + 1 °F
•
mA= °F
OK? Difference,
»F
Allowable
Value
+ 0.6°F
+ 1.2°F
OK?
Model:
ID or Serial #:
Flow Meter Manufacaturer:
NIST Cal. Date: Low span, 4 mA = gpm; High span, 20 mA = gpm
Installation Data
Date:
Flow State
zero flow
Normal flow
Signature:
Flow Reading, gpm or mA
Expected Value, gpm or mA
OK?
Pretest Data
Date:
Flow Rate, gpm
zero flow
Normal flow
Signature:
Flow Reading, gpm or mA
Expected Value, gpm or mA
OK?
Note: zero flow indication must be less than + 1.0 % FS
Installation Location (BoP loop, cooling tower loop, etc.)
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Appendix C
Cl: Generic IC-Engine Hot Fluid-driven CHP Chiller System with Exhaust Diverter
Electric Power
System (EPS)
Point of Common L«~L«J
Coupling (PCC) fT1"!
Breaker/ "\
Disconnect )
OUT
Boundary
To Chilling
Loads
— Fuel Line
Heat Transfer Fluid
Air or Exhaust Gas
Electrical Conductors
AC Generator
—fO-
Prime Mover
Exhaust
Combustion Air
Engine
Starting Motor
M
Fuel Gas Booster
Fuel Treatment System
Prime Mov
Cooling Modpjle
Fuel
Supply
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C2: Generic MTG Hot Fluid-Driven CHP System in Heating Service
Electric Power
System (EPS)
Point of Common LJL«J
Coupling (PCC) p"pO
Cooled
Exhaust
Heating Loads
Fuel Line
Heat Transfer Fluid
t Air or Exhaust Gas
Electrical Conductors
Integrated
Heat Recovery
Unit
Fuel
Supply
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Appendix D: Definitions and Equations
Dl: Electrical Performance
Voltage
Voltage is a measure of the electromotive force or potential developed between separated positive and
negative electric charges. In AC circuits, the root-mean-square (rms) voltage is the square root of the sum
of the instantaneous voltage values, squared, or [Dl]:
V =
Where:
T , Eqn-D1
V = rms voltage, V
T = time period
a = initial time
v = instantaneous voltage, V
For a pure sine wave, the rms voltage value is 0.7071 times the peak voltage value. Rms voltages for
distorted wave forms can differ from this proportion.
Current
Current is a measure of the quantity of charge flowing past a fixed point during a one-second interval. A
potential difference of one volt across a one ohm resistor generates a one ampere (A) current. Rms current
in AC circuits is stated the same way as rms voltage.
Real Power
Real power is the combination of the voltage and the value of the corresponding current that is in phase
with the voltage. Real power produces resistive heating or mechanical work, and can be expressed as
[Dl]:
P = -
T
10 +1 I L
--— \vidt Eqn. D2
T ta-Tll
Where:
P = average real power at any time t0, watts (W)
v = instantaneous voltage, volts
i = instantaneous current, amperes
T = time period
If both the voltage and current are sinusoidal and of the same period,
P = VIcosO Eqn. D3
Where:
V = voltage rms value, V
I = current rms value, A
0 = phase angle between V and I, degrees
In three-phase wye-connected systems for purely resistive loads (where 0 = 0), total power is:
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Ptot =-£/„ +-j=Ib +-^IC Eqn. D4
•\J3 \3 \3
Where:
Ptot = total power, W
Vab = rms voltage between phases a and b, V
Ia = phase a current, A
Vbc = rms voltage between phases b and c, V
Ib = phase b current, A
Vca = rms voltage between phases c and a. V
Ic = phase c current, A
This relationship is useful for setting up instruments and troubleshooting.
Energy
Total energy in watt-hours is the real power integrated over the time period of interest. 1000 watts (W)
produced for one hour (H) results in one kilowatt-hour (kWh) of energy transfer.
Reactive Power and Apparent Power
Reactive power develops when inductive, capacitive, or nonlinear sources and loads exist on the system.
It does not represent useful energy that can be extracted from the system, but it can cause increased
losses, over-current conditions, and excessive voltage peaks. Reactive power is calculated as[Dl]:
Eqn. D5
Where:
Q = reactive power, volt-amperes reactive (VAR)
S = apparent power, calculated as V * A, VA
P = real power, W
Power Factor
Power factor is the ratio between real power and apparent power [Dl]:
PF = — Eqn. D6
S
Power factor indicates how much of the apparent power flowing into a load or a feeder is real power, P.
Frequency
Frequency is the number of complete cycles of sinusoidal variation per unit time. Throughout most of
North America, the EPS frequency is nominally 60 Hertz (Hz)
Total Harmonic Distortion
AC waveform distortion occurs at integer multiples, or harmonics, of the lowest sine wave frequency, or
fundamental. Total harmonic distortion defines the relationship of all distorting integer harmonic
waveforms with the fundamental. THD is the ratio of the root-mean-square (rms) summed harmonic
current or voltage to the rms value of the fundamental, expressed as a percent of the fundamental [D2]. In
equation form:
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%THD, = 100
%THDV = 100
Vf
Where:
Eqns. D7, D8
%THD = total harmonic distortion, percent
f = fundamental harmonic order (60 Hz in North America)
h = harmonic order as an integer multiple of the fundamental (h = 2 for 120 Hz)
I = true rms current, A
V = true rms Voltage, V
External Parasitic Loads
Parasitic loads are those which are essential for proper SUT function. The power connections for some
parasitic loads, such as fuel gas compressors, heat rejection unit fans, heat transfer fluid pumps, etc., may
be on the PCC-side, or "upstream", of the power meter (see Figure 2-1). Such loads are considered to be
external parasitic loads.
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D2: Electrical Efficiency Equations
Electrical Efficiency
Efficiency is the proportion of the fuel's heating value that appears as electricity at the DUT output
terminals [D3, D4]:
3412 14* P*}
*100 Eqn. D9
Where:
T|e = electrical generation efficiency, percent
3412.14 = British thermal units per hour (Btu/h) per kW
P = average power output (considered as Ptot or Pnet, see below), kW
Qm = average heat input, Btu/h
The average power output, or P, is the mean of all the one-minute power readings logged during each test
run (refer to Sections 2.3.1, 2.3.2). Power output may or may not incorporate losses from external
parasitic loads, so two efficiency values are appropriate:
• efficiency calculated on a total power output basis, without considering external
parasitic loads as a debit against performance
• efficiency including the external parasitic loads
Section 3.5.1.1 discusses how assumptions about external parasitic loads affect net power output and the
electrical efficiency accuracy.
Electrical efficiency determinations in this GVP are based on the fuel's LHV and should appear as rjeLHv-
For reference, the relationship between rjeHHv and TjeLHv is straightforward. In general,
e'HHV —, or approximately 0.90 (90 percent) Eqn. DIG
Heat Rate
Heat rate is the normalized heat input per unit of real power output [D3, D4]:
HR = Q?- Eqn. Dll
P
Where:
HR = heat rate, Btu/kWh
Qin = average heat input during each 30-minute test run, Btu/h
P = average power output, kW
Similar to efficiency, two heat rate reports are appropriate:
• heat rate calculated on a total power output basis, without considering external
parasitic loads as a debit against performance,
• heat rate including the external parasitic loads.
Heat rate determinations based on the LHV of the fuel should appear as HRLHv.
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Heat Input, Gaseous Fuels
Gaseous fuel heat input determination requires measurement of the actual flow rate of the fuel averaged
over each test run and corrected to standard conditions. Laboratory sample analysis for LHV is also
required:
Qs=1s*Vg^ Eqn.D12
Where:
Qg = heat input from fuel gas, Btu/h
qg = fuel gas LHV from laboratory sample analysis, Btu/scf
Vg,std = fuel volumetric flow rate at standard conditions (14.7 psia, 60 °F), scfh
The determination of volumetric flow rate for positive displacement flow meters, corrected to standard
conditions, requires measurement of flow rate in acfh, gas pressure, gas temperature, and gas
compressibility as follows:
v id=v Eqn.D13
s>std m( 14.7 )(Tg)Zg 4
Where:
Vm = average gas meter flow rate during each 30-minute test run, acfh
pbar = ambient barometric pressure, psia
Pfuei = gas fuel pressure at the gas meter, psig
14.7 = standard ambient pressure, psia
520 = standard absolute temperature, R
Tg = absolute gas temperature, R
Zstd = average gas compressibility at 14.7 psia, 60 °F from laboratory analysis
Zg = average gas compressibility at test conditions from laboratory analysis
Heat Input, Liquid Fuels
Heat input from liquid fuel is:
Qt=qi*m Eqn. D14
Where:
Qi = heat input from liquid fuel, Btu/h
qi = liquid fuel LHV from laboratory sample analysis, Btu/lb
m = liquid fuel mass consumption rate, Ib/h
Liquid fuel mass consumption rate is:
Eqn. D15
-1
I elapsed J
Where:
Wti = initial day tank weight at the beginning of the time period, Ib
Wt2 = final day tank weight at end of the time period, Ib
60 = minutes per hour
Teiapsed = length of the test run, minutes (min)
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D3: CHP Thermal Performance
Thermal Performance and Average Operating Temperature
The thermal performance is the energy transferred out of the CHP system boundary by the heat transfer
fluid to the BoP and cooling tower(s), if present [D5]:
Eqn.D16
Where:
Qout = thermal performance, Btu/h
Vi = heat transfer fluid volumetric flow rate, gallons per hour (gph)
AT = absolute value of the difference between supply and return temperatures,
T — T °F
sup ply return '
cp = heat transfer fluid specific heat at the average operating temperature, Btu/lb.°F
p = heat transfer fluid density at the average operating temperature, Ib/gal
In heating service, Tsuppiy and Treturn are the higher and lower temperature fluids, respectively. In chiller
service, Tsuppiy and TretUm are the lower and higher temperature fluids, respectively.
In chiller applications, thermal performance can be expressed as refrigeration tons:
KT =0°"- Eqn. D17
"•" 12000 4
Where:
RTout = transferred heat, RT
12000 = Btu/RT
Maximum thermal performance, or Qmax, in heating applications is the sum of the thermal energy
transferred to the BoP (Qout,Bop) and that rejected from the cooling tower(s), if present (Qout,cooitower)
Maximum thermal performance in chilling applications is not meaningful because the energy transferred
to the BOP is used for chilling while heat rejected from cooling module(s), if present, could be used only
for heating. They should be reported separately.
The average operating temperature is:
T +T
supply return -•-. T-V i o
- - D18
Thermal Efficiency
For CHP units in heating service only, thermal efficiency (r|th) is the proportion of the fuel's heating value
that appears as useful heat recovered from the CHP system:
r!th= V- *100 Eqn. D19
Where:
T|th = thermal efficiency, percent
Qout = thermal energy transferred, Btu/h
Qm = heat input, Btu/h
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The thermal energy transferred (Qout) is that which is moved out of the system boundary to the BOP.
Where cooling module(s) are present, the maximum thermal efficiency is:
Eqn.D20
V zfin j
Where:
T|th,max = maximum thermal efficiency, percent
Qmax = maximum thermal performance: the sum of Qout,BOp and Qout,cooi module, Btu/h
Qm = heat input, Btu/h
Thermal efficiency determinations based on the fuel's HHV will appear as rjthHHv. Those based on LHV
will appear as r|thjLHv.
Total Efficiency
For CHP units in heating service only, total efficiency is:
*7tot = Ve + Tlth Eqn. D21
Where:
T|tot = total efficiency, percent
T|e = electrical generation efficiency (Section 5.2.1)
T|th = thermal efficiency
In chilling applications heat that is normally discarded through a cooling tower or fan-coil unit may be
recovered for low-grade service, such as to provide swimming pool heat. This lower grade product may
be presented as a thermal efficiency. However the heating or chilling energy value depends on how high
(for heating) or low (for chilling) the temperature is for each loop. Therefore each "efficiency" may be
reported separately.
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D4: Emission Rates
Normalized Emission Rates
Emission rate normalized against system power output to provide emission rates (Ib/kWh) is:
E,
ERN = J— Eqn. D22
1\ ,KW 1 TT7-I l
Where:
ERN,kw = normalized emission rate, Ib/kWh
Ej = mean emission rate at load condition j, Ib/h
kWhj = mean power production at load condition j, kW
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D5: References
[Dl] IEEE Std 120-1989—Master Test Guide for Electrical Measurements in Power Circuits. Institute of
Electrical and Electronics Engineers, Inc., New York, NY. 1989
[D2] IEEE Std 519-1992—Recommended Practices and Requirements for Harmonic Control in Electrical
Power Systems. Institute of Electrical and Electronics Engineers, Inc., New York, NY. 1992
[D3] ASME PTC 22-1997—Performance Test Code on Gas Turbines. American Society of Mechanical
Engineers, New York, NY. 1997
[D4] ASME PTC 17-1997—Reciprocating Internal-Combustion Engines. American Society of
Mechanical Engineers, New York, NY. 1997
[D5] ANSI/ASHRAE 125-1992: ASHRAE Standard Method of Testing Thermal Energy Meters for Liquid
Streams in HVAC Systems. American Society of Heating, Refrigeration, and Air-Conditioning Engineers,
Inc., Atlanta, GA. 1992
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Appendix E: Often-overlooked Emission Testing Requirements
Requirement
Clean sample lines and probe
Properly heated sample line (record the
temp)
Proper analyzer ranges and cal gases
(readings should be over 30 percent of
range)
Proper moisture removal system (minimize
contact between gas and condensed water)
Clean glassware
Do the reagent and field blanks specified in
the methods
Straight run, cyclonic flow checks
Method 4 last impinger temp.
Witness Method 5 sampling train leak check
(operator to not touch sampling controls
once the leak check starts, etc.)
Witness Method 5 pitot tube leak check
(operator to not touch sampling controls
once the leak check starts, etc.)
Calibration gases certified and within
expiration dates
Parameters affected
NOX, SO2, TPM
NOX, THC, CH4
NOx, CO, THC, SO2
NOX
TPM, metals, NH3,
HCOH
TPM, metals, NH3,
HCOH
TPM, metals
Stack gas moisture
content
TPM
TPM
NOX, CO, C02, 02,
THC, CH4
Impact if not conducted
Positive bias from residuals
Negative bias from condensation
Bias results
Negative bias
Positive bias in results
Positive bias in results
Bias results
Negative bias
Negative bias
Bias results
Bias results
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Appendix F: Sample Implementation
Fl: Scope
This sample implementation provides detailed measurement instrument specifications and suggests
instruments which would fulfill the GVP's accuracy specifications for DG units less than approximately
500 kW. Numerous instruments of equivalent capabilities are available. Mention of brand names or model
numbers does not imply exclusivity or endorsement.
This Appendix also provides generic installation procedures and schematics for reference.
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F2: Electrical Measurements and Datalogging
Power Meter
The power meter must meet ANSI C12.20-2002 [Fl] and the GVP's specifications as shown in
the following table:
Table F-l: Electrical Instrument Specifications
Parameter
Voltage
Current
Real Power
Reactive Power
Power Factor
Frequency
Voltage THD
Current THD
Maximum Allowable Error
+ 0.50 % (class B)
+ 0.40 % (class B)
+ 0.6 % overall
1.5
+ 2.00%
+ 0.01 Hz (class A)
+ 5.00%
+ 4.90%
Citation
IEC 61000-4-30 [F2]
" "
" "
n/a
IEEE 929 [F3]
IEC 61000-4-30 [F2]
IEEE 5 19 [F4]
IEEE 5 19 [F4]
aAll accuracy specifications are percent of reading, except where noted.
bFull scale (FS) is 600 V, phase-to-phase
°Full scale depends on the selected current transformer (CT) range
Current Transformers
Current measurements require one CT for each phase. A CT with the proper current ratio will produce a 5
A output (or output appropriate for the power meter) when the DUT is operating near its rated capacity.
The following table lists common CT current ratios and associates each with common DUT capacity
ratings.
Table F-2: Common CT Ratios and DUT Ratings
Current
Ratio
100:5
200:5
400:5
800:5
1200:5
1600:5
2000:5
3000:5
kWper
Phase3
111
55.4
110.8
221.7
332.6
443.4
554.3
831.4
3-Phase
Total, kW
83.1
166.3
332.6
665.1
997.7
1330.2
1662.8
2494.2
Recommended Nominal
DUT Capacity
<75kW
150kW
300 kW
600 kW
900 kW
1.2 MW
1.5 MW
2.2 MW
aAssumes 480 V rated system voltage.
The GVP (and IEC 61000-4-30) specifies that CT accuracy class be ± 0.5 percent or better.
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Other Instruments
Table F-3 suggests appropriate supplemental instruments and summarizes the GVP's specifications.
Table F-3: Su
Parameter
Ambient Temperature
Ambient Barometric Pressure
External
Parasitic Loads:
Voltage
Current
)plemental Instrui
Max. Allowable
Error
+ 1.0°F
+ 0.1"Hg(+0.05
psia)
+ 1.0% of reading
+ 2.0% of reading
ment Spec
Range
-20 to
120 °F
OtolS
psia
0 - 600 V
0 - 600 A*
ifications
Instrument Error
+ 1.0%FS"
+ 0.25 % FS (+ 0.04
psia)
+ 1.0% of reading
+ 2.0% of reading
"+ 1.0 % of full scale represents + 1.2 °F. Ambient temperature is used only to verify stable
SUT operations, and the maximum permissible variation is + 4 °F.
*This current capacity is sufficient for 480 V loads up to approximately 500 kW, or 166 kW per
phase.
Loop Power Supply
Installers should review the sensor specifications to evaluate the need for series current-limiting resistors
(usually 250 ohm).
Datalogger
The test manager (or a designated database manager) must download the data to a laptop computer or
over a phone line before the datalogger capacity limit is reached. Confirm datalogger capacity to prevent
data loss. The power parameters may be logged within the power meter (if this function is available) or
externally.
Note that three analog channels and datalogger inputs (heat transfer fluid flow, Tsuppiy, Treturn) are required
for each thermal performance measurement location.
Electrical Instrument Installation
Figure F-l shows a generalized installation schematic for a 4-wire WYE system. It is important that the
voltage sensing lead for each phase be associated with the proper CT for that phase. Note that most
instruments can accommodate delta-wired systems if necessary. Refer to the power meter manufacturer's
instruction manual for specific installation procedures.
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Figure F-l. Four-wire Wye Instrument Connections
Phase
A B C N
Meter
:c
0
(
^ A^
Phase A
CT
G
_
(
\
Phase B
CT
_
(
k.
Phase C
CT
fuses
/"> .
' W
O ,
' \J
^J
/<~\
Cv
i
i^ •)
v_y
®T
QT
CT Shorting
Switch
Al
^A2
Bl
B2
Cl
Ic2
A
VB
C
Note: CT Polarity Indicator
Instrument installation consists of:
• installing and commissioning the power meter and supplementary instruments, and
• performing sensor function checks.
The installer must de-energize and physically remove each phase conductor from its terminal to allow for
solid-core CT installation. Split-core CTs do not require this. Refer to manufacturers' specifications to
ensure that CT polarity is correct.
The maximum (one-way) CT lead length should not exceed the manufacturer's specifications and
depends on the wire size (usually at least 12 gauge).
CT secondary wire leads should be physically connected to a functioning power meter, to a closed
shorting switch, or twisted together as a dead short circuit before energizing the power circuit. This is an
important safety measure because CTs can generate high voltages while a phase is energized if the CT
secondary circuit is open. Shorting switches are advantageous because they allow easy instrument service
without disturbing SUT wiring or operations.
Most power meter manufacturers specify a fuse in series with each voltage sensing wire. The fuse rating
should be as specified by the power meter manufacturer (usually 0.5 to 2.0 A). The fuse and its holder
should be capable of at least 200 kiloamperes interrupt current (KAIC).
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F3: Electrical Efficiency Measurements
This subsection specifies instrument requirements, laboratory analyses, allowable measurement error, and
installation procedures for measuring SUT fuel input, Qm. Section F2.0 provided power meter and CT
specifications and installation procedures for measuring power output, P, and external parasitic loads.
Figure F-2 outlines the different fuel measurement configurations considered here.
Figure F-2. Fuel Measurement Systems
Electric Power System/-^ \
(EPS) V M
Point of Common Coupling
(PCC)
Main Power Meter
( Platform Scale )
Liquid Fuel Microturbine
Power Meter
) For Parasitic Loads
Liquid Fuel 1C Engine
>500 kW
Temperature, degF
Volumetric
Flow (cu ft)
Liquid Fuel 1C Engine
<500 kW
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Gas Fuel Consumption Meter
This implementation suggests use of displacement-type gas meters. These meters are readily available,
reliable, and meet the GVP's ±1.0 percent accuracy specification. Installers should specify the meter size
so that the actual fuel consumption of the SUT is between approximately 10 and 100 percent of the
meter's capacity at all three power commands.
Table F-4 suggests common meter capacities to be used with hypothetical DUT capacities. For reference,
LFfV and rjeLHv are assumed to be 911 Btu/scf and 26 percent, respectively.
Table F-4: Gas Meter Sizing
DUT Capacity,
kW
30
70
100
250
500
1500
2000
3000
Heat Input,
Btu/h
393700
918600
1312400
3281000
6562000
19685000
26247000
39371000
Gas Con-
sumption, scfh
432
1009
1441
3602
7204
21613
28818
43226
Meter Capacity,
scfh
800
3000
3000
5000
11000
23000
38000
56000
Collection and analysis of fuel samples from biogas or landfill gas sources is strongly recommended prior
to specifying the gas meter because such gases can be extremely corrosive. At a minimum, the samples
should be analyzed by ASTM D5504 [F5] for sulfur compounds including H2S and mercaptans. The
meter manufacturer can then recommend a suitable meter for corrosive service if required.
Pressure and Temperature Sensors
This GVP suggests a direct-insertion bimetal thermometer and bourdon-type pressure gauge. Table F-5
presents the example instrument specifications.
Table F-5: Pressure and Temperature Instrument Specifications
Parameter
Pressure
Temperature
Maximum Allowable
Error
+ 2.0%
+ 1.0%"
Range
0-15 psig
-20 - 120 °F
Accuracy
+ 0.5%FS(FS=15
psig)
+ 1.0%FS(FS =
120 °F)
Gas Meter Installation
Site or test personnel should plan the gas flow meter installation with respect to the meter's specific
requirements. Some common gas meters, for example, must be mounted such that the lubrication
reservoirs and index are in the proper orientation. Other gas meter styles, such as orifice meters, require
straight pipe runs or flow straighteners upstream and downstream of the metering element [F6]. Whatever
the meter configuration, the site may wish to install isolation valves and a bypass loop to allow meter
service without disturbing SUT operations.
The meter run should incorporate pressure and temperature sensor ports adjacent to the gas meter for
those meters which are not pressure- or temperature-compensated. The temperature sensor port should
provide for a thermowell. This will allow the sensor to be removed without disturbing the gas flow and
the sensor need not be hermetically sealed.
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A fuel sampling port with the appropriate valve should be available.
Liquid Fuel Mass Consumption for DG Units < 500 kW
Day Tank and Secondary Containment
Actual equipment and configuration can vary widely. A 100-gallon polyethylene or metal tank placed on
a 1000 Ib capacity platform scale will provide enough fuel to operate a 70 kW MTG for about 14 hours.
The same installation would fuel a 500 kW diesel 1C generator for approximately \1A hours (at 50 gph or
350 Ib/h). This is permissible if testers refuel the day tank from a common supply before each test run.
Always check with the vendor prior to purchase to ensure that the day tank materials are compatible with
the fuel. Some facilities may require a secondary containment pan under the platform scale and day tank
to control potential fuel spills.
Platform Scale
The scale's capacity should not exceed 1000 Ib. The scale's accuracy specification should be ± 0.01
percent of reading and ± 0.05 Ib display resolution. This resolution is usually specified as "non-
commercial" or "not legal for trade." Such scales are readily available for rental or purchase.
Return Fuel Cooler (Diesel 1C Generators Only)
The required return fuel cooler capacity depends on the return fuel flow rate and return temperature. The
return temperature should be below about 140 °F. The fuel in the day tank (as supplied to the engine)
should not exceed about 110 °F.
In general, diesel engine return fuel flow rate ranges between about 4!/2 times (for Caterpillar brand) and 2
!/2 times (for other brands) of the engine's actual fuel consumption. Return fuel flow from a 500 kW 1C
generator should be between 180 to 260 gph, or 930 to 1500 Ib/h. At a diesel fuel specific heat of 0.5
Btu/lb.°F, the cooler capacity should therefore be between 14,000 and 22,000 Btu/h (assuming 110 and
140 °F supply and return temperatures, respectively). Numerous fan- or liquid-cooled heat exchangers are
available for this purpose. In one instance, a 15-foot coil of copper tubing placed in a cooler full of ice
was adequate for a 200 kW diesel engine.
Liquid Fuel Mass Consumption Flow Meters for DUT > 500 kW
Prime movers without return fuel flow require one temperature-compensated fuel flow meter connected to
a suitable datalogger. The flow meter accuracy specification, corrected to 60 °F, is ± 1.0 percent of
reading. Turbine flow meters are available which meet these specifications.
Differential measurements of supply and return fuel flow are necessary for diesel 1C generators larger
than 500 kW or other prime movers with return fuel flow. This requires two separate flow meters (see
Figure F-2). The return fuel flowmeter installation should incorporate an upstream integral or external de-
aerator / de-foamer. The accuracy specification of the differential value, corrected to 60 °F, is ± 1.0
percent of reading. In general, this means that each flow meter's temperature-compensated accuracy
should be better than ± 0.2 percent.
Note that test personnel should review the expected prime mover fuel supply (and return) flow rates at all
three power commands (50, 75, and 100 percent) prior to specifying the flow meter(s) to ensure that the
flow rates fall within the manufacturer's calibrated instrument response.
Liquid Fuel Meter Installation
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Installation for either liquid fuel metering scheme consists of obtaining and plumbing the appropriate
leak-free fuel-rated hoses or pipelines. Hoses should be suspended at day tank installations to ensure that
they do not contact the tank or affect scale readings. Installers may wish to incorporate bypass pipelines,
valves, and tee fittings to allow insertion and removal of the meters without affecting SUT operations.
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F4:Thermal Performance and Efficiency Measurements
Heat Transfer Fluid Flow Meter
The proper heat transfer fluid flow meter size depends on the expected fluid flow rate at the design
temperature. Testers should consult with the CHP designer prior to meter selection and sizing. Turbine
meters are suitable for the flow rates expected at typical CHP installations. Flow meter and transmitter
accuracy specification is ± 1.0 percent of reading.
Heat Transfer Fluid Temperature Meters
The GVP's temperature sensor specification is ± 0.55 °F accuracy from 100 to 180 °F and about ± 0.60 °F
from 180 to 212 °F.
CHP Flow and Temperature Meter Installation
Installation consists of:
• designing, fabricating, and installing the flow meter, isolation valves, and fluid
sampling port (if needed)
• installing thermowells, sensors, and transmitters
• wiring the transmitters to the loop power supply and the datalogger.
Most flow meters require a straight run of pipe to ensure undisturbed flow. This straight run usually
incorporates at least 15 pipe diameters to the nearest upstream disturbance (elbow, restriction, etc.) and
five diameters to the nearest downstream disturbance. The actual number of diameters depends on the
flow meter and disturbance type. The meter run can incorporate flow straighteners where space is
constrained. The flow meter manufacturer can provide the necessary details. CHP installations which do
not use pure water as a heat transfer fluid should have a fluid sampling port and valve available. This
GVP recommends installation of isolation valves to allow flow meter removal and service without
disabling SUT operations. Figure F-3 provides a reference schematic.
«-
Sar
P
return
1
Flow Meter \
Isolation Valve /
Typical Requirement:
5 diameters straight run
1 downstream.
nple | No flow disturbances.
Drt J 1
J( / Flow
T / Sensor
^ s ' s '
F
() «
-4-
Typical Requirement:
15 diameters straight run
upstream.
No flow disturbances.
1,
J
7 Flow Transmitter Row Meter ^
A Isolation Valve A
Device Under Test
OUT
Flow Meter
Blocking Valve
Heat Transfer
Fluid Return
Heat Transfer
Fluid Supply
supply
Figure F-3. Heat Transfer Fluid Flow Meter and Temperature Sensor Schematic
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F5: Example Equipment
Note that the manufacturers referenced here have been successfully used in the past and are provided for
convenience only. This does not represent an endorsement. Any product that meets or exceeds the
requirements outlined above is acceptable for the purpose of this GVP.
Table F-6: Example Test Equi
Device
Power Meter
Current
Transformer (CT)
Temperature
Barometric Pressure
External Parasitic
Loads
Shorting Switch
Voltage Leads
Power Supply
Pressure
Day Tank
Spill Containment
Platform Scale
Liquid Fuel Meter
Fuel Meter (gas)
Liquid Fuel Meter
(differential)
Flow Meter
Flow Transmitter
Temperature Sensor
Temperature
Transmitter
Measurement(s)
Voltage, Current, Real Power, Reactive Power,
Power Factor, Frequency, Voltage THD, Current
THD
(w. internal 24 hour datalogger function)
Current
Temperature
Ambient Barometric Pressure
Voltage, Current
CT Shorting Switch
Voltage Sensor Leads w. Fuses (3 -pack)
For 4-20 mA instrument loops
0-15 psig
100 gallon polyethylene
Containment pan
1000 Ib capacity
Turbine flow meter
Displacement gas meter
Liquid fuel supply and return; temperature-
compensated flow
Heat transfer fluid flow (turbine type)
Transmitter for turbine flow meter
Heat transfer fluid temperatures ("class A"
Platinum resistance temperature detector)
For above RTD 0-200 F range
pment
Model
ION 7330
19RL, 191, 194,
195
30EI60L040-
20/120/F/C
PX205-015AI
335 Clamp-on
U3889
H6911-3
U24Y101
1981
38555K33
12635T14
"Aegis"
Roots series
FuelCom series
FTB
FLSC-62
PR-18-2-100-1/4-
6-E-CLA
TX92A-2
Manufacturer
Power
Measurements Ltd.
Flex-Core
Ashcroft"
Omega Instruments
Fluke Instruments
Flex-Core
Veris Industries
Omega Instruments
Ametek
McMaster-Carr
McMaster-Carr
Fairbanks Morse
Omega Instruments
Dresser Industries
Flow Technology,
Inc.
Omega Instruments
Omega Instruments
Omega Instruments
Omega Instruments
"ASME PTC-22 and other protocols specify + 1.0 °F. The 1.0 % FS accuracy of the Ashcroft thermometer
suggested here represents +1.2 °F, which is a reasonable compromise for inexpensive field instrumentation.
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F6: References
[Fl] ANSI Cl2.20-2002: Code for Electricity Meter—0.2 and 0.5 Accuracy Classes. National Electrical
Manufacturers' Association, American National Standards Institute, Rosslyn, VA. 2001.
[F2] IEC 61000-4-30: Electromagnetic Compatibility (EMC)—Part 4-30: Testing and Measurement
Techniques-Power Quality Measurement Methods. International Electrotechnical Commission, Geneva,
Switzerland. 2003.
[F3] IEEE Std. 929-2000—IEEE Recommended Practice for Utility Interface of Photovoltaic (PV)
Systems. Institute of Electrical and Electronics Engineers, Inc., New York, NY. 1992.
[F4] IEEE Std 519-1992—Recommended Practices and Requirements for Harmonic Control in Electrical
Power Systems. Institute of Electrical and Electronics Engineers, Inc., New York, NY. 1992.
[F5] ASTM D5504-01—Standard Test Method for Determination of Sulfur Compounds in Natural Gas
and Gaseous Fuels by Gas Chromatography and Chemiluminescence. American Society for Testing and
Materials, west Conshohocken, PA. 2001.
[F6] AGA Report No. 3, Orifice Metering of Natural Gas Part 2: Specification and Installation
Requirements (2000). American Gas Association, Washington, DC. 2002.
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Appendix G. Uncertainty Estimation
Gl: Scope
This Appendix presents compounded error estimation procedures for quantities which are developed from
two or more instruments (or analyses) with individual measurement errors. It includes examples which
use the ASERTTI Microturbine and Microturbine-CHP Field Testing Protocol, Sections 2.0 through 7.0,
as a basis.
In addition to following the specified procedures to ensure data quality, evaluation and reporting of the
achieved uncertainty is an important aspect of this GVP. Where applicable, two methods of uncertainty
evaluation are acceptable.
First, if each measurement meets its minimum accuracy specification, analysis can report the overall
estimated uncertainty as that cited in the GVP. If all specifications are not met, analysts should instead
calculate the actual parameter uncertainty in accordance with the methods specified below.
Second, the achieved parameter uncertainty may be calculated based on actual measurement instrument
calibration data, actual laboratory error, field conditions, and other uncertainties determined as described
in the GVP. Analysts may compound the measurement errors to determine the achieved uncertainty (or
relative error) for the parameter of interest using the methods specified below.
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G2: Measurement Error
This Appendix defines measurement error, uncertainty, or accuracy as the combination of all contributing
instrument errors and instrument precision. It makes no effort to separate the two or to quantify sampling
error. An instrument manufacturer's accuracy specification (or laboratory analysis accuracy statement,
etc.) is sufficient if it is accompanied, at a minimum, by current applicable National Institutes of
Standards and Technology (NIST)-traceable calibration(s), appropriate QA/QC checks, or other
supporting documents which support the accuracy statements.
Absolute and Relative Errors
Absolute measurement error is an absolute value compared to a given value or operating range. An
example is: "± 0.6 °F between 100 and 212 °F" for a temperature meter.
Relative measurement error, generally stated as a percentage, is:
err,.
rel 7.
reading
Where:
100 Eqn. G-l
errrel = relative error, percent
errabs = absolute error, stated in the measurement's units
reading = measurement result, stated in the measurement's units
The reference basis for relative accuracy statements can be either the instrument's full scale or span or the
measurement reading. The following examples show the relationships between relative and absolute
measurement errors.
Relative Error Accuracy Statement FS (or span) Absolute Error
"Temperature accuracy is ± 1.0 %, FS" 120 °F ±1.2 °F at 60 °F
"Temperature accuracy is ± 1.0 % of reading" n/a ± 0.6 °F at 60 °F
Compounded Error for Added and Subtracted Quantities
For added or subtracted quantities, the absolute errors compound as follows [Gl, G2]:
Where:
errc abs = compounded error, absolute
err] = error in first added or subtracted quantity, absolute value
errabs2 = error in second subtracted quantity, absolute value
As an example, the GVP defines the heat transfer fluid AT as the difference between Tsuppiy and Treturn. The
uncertainties in each temperature measurement compound together to yield the overall AT uncertainty.
The absolute error for each temperature meter specified in the GVP is ± 0.6 °F, from 100 to 212 °F. The
resulting AT absolute error is constant at V0.62 +0.62 , or ± 0.85 °F. Relative error will vary with the
actual AT found during testing.
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Compounded Error for Multiplied or Divided Quantities
For two multiplied or divided quantities, the relative errors compound to yield the overall error estimate
[G2,G3,G4]:
err , =
- G-3
Where: errc rei = compounded relative error, percent
erri rei = relative error for first multiplied quantity, percent
err2, rei = relative error for second multiplied quantity, percent
For example, the power meter described in the GVP measures the CT output and applies the appropriate
scaling factor by multiplication. The GVP specifies current THD accuracy as ± 4.9 percent at 360 Hz.
Compounded with the specified ±1.0 percent CT accuracy at that frequency, the overall current THD
accuracy is V4.92 + l.O2 or ± 5.0 percent.
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G3: Examples
This section provides example uncertainty calculations for each of the GVP's parameters. Each parameter
is a combination of multiplied/divided or added/subtracted values. The relative or absolute errors
compound accordingly. Accuracy actually achieved in field testing may be estimated by entering the
actual instrument or measurement accuracies in the appropriate calculations.
Electrical Generation Performance Uncertainty
The electrical generation performance accuracy depends on the power meter accuracy alone for the
parameters shown in Table G-l. This table essentially repeats the GVP's specifications for those
parameters. For other parameters, CT uncertainty compounds multiplicatively according to Eqn. G3 with
the power meter accuracy. Table G-2 shows the effects.
Table G-l: Directly Measured Electrical Parameter Uncertainty
Parameter
Voltage
Voltage THD
Frequency
Ambient temperature
Ambient barometric pressure
Accuracy
+ 0.5 % of reading
+ 5.0% of reading
+ 0.01 Hz
+ 1°F
+ 0.1"Hgor + 0.05psia
Table G-2: Compounded Electrical Parameter Uncertainty
Parameter
Current
Real power
Reactive power
Power factor
Current THD
Power Meter
Accuracy
+ 0.4 %
+ 0.6 %
+ 1.5%
+ 2.0%
+ 4. 9% (to 360 Hz)
CT Accuracy
+ 0.3 %
+ 1.0% (to 360 Hz)
Compounded
Uncertainty
+ 0.5%
+ 0.7 %
+ 1.5%
+ 2.0%
+ 5.0 % (to 360 Hz)
"All accuracies are percent of reading
Electrical Efficiency Uncertainty
The electrical efficiency determination accuracy depends on the real power, fuel heating value, and fuel
consumption uncertainties. Each of these quantities incorporate individual measurements and
corresponding errors.
Real Power Uncertainty
The GVP specifies that electrical efficiency must be reported as two values:
• efficiency calculated on a total power output basis, without considering external
parasitic loads as a debit against performance
• efficiency including the external parasitic loads.
External parasitic loads are considered as a debit against SUT performance. Their inherent measurement
errors will contribute to the real power determination and overall rje uncertainties.
This GVP suggests the quantification of the external parasitic loads' apparent power consumption as
either kVA with a clamp-on DVM or kW with individual real power meters (and datalogger channels)
installed at each load.
Use of the clamp-on DVM increases the r|e error more than use of a real power meter because the clamp-
on DVM will report external parasitic loads as apparent power, or kVA. Subtraction of kVA from kW is
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strictly accurate only when the parasitic load power factor is unity (or 1.00). For lower power factors, the
subtraction will negatively bias the rje result. As an example, a 100 kW MTG could have the following
inductive parasitic loads and power factors:
Table G-3: Example External Parasitic Loads
Example Load Type
Compressor motor
Circulation pump motor
Total:
Load
(apparent
power)
5kVA
3kVA
8kVA
Power
Factor
0.80
0.70
0.76
Load (real
power)
4.0 kW
2.1 kW
6.1 kW
If the parasitic loads are measured as kVA, real power would be reported as 92 kW (100 kW minus 8
kVA) instead of 93.9 kW (100 kW minus 6.1 kW). This 1.9 kW negative bias compounds additively with
the ± 0.7 percent real power uncertainty (Table G-2) according to Eqn. G-2. This increases real power
uncertainty to the ± 2.2 percent shown in Table G-4.
Table G-4: Real Power Uncertainty
Parameter Description
DUT real power output
External parasitic load as
kVA, 0.76 power factor
SUT real power, net
Value
lOOkW
8kW
92 kW
Absolute
Error
0.7 kW
1.9kW
2.0 kW
Relative
Error
0.7 %
23.8 %
2.2 %
If the loads are measured with ±1.0 percent-accurate real power meters, the overall real power
uncertainty increases slightly to ± 0.74, rounded to ± 0.7 percent. The disadvantage in measuring external
parasitic loads with real power meters is the need for installation of a meter (and datalogger channel) at
each load. Clamp-on real power meters are available whose impact on achieved accuracy falls between
these two limits.
Gaseous Fuel Heating Value, Pressure, Temperature, and Consumption Uncertainty
Heating Value
The GVP specifies ±1.0 percent relative accuracy for the gaseous fuel heating value, as supported by
laboratory NIST-traceable calibrations, duplicate analyses, and other QA/QC checks.
Absolute Gas Pressure
The gaseous fuel consumption determination requires the gas absolute pressure at the meter, or the sum of
ambient barometric pressure (pbar, psia) and gas pipeline gage pressure (pfuei, psig). The specified
instrument accuracies are:
• pbar: ± 0.05 psia
• pfud: ± 0.5 % FS, or ± 0.075 psig if FS is 15 psig
Standard gas delivery pressure at the metering location for many installations is between 0.25 and 1.0
psig (4 to 16 ounces, or 6 to 25 inches, water column). The GVP therefore assumes that pbar and pfuei are
14.2 psia and 0.50 psig, respectively; total absolute pressure is 14.7 psia. The absolute errors compound
per Eqn. G-2 as: V.052 +.0752 , or ± 0.09 psia. In this case, the relative error is [o.09/14.7]*100 or ± 0.6
percent.
Absolute Gas Temperature
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Fuel consumption also requires the absolute gas temperature, which is 460 °R plus the gas temperature
reading in °F. The specified temperature sensor accuracy is ± 1.0 percent, FS, or ± 1.2 °F if FS is 120 °F.
For 60 °F gas temperatures, the relative error is [l.2/(60 + 460)]*100 , or ± 0.2 percent
Fuel Gas Consumption
The gas pressure and temperature relative uncertainties contribute to the overall fuel consumption
uncertainty as shown in Table G-5. The table also summarizes the remaining gas consumption
measurements, their associated relative accuracy, and the resulting compounded relative accuracy. All
quantities are multiplied or divided, so their relative errors compound per Eqn. G-3.
Table G-5: Gaseous Fuel Consumption Uncertainty
Parameter
Vm, acfm
Pbai + Pfuei, 14.7 psia assumed
Tg, or tfuei + 460, °R
Zst(j, compressibility at standard
conditions (from lab analysis)
Zg, compressibility at field
conditions
Fuel consumption, scfh
Relative Accuracy
+ 1.0%
+ 0.6 %
+ 0.2 %
+ 1.0%
+ 1.0%
+ 1.8 %
Liquid Fuel Heating Value and Consumption
Heating Value
The GVP specifies ± 0.5 percent relative accuracy for the liquid fuel heating value.
Liquid Fuel Consumption
The GVP defines liquid fuel consumption as the fuel day tank weight at the end of a test run subtracted
from the starting weight. Three errors contribute to liquid fuel consumption uncertainty. They are:
• platform scale error: ± 0.01 percent of reading
• display resolution error: ± 0.05 Ib
• subtraction error
The worst case errors occur for low fuel consumption rates and high day tank weights. A 30 kW MTG
operating at 50 percent power command will consume approximately 5.40 Ib of fuel during a !/2-hour test
run. Table G-6 shows the resulting measurement errors for a starting weight of 950 Ib. All quantities are
added or subtracted, so their absolute errors compound per Eqn. G-2.
Table G-6: Liquid Fuel Consumption Uncertainty
Measurement
Wtj
Wt2
Wtj - Wt2
Example
950.00
944.60
5.40
Error
Description
scale
display
scale + display
scale
display
scale + display
subtraction
errrei
+ 0.01 %
+ 0.01 %
+ 2.8%
errabs
+ 0.095 Ib
+ 0.051b
+ 0.107 Ib
+ 0.094 Ib
+ 0.051b
+ 0.1071b
+ 0.151 Ib
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Electrical Efficiency
The real power, fuel heating value, and fuel consumption relative errors compound multiplicatively (Eqn.
G-3), as summarized in Table G-7.
Table G-7: Electrical Efficiency Accuracy
Gaseous
Fuels
Liquid Fuels
Parameter
Real Power, kW
Fuel Heating Value
(LHV or HHV),
Btu/scf
Fuel Rate, scfh
Efficiency, r\e
Real Power, kW
Fuel Heating Value
(LHV or HHV),
Btu/scf
Fuel Rate, Ib/h
Efficiency, r\e
Relative
Accuracy, %
+ 2.2
+ 1.0
+ 1.8
+ 3.0
+ 2.2
+ 0.5
+ 2.8
+ 3.6
Note that, for efficiency, both relative and absolute errors are stated as percentages. It is less confusing to
report the achieved absolute accuracy rather than relative accuracy. For a gas-fueled MTG which attains
26 percent electrical efficiency, the absolute uncertainty would be 26 * 0.030, or ± 0.78 percent. The
report would state "r|e was 26 ± 0.78 percent."
CHP Efficiency Uncertainty
CHP heating service efficiency determinations require system heat input (Qm) and thermal performance
(Qout). The fuel heating value and consumption, multiplied together, yield Qm. Qout at each thermal
performance measurement location is the product of the difference between Tsupply and Treturn (AT), the
fluid density or specific gravity (p), the fluid specific heat (cp), and the heat transfer fluid flow rate (Vi).
Heat Input (Qm)
Table G-8 shows the compounded Qm uncertainty for gaseous and liquid fuels.
Table G-8: Qjn Accuracy
Gaseous
Fuels
Liquid
Fuels
Parameter
Fuel Heating Value
(LHV or HHV), Btu/scf
Fuel consumption, scfh
Qm, BtU/h
Fuel Heating Value
(LHV or HHV), Btu/scf
Fuel consumption, Ib/h
Qln, Btu/h
Relative
Accuracy, %
+ 1.0
+ 1.8
+ 2.1
+ 0.5
+ 2.8
±2.8
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Qout and Thermal Performance
AT
AT is Treturn subtracted from Tsuppry. The Tsuppiy and Treturn absolute errors compound per Eqn. G-2. The
GVP specifies ± 0.6 °F temperature meter accuracy between 100 and 212 °F. The compounded
uncertainty for any AT will therefore be Vo.602 +0.602 or ± 0.85 °F. The relative error for 20 °F AT (Eqn.
G-l) is [0.85/20]*100, or 4.3 percent.
Note that the achieved accuracy deteriorates quickly for smaller AT even though the sensor errors do not
change. For example, at 5.0 °F AT, accuracy will be ± 17.0 percent (or [0.85/5.OJ* 100) with the specified
± 0.60 °F temperature meter error. Analysts should calculate and report the achieved accuracy if AT is
less than 20 °F.
Heat Transfer Fluid Specific Gravity and Specific Heat
Most heat transfer fluids are propylene glycol in water (PG). The GVP specifies the PG laboratory
analysis relative error for p (density) as ± 0.11 percent.
The reported p is the entry point in a table of PG densities for various concentrations. Interpolation of the
reported value against the table entries yields the actual PG concentration. The PG concentration, in turn,
is the entry point in a table of PG specific heats, cp, for various concentrations. Analysts then interpolate
the PG concentration against the table entries to obtain the cp. This procedure implies that the laboratory
analysis error affects cp at two stages:
1) determination of actual PG concentration
2) determination of cp from actual PG concentration
The errors compound multiplicatively per Eqn. G-3. The compounded cp uncertainty is therefore ±0.16
percent (or Vo.ll2 +0.112 ).
Compounded O^ Uncertainty
The GVP specifies the heat transfer fluid flow meter accuracy as ± 1.0 percent of reading. Qout is a
product of the contributing measurements, so the relative errors compound per Eqn. G-3. The
compounded accuracy, assuming that AT is at least 20 °F is
^en-2 + Perr2 +c ^ +Vierr2 X or i 4.4 percent.
•v/4.32+0.112+0.162+1.02
CHP Efficiency
T]th in heating service is Qout divided by Qm, so the relative errors compound per Eqn. G-3. Table G-9
shows the compounded accuracy for gaseous and liquid fuels, assuming that AT is at least 20 °F.
Table G-9: T]th Accuracy
Gaseous
Fuels
Liquid Fuels
Parameter
Qm, Btu/h
Qout, Btu/h
Tlth, %
Qm, Btu/h
Qout, Btu/h
ilth, Btu/h
Relative
Accuracy, %
+ 2.1
+ 4.4"
+ 4.9
+ 2.8
+ 4.4"
+ 5.2
"AT is at least 20 °F
G-8
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GVP - DG CHP Field Testing Protocol
Version 1.0
September 2005
G4: Total Efficiency Uncertainty
T|tot in heating service is the sum of r|th and r|e, so the absolute errors compound per Eqn. G-2. Actual r|th
and T|e results are needed to the calculate absolute errors and the resulting r|tot compounded error. As an
example, assume that the SUT has r|th and r|e of 53 and 26 percent, respectively. Table G-10 shows the
compounded accuracy for gaseous and liquid fuels, assuming that AT is at least 20 °F.
Table G-10: T]tot Uncertainty
Gaseous
Fuels
Liquid
Fuels
Parameter
rith, 53 % assumed
T|e, 26 % assumed
r|tot, 79 % assumed
nth, 53 % assumed
T|e, 26 % assumed
r|tot, 79 % assumed
Relative
Error
+ 4.9%
+ 3.0%
+ 3.5%
+ 5.2%
+ 3.6%
±3.7%
Absolute
Error
+ 2.6%
+ 0.8%
+ 2.8%
+ 2.8%
+ 0.9%
± 2.9 %
"AT is at least 20 °F.
Note that, for efficiency, both relative and absolute errors are stated as percentages. It is less confusing to
report the achieved absolute accuracy rather than relative accuracy. The example here, for gaseous fuels,
would be reported as "r|tot was 71 ± 2.8 percent."
G-9
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GVP - DG CHP Field Testing Protocol September 2005
Version 1.0
G5: References
[Gl] Methane Emissions from the U.S. Petroleum Industry. EPA-600/R-99-010, U.S. Environmental
Protection Agency, Office of Research and Development, Research Triangle Park, NC. 1999.
[G2] Fundamentals of Analytical Chemistry, 4th Edition. Douglas A. Skoog, Donald M. West, CBS
College Publishing, Philadelphia, PA. 1982.
[G3] Significance of Errors in Stack Sampling Measurements. R. T. Shigehara, W. F. Todd, W. S. Smith,
presented at the annual meeting of the Air Pollution Control Association, St. Louis, MO. 1970.
[G4] Measurement Uncertainty of Selected EPA Test Methods. R. T. Shigehara, presented at the
Stationary Source Sampling and Analysis for Air Pollutants XXV Conference, Destin, FL. 2001.
G-10
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