Appendix B - Testing and Certification Criteria
This Appendix describes the test procedures and requirements for equipment used for the Interconnection of Distributed Generation to the Electric Corporation's Distribution System. Included are Type Testing, Production Testing, Commissioning Testing, and Periodic Testing. The procedures listed rely heavily on those described in appropriate Underwriters Laboratory (UL), Institute of Electrical and Electronic Engineers (IEEE), and International Electrotechnical Commission (IEC) documents-most notably UL 1741 and IEEE 929-as well as the testing described in May 1999 New York Standardized Interconnection Requirements. These procedures and requirements were developed prior to the completion of IEEE P1547 Standard for Distributed Resources Interconnected with Electric Power Systems, and should be revisited once that standard is published.
The tests described here, together with the technical requirements in Section 4 of Rule 21, are intended to provide assurance that the DG equipment will not adversely affect the EC Distribution System and that it will cease providing power to the grid under abnormal conditions. The tests were developed assuming a low level of DG penetration. At high levels of DG penetration, other requirements and corresponding test procedures may need to be defined.
This test specification also provides a means of certifying equipment. The Electric Corporation does not need to review the design or test Protective Functions of Certified Equipment. The use of non-certified equipment may be acceptable subject to testing and approval by the EC as discussed below.
Equipment tested and approved (e.g. listed) by an accredited, nationally recognized testing laboratory (NRTL) as having met both the Type Testing and Production Testing requirements is considered Certified Equipment for purposes of Interconnection. Certification may apply to either a pre-packaged system or an assembly of components that address the necessary functions. Type Testing may be done in the factory/test lab or in the field. At the discretion of the testing laboratory, field-certification may apply only to the particular installation tested. In such cases, some or all of the tests may need to be repeated at other installations.
For non-certified equipment, some or all of the tests described in this document may be required by the EC. The manufacturer or other lab acceptable to the EC may perform these tests. Test results must be submitted to the EC with the Interconnection Application for review and approval under the supplemental review. Approval by one EC for use in a particular application does not guarantee approval for use in other applications or by other ECs.
The NRTL shall provide to the manufacturer, at a minimum, a Certificate with the following information for each device certified:
Administrative:
· Effective date of certification or applicable serial number (range or first in series), other proof that certification is current
· Equipment model number (s)
· Software version, if applicable
· Test procedures specified (including date or revision number)
· Laboratory accreditation (by whom and to what standard)
Technical (As appropriate):
· Device rating (kW, kVA, V, A, etc.)
· Maximum available fault current, A
· In-rush current, A
· Trip points, if factory set (trip value and timing)
· Trip point and timing ranges for adjustable settings
· Nominal power factor or range if adjustable
· If the device/system is certified for non-export and the method used (reverse power or under power)
· If the device/system is certified non-islanding
It is the responsibility of the equipment manufacturer to ensure that certification information is made publicly available by the manufacturer, the testing laboratory, or by a third party.
Static power inverters shall meet all of the Type Tests and requirements appropriate for a utility interactive inverter as specified in UL 1741 Static Inverters and Charge Controllers for Use in Photovoltaic Power Systems, and listed below. These requirements may be applied to inverters used with DG sources other than PV. The specific section number from the May 1999 version of UL1741 is provided for each test and requirement. The titles for some sections were added for clarity. These section numbers are subject to change by UL. A revised version of 1741 is expected to be published around Nov 2000. The utility interconnection-related procedures and requirements of that version will need to be reviewed to determine if they should be adopted into these testing and certification rules. The requirements described below cover only issues related to Interconnection and are not intended to address device safety and other issues outside the need and relationship between the EC and EP.
39.1 Utility Disconnect Switch
39.2 Field Adjustable Trip-points
39.3 Field Adjustable Trip-points
39.4 Field Adjustable Trip-points
39.5 Field Adjustable Trip-points, Marking
40.1 DC Isolation
41.2 Simulated PV Array (Input Source) requirements
44 Dielectric Voltage Withstand Test
45.2.2 Power Factor
45.4 Harmonic Distortion
45.5 DC Injection
46.2 Utility Voltage and Frequency Variation Test
46.2.3 Reset Delay
46.4 Loss of Control circuit
47.3 Short Circuit Test
47.7 Load Transfer Test
A description of key aspects of these procedures is provided in the testing procedures section of this Appendix.
Separate test procedures are provided to certify non-islanding function (B3.4) and non-export function (B3.5), to determine the in-rush current B3.6, to subject the device to voltage surge conditions B3.7, and to verify the inverter's ability to synchronize with the Distribution System (B3.8).
Until a standardized test procedure, written specifically for synchronous generators, is identified, an EC or NRTL shall determine which of the tests described in this Appendix are appropriate and necessary to certify the performance of the control and protection system functions of the synchronous machine, and how to perform them. The following tests, defined in UL 1741, shall be performed as applicable to a synchronous generator.
39.1 Utility Disconnect Switch
39.2 Field Adjustable Trip-points
39.3 Field Adjustable Trip-points
39.4 Field Adjustable Trip-points
39.5 Field Adjustable Trip-points, Marking
44 Dielectric Voltage Withstand Test
45.2.2 Power Factor
45.4 Harmonic Distortion
46.2 Utility Voltage and Frequency Variation Test
46.2.3 Reset Delay
46.4 Loss of Control circuit
47.3 Short Circuit Test
Separate test procedures are provided to certify non-islanding function and non-export function, to determine in-rush current, to subject the device to voltage surge conditions, and to verify the generator's ability to synchronize with the Distribution System.
Until a standardized test procedure, written specifically for induction generators is identified, an EC or NRTL shall determine which of the tests described in this Appendix are appropriate and necessary to certify the performance of the control and protection system functions of the induction generator, and how to perform them. The following tests, defined in UL 1741, shall be performed as applicable to a induction generator.
39.1 Utility Disconnect Switch
39.2 Field Adjustable Trip-points
39.3 Field Adjustable Trip-points
39.4 Field Adjustable Trip-points
39.5 Field Adjustable Trip-points, Marking
44 Dielectric Voltage Withstand Test
45.2.2 Power Factor
45.4 Harmonic Distortion
46.2 Utility Voltage and Frequency Variation Test
46.2.3 Reset Delay
46.4 Loss of Control circuit
47.3 Short Circuit Test
47.7 Load Transfer Test
Separate test procedures are provided to certify non-islanding function and non-export function, to determine the in-rush current, and to subject the device to voltage surge conditions.
B3.4 Anti-Islanding Test
In addition to the above Type Tests, devices that pass the Anti-Islanding test procedure described in this Appendix will be considered Non-Islanding for the purposes of these interconnection requirements.
In addition to the above Type Tests, devices that pass the Non-Export test procedure described in Section C1.1 will be considered Non-Exporting for the purposes of these interconnection requirements.
Generation equipment that utilizes EC power to motor up to speed will be tested using the procedure defined in Section C1.2 to determine the maximum current drawn during this startup process. The resulting in-rush current is used to estimate the starting voltage drop.
B3.7 Surge Withstand Capability Test
Interconnection equipment shall tested for surge withstand capability (SWC), both oscillatory and fast transient, in accordance with the test procedure defined in IEEE/ANSI C62.45 using the peak values defined in IEEE/ANSI C62.41 Tables 1 and 2 for location category B3. An acceptable result occurs even if the device is damaged by the surge, but is unable to operate or energize the EC. If the device remains operable after being subject to the surge conditions, previous type tests related to EC protection and power quality will need to be repeated to ensure the unit will still pass those tests following the surge test.
This test verifies that the unit synchronizes within the specified voltage/frequency/phase angle requirements. It is applied to synchronous generators and inverters capable of operating as voltage-source while connected to the EC. This test is not necessary for induction generators or current-source inverters.
The test will start with only one of the three parameters--voltage difference between DG and EC, frequency difference, or phase angle--outside of the synchronization specification. Initiate the synchronization routine and verify that the DG is brought within specification prior to synchronization. Repeat the test five times for each of the three parameters.
For manual synchronization with synch check or manual control with auto synchronization, the test must verify that paralleling does not occur until the parameters are brought within spec.
As a minimum, the Utility Voltage and Frequency Variation Test procedure described in UL1741 under Manufacturing and Production Tests, Section 68 shall be performed as part of routine production (100 percent) on all equipment used to interconnect DG to EC. This testing may be performed in the factory or as part of a Commissioning Test (B5.1).
Commissioning Testing, where required, will be performed on-site to verify protective settings and functionality. Upon initial Parallel Operation of a generating system, or any time interface hardware or software is changed that may affect the functions listed below, a Commissioning Test must be performed. An individual qualified in testing protective equipment (professional engineer, factory-certified technician, or licensed electrician with experience in testing protective equipment) must perform commissioning testing in accordance with the manufacturer's recommended test procedure to prove the settings and requirements of this document.
The EC has the right to witness Commissioning Tests as described below, or to require written certification by the installer describing which tests were performed and their results.
Functions to be tested during commissioning, particularly with respect to non-certified equipment, may consist of the following:
1. Over- and under-voltage
2. Over- and under-frequency
3. Anti-Islanding function (if applicable)
4. Non-Export function (if applicable)
5. Inability to energize dead line
6. Time delay restart after utility source is stable
7. Utility system fault detection (if used)
8. Synchronizing controls (if applicable)
9. Other interconnection protective functions that may be required as part of the Interconnection Agreement
Other checks and tests that may need to be performed include:
1. Verifying final protective settings
2. Trip test
3. In-service test
Systems qualifying for Simplified Interconnection incorporate Certified Equipment that have, at a minimum, passed the Type and Production Tests described in this document, and are judged to have little or no potential impact on the EC distribution system. For such systems, it is necessary to perform only the following tests:
1. Protection settings that have been changed after factory testing will require field verification. Tests will be performed using injected secondary quantities, applied waveforms, a test connection using a generator to simulate abnormal utility voltage or frequency, or varying the set points to show that the device trips at the measured (actual) utility voltage or frequency.
2. Non-Islanding function will be checked by operating a load break disconnect switch to verify the interconnection equipment ceases to energize the line and does not re-energize for the required time delay after the switch is closed
3. Non-Export function will be checked using secondary injection techniques. This function may also be tested by adjusting the DG output and local loads to verify that the applicable non-export criteria (i.e., reverse power or under power) are met.
The supplemental review or an Interconnection Study may impose additional components or additional testing.
Non-certified equipment shall be subjected to the appropriate tests described in Type Testing (Section B3) as well as those described in Certified Equipment Commissioning Test (Section B5.1). With EC approval, these tests may be performed in the factory, in the field as part of commissioning, or a combination of both. The EC, at its discretion, may also approve a reduced set of tests for a particular application or, for example, if they have sufficient experience with the equipment.
B5.3 Verifying final protective settings
If the testing is part of the commissioning process, then, at the completion of such testing, the EP shall confirm all devices are set to EC-approved settings. This step shall be documented in the Commissioning Test Certification.
Interconnection protective devices (e.g. reverse power relay) that have not previously been tested as part of the interconnection system with their associated interrupting devices (e.g. contactor or circuit breaker) shall be trip tested during commissioning. The trip test shall be adequate to prove that the associated interrupting devices open when the protective devices operate.
Interlocking circuits between protective devices or between interrupting devices shall be similarly tested unless they are part of a system that has been tested and approved during manufacture.
Interconnection protective devices that have not previously been tested as part of the interconnection system with their associated instrument transformers or that are wired in the field shall be given an in-service test during commissioning. This test will verify proper wiring, polarity, CT/PT ratios, and proper operation of the measuring circuits. The in-service test shall be made with the power system energized and carrying a known level of current. A measurement shall be made of the magnitude and phase angle of each ac voltage and current connected to the protective device and the results compared to expected values.
For protective devices with built-in metering functions that report current and voltage magnitudes and phase angles, or magnitudes of current, voltage, and real and reactive power, the metered values may be used for in-service testing. Otherwise, portable ammeters, voltmeters, and phase-angle meters shall be used.
B6 Periodic Testing
Periodic Testing of Interconnection-related Protective Functions shall be performed as specified by the manufacturer, or at least every four years. All periodic tests prescribed by the manufacturer shall be performed. The EP shall maintain periodic test reports or a log for inspection by the Electrical Corporation. Periodic Testing conforming to EC test intervals for the particular line section may be specified by the EC under special circumstances, such as high fire hazard areas.
A system that depends upon a battery for trip power shall be checked and logged once per month for proper voltage. Once every four years, the battery must be either replaced or a discharge test performed.
Testing Procedures
C1 Type Test and Requirements
This section describes the Type Tests necessary to qualify a device as Certified, which are not contained in Underwriters Laboratories UL 1741 Standard Inverters, Converters and Controllers for Use in Independent Power Systems, or other referenced standards.
C1.1 Non-Export Test Procedure
The non-export test is intended to verify the operation of relays, controllers and inverters designed to limit the export of power and certify the equipment as meeting the requirements of Step 2, Options 1 and 2, of the Initial Review Process. Tests are provided for discrete relay packages and for controllers and inverters that include the intended function.
C1.1.1 Reverse Power Relay Test
This version of the Non-Export test procedure is intended for stand-alone reverse power and under power relay packages provided to meet the requirements of Options 1 and 2 of the Export Screen. It should be understood that in the reverse power application, the relay will provide a trip output with power in the export (toward the EC system) direction.
Step 1: Power Flow Test at Minimum, Midpoint and Maximum Pickup Level Settings
Determine the appropriate secondary pickup current for the desired export power flow of 0.5 secondary watts (the agreed-upon minimum pickup setting, assumes 5Amp and 120V CT/PT secondary). Apply nominal voltage with minimum current setting at 0 degrees in the trip direction. Increase the current to pickup level. Observe the relay's (LCD or computer display) indication of power values. Note the indicated power level at which the relay. Trips. The power indication should be within 2 percent of the expected power. For relays with adjustable settings, repeat this test at the midpoint, and maximum settings.
Repeat at phase angles of 90, 180 and 270 degrees and verify that the relay does NOT operate (measured watts will be zero or negative).
Step 2: Leading Power Factor Test
Apply rated voltage with a minimum pickup current setting (calculated value for system application) and apply a leading power factor load current in the non-trip direction (current lagging voltage by 135 degrees). Increase the current to relay rated current and verify that the relay does NOT operate. For relay's with adjustable settings, this test should be repeated at the minimum, midpoint, and maximum settings.
Step 3: Minimum Power Factor Test
At nominal voltage and with the minimum pickup (or ranges) determined in Step 1, adjust the current phase angle to 84 or 276 degrees. Increase the current level to pickup (about 10 times higher than at 0 degrees) and verify that the relay operates. Repeat for angles 90, 180 and 270 degrees and verify that the relay does NOT operate.
Step 4: Negative Sequence Voltage Test
Using the pickup settings determined in Step 1, apply rated relay voltage and current at 180 degrees from tripping direction, to simulate normal load conditions (for 3-phase relays, use Ia at 180, Ib at 60 and Ic and 300 degrees). Remove Phase-1 voltage and observe that the relay does not operate. Repeat for phase-2 and 3.
Step 5: Load Current Test
Using the pickup settings determined in Step 1, apply rated voltage and current at 180 degrees from the tripping direction, to simulate normal load conditions (use Ia at 180, Ib at 300 and Ic at 60 degrees). Observe that the relay does NOT operate.
Step 6: Unbalanced Fault Test
Using the pickup settings determined in Step 1, apply rated voltage and 2 times rated current, to simulate an unbalanced fault in the non-trip direction (use Va at 0 degrees, Vb and Vc at 180 degrees, Ia at 180 degrees, Ib at 0 degrees, and Ic at 180 degrees). Observe that the relay, especially single phase, does not misoperate.
Step 7: Time Delay Settings Test
Apply Step 1 settings and set time delay to minimum setting. Adjust the current source to the appropriate level to determine operating time, and compare against calculated values. Verify that the timer stops when the relay trips. Repeat at midpoint and maximum delay settings
Step 8: Dielectric Test
Perform the test described in IEC 414 using 2 kV RMS for 1 minute.
Step 9: Surge withstand
Perform the surge withstand test described in IEEE C37.90.1.1989 or the surge withstand test described in B.3.7.
C1.1.2 Under Power Relay Test
In the underpower application, the relay will provide a trip output when import power (toward the EP) drops below the specified power level.
Note: For an underpower relay, pickup is defined as the highest power level at which the relay indicates that the power is less than the set setting.
Step 1: Power Flow Test at Minimum, Midpoint and Maximum Pickup Level Settings
Determine the appropriate secondary pickup current for the desired power flow pickup level of 5% of peak load (the agreed-upon minimum pickup setting). Apply rated voltage and current setting at 0 degrees in the direction of normal load current. Decrease the current to pickup level. Observe the relay's (LCD or computer display) indication of power values. Note the indicated power level at which the relay. Trips. The power indication should be within 2 percent of the expected power. For relays with adjustable settings, repeat the test at the midpoint, and maximum settings.
Repeat at phase angles of 90, 180 and 270 degrees and verify that the relay operates (measured watts will be zero or negative).
Step 2: Leading Power Factor Test
Using the pickup current setting determined in step 1, apply rated voltage and rated leading power factor load current in the normal load direction (current leading voltage by 45 degrees). Decrease the current to 145% of the pickup level determined in Step 1 and verify that the relay does NOT operate. For relays with adjustable settings, repeat the test at the minimum, midpoint, and maximum settings.
Step 3: Minimum Power Factor Test
At nominal voltage and with the minimum pickup (or ranges) determined in Step 1, adjust the current phase angle to 84 or 276 degrees. Decrease the current level to pickup (about 10% of the value at 0 degrees) and verify that the relay operates. Repeat for angles 90, 180 and 270 degrees and verify that the relay operates for any current less than rated current.
Step 4: Negative Sequence Voltage Test
Using the pickup settings determined in Step 1, apply rated relay voltage and 25% of rated current in the normal load direction, to simulate light load conditions. Remove Phase-1 voltage and observe that the relay does not operate, repeat for phase-2 and 3.
Step 5: Unbalanced Fault Test
Using the pickup settings determined in Step 1, apply rated voltage and 2 times rated current, to simulate an unbalanced fault in the normal load direction (use Va at 0 degrees, Vb and Vc at 180 degrees, Ia at 0 degrees, Ib at 180 degrees, and Ic at 0 degrees). Observe that the relay, especially single phase, operates properly.
Step 6: Time Delay Settings Test
Apply Step 1 settings and set time delay to minimum setting. Adjust the current source to the appropriate level to determine operating time, and compare against calculated values. Verify that the timer stops when the relay trips. Repeat at midpoint and maximum delay settings.
Step 7: Dielectric Test
Perform the test described in IEC 414 using 2 kV RMS for 1 minute.
Step 8: Surge withstand
Perform the surge withstand test described in IEEE C37.90.1.1989 or the surge withstand test described in B.3.7
C1.1.3 Functional Test for Inverters and Controllers
Inverters and controllers designed to provide reverse or under power functions shall be tested to certify the intended operation of this function. Two methods are provided.
Method 1: If the controller utilizes external current/voltage measurement to determine the reverse or underpower condition, then the controller shall be functionally tested by application of appropriate secondary currents and potentials as described in the Relay Test C1.1.1.
Method 2: If external secondary current or potential signals are not used, then unit-specific tests must be conducted to verify that power cannot be exported across the PCC for a period exceeding two seconds. These tests may be factory tests, if the measurement and control points are part of a single unit, or may be provided for in the field.
This test will determine the maximum in-rush current drawn by the unit.
C1.2.1 Locked-Rotor Method
Use the test procedure defined in NEMA MG-1 (manufacturer's data is acceptable if available).
C1.2.2 Start-up Method
Install and setup the DG equipment as specified by the manufacturer. Using a calibrated oscilloscope or data acquisition equipment with appropriate speed and accuracy, measure the current draw at the Point of Interconnection as the DG starts up and parallels to the EC. Startup shall follow the normal, manufacturer-specified procedure.
Sufficient time and current resolution and accuracy shall be used to capture the maximum current draw within five percent. In-rush current is defined as the maximum current draw from the EC during the startup process, using a 10-cycle moving average. During the test, the utility source, real or simulated, must be capable of maintaining voltage within +/- five percent of rated at the connection to the unit under test. Repeat this test five times. Report the highest 10-cycle current as the in-rush current
A graphical representation of the time-current characteristic along with the certified in-rush current will be included in the test report and will be made available to the EC.
(END OF APPENDIX B)
(END OF ATTACHMENT A)
ATTACHMENT B
INTERCONNECTION APPLICATION AGREEMENT
