PSEG-LONG ISLAND SMART GRID SMALL GENERATOR INTERCONNECTION SCREENING CRITERIA FOR OPERATING IN PARALLEL WITH LIPA S DISTRIBUTION SYSTEM

Transcription

1 PSEG-LONG ISLAND SMART GRID SMALL GENERATOR INTERCONNECTION SCREENING CRITERIA FOR OPERATING IN PARALLEL WITH LIPA S DISTRIBUTION SYSTEM PSEG-LI SGSGIP DG Screening Criteria

2 Table of Contents I. INTRODUCTION... 3 II. GENERAL REQUIREMENTS... 4 III. CONTROL AND PROTECTION REQUIREMENTS... 6 IV. NON-INVERTER INTERFACED DG SCREENING CRITERIA A. VOLTAGE B. FLICKER C. VOLTAGE DIP D. FREQUENCY E. HARMONICS F. POWER FACTOR G. EXTERNAL FAULT AND LINE CLEARING H. DC INJECTION I. UNINTENTIONAL ISLANDING V. INVERTER-INTERFACED DG SCREENING CRITERIA A. INTRODUCTION B. KEY ASSUMPTIONS C. LIPA DG INTERCONNECTION POLICIES D. INVERTER-INTERFACED DG IMPACTS E. STEADY-STATE VOLTAGE DEVIATIONS Primary Feeder Voltage Profile Steady-State Primary Voltage Criteria Secondary Voltages F. CONTINGENCY VOLTAGE DECREASE ON SIMULTANEOUS DG TRIP G. INADVERTENT ISLANDING AND TEMPORARY OVERVOLTAGE Temporary Overvoltages Islanding TOV Criteria Out-of-Phase Reclosing Out-of-Phase Reclosing Criteria H. POWER QUALITY Flicker Flicker Screening Harmonics I. SYSTEM LOADING J. FAULT CURRENT CONTRIBUTION AND PROTECTION K. SUMMARY OF RECOMMENDED SCREENS VI. MAINTENANCE AND OPERATING REQUIREMENTS VII. CLASSIFICATION OF DG SYSTEM GENERATOR INSTALLATIONS VIII. APPENDIX APPENDIX A APPENDIX B APPENDIX C APPENDIX D APPENDIX E APPENDIX F PSEG-LI SGSGIP DG Screening Criteria

3 I. Introduction This document provides additional technical requirements defined in the Smart Grid Small Generator Interconnection Procedures (SGSGIP)for all interconnection Distribution Generation (DG) system for operating in parallel with LIPA s distribution system. This document provides details for the minimum control and protection requirements for safe and effective operation of Distributed Generation Equipment, interconnecting with the Long Island Power Authority (LIPA) radial distribution system. The term Distributed Generation Equipment (DG System) refers to generating systems owned by individuals, companies, or agencies, other than PSEG Long Island, within the PSEG Long Island service area. It is emphasized that these requirements are general and may not cover all details in specific cases. The customer must be Primary Metered for DG system greater than 1.5 MVA. Secondary Meter for DG system greater than 300 kva will be permitted up to 1.5 MVA on a case by case basis only. Primary Metering requirements are defined elsewhere. Interconnections shall not be made to primary feeders supplying secondary network systems. Generator size limitations are outlined in Section VII - Classification of DG System Generator Installations. PSEG Long Island will evaluate applications for interconnections to looped radial primary systems (fused loops). If approved, these interconnections shall be made through a LIPA installed and owned fused disconnect switch installed on the primary side of the customer owned transformer. The installation of the fused switch shall be at the DG System s expense. Interconnection requirements as well as specific electrical requirements for parallel operation with the LIPA system are provided for substation and distribution interconnections of synchronous generators, induction generators, and D.C. generators with inverters. Application forms from SGSGIP shall be used by the DG System and PSEG Long Island to document the specific characteristics of the installation. This application shall be coordinated by PSEG Long Island's Power Asset Management group. Responsibility for protection of the DG System against possible damage resulting from parallel operation with the LIPA Distribution System lies solely with the DG System. The LIPA transmission lines have automatic instantaneous reclosing and distribution feeders have automatic instantaneous and time delay reclosing with a dead time as short as 12 cycles and as long as 30 seconds. It is the DG System's responsibility to protect its equipment from being reconnected out-of-synchronism with the LIPA system after automatic reclosing of a LIPA circuit breaker. The DG System connected to the distribution system can also be affected by a transmission line breaker reclosure. It is the DG System s responsibility to protect its equipment from these reclosures. The DG System shall provide high speed protective relaying to remove its equipment from the utility circuit prior to the automatic reclosure. This requirement cannot be met by direct transfer trip equipment. 3

4 II. General Requirements Each DG System operating in parallel with the LIPA system shall have its interconnection control and protection designs reviewed and accepted by PSEG Long Island. The specific design requirements of the protection system depend on the generator type, size, and other site specific considerations. The DG System shall meet PSEG Long Island's Specifications and Requirements for Electric Installations (Red Book), latest revision, all applicable sections of the NEC and all local and municipal codes. It is the intent of these Interconnection Requirements that interconnected DG Systems meet operational requirements outlined in IEEE Standard P1547 and all future companion documents to P1547, as they may be adopted by the IEEE Standards Board in the future. PSEG Long Island reserves the right to impose site specific interconnection requirements on a case by case basis. To eliminate unnecessary costs and delays, a DG System interconnection one line drawing should be submitted to PSEG Long Island for acceptance prior to the commencement of construction and ordering of equipment. Seven (7) copies of the following must be submitted before a final acceptance can be given to the DG System's design: A. DG System Interconnection one-line drawing. B. Relay Functional diagram showing all current (CT) and potential transformer (PT) circuits, relay connections, and protective control circuits. All interconnections with LIPA's circuits should be clearly labeled (See Appendix F for an example of an acceptable relay functional). C. Three line AC schematic diagrams of transformers and bus relay protection. D. Interconnection breaker AC and DC schematics. E. Protective relay equipment list including manufacturer model number, relay ranges, manufacturer's bulletins, curves and proposed settings. F. Generator, transformer, and breaker nameplate information including generator transient, generator harmonic characteristics (non type tested generators), subtransient, and synchronous impedances and transformer positive and zero sequence impedances (Appendix D). G. Producer generator protection scheme. H. Interconnection breaker speed curve. I. All drawings should incorporate PSEG Long Island's requirements for the name and number description of major equipment (switches, breakers, etc.). No installation of equipment can be completed without written acceptance from PSEG Long Island. If the DG System is installed without prior written acceptance of the equipment by PSEG Long Island, it shall be done at the DG system s own risk. The DG System shall be solely responsible for all costs associated with the replacement of any equipment that has not been accepted by PSEG Long Island. Final acceptance of the interconnection by PSEG Long Island will be contingent upon PSEG Long Island's acceptance of all of the DG System's interconnection equipment. 4

5 If the DG System makes changes in the design of the project, any previous information furnished by PSEG Long Island shall be subject to review and possible changes. At the completion of construction, functional tests of all protective equipment shall be performed by a qualified testing company acceptable to PSEG Long Island, and PSEG Long Island reserves the right to witness such tests. If these tests are successful, and the protective relay settings have been correctly applied, PSEG Long Island shall permit the interconnection to be energized. To accomplish the interconnection and to provide for continuing operations in a safe, economical and efficient manner, PSEG Long Island shall prepare and deliver Operating Instructions to the DG System prior to interconnecting the facility. The Operating Instructions shall include but not be limited to defining requirements for: A. Maintaining proper voltage and frequency and for putting into effect voltage changes as required from time to time. B. Phasing and synchronizing the facility and LIPA's system. C. Taking feeders out of service for maintenance during a system emergency or system pre-emergency conditions and restoring such feeders to service. D. Controlling the flow of real and reactive power. E. Periodic maintenance of the interconnection circuit breaker and related facilities. F. Procedure for communication between electrical operations personnel of the DG System and PSEG Long Island. The DG System shall also ensure the availability of a dedicated telephone handset, for use by PSEG Long Island personnel during testing and maintenance of the DG System's equipment. The DG System shall be required to have a qualified testing company, acceptable to PSEG Long Island, perform maintenance, trip tests, and recalibration tests on its protective relaying devices once every two (2) years. A copy of the test results shall be sent to PSEG Long Island for review, comment, and acceptance, no later than five (5) working days after completion of tests. All other DG systems including but not limited to rotating machines, non-inverter interfaced DG system shall follow the Criteria outlined in Section IV. All inverter interfaced DG system shall be screened as per Inverter-Interfaced DG Screening Criteria (outlined in Section V). This document is developed for PSEG Long Island to provide a process to review inverter interfaced DG interconnection requests to determine the impacts and identify specific mitigation measures necessary to interconnect the DG. These screening criteria will determine whether an inverter based DG interconnection should be fast tracked or if the project requires further engineering study. 5

6 III. Control and Protection Requirements The inverter interfaced DG system passing the Inverter-Interfaced DG Screening Criteria may not need following engineering studies performed. A. Engineering Studies Engineering studies shall be performed by PSEG Long Island to determine the exact electrical configuration of the interconnection installation and to identify any required additions, changes, or modifications to the LIPA system. Major equipment requirements such as circuit breakers and special protective relaying shall also be studied. Items requiring investigation are as follows: 1. Equipment short circuit duty. 2. Feeder breaker relay protection coordination due to in-feed for three phase and line to ground faults. 3. Branch fusing coordination due to fault current in-feed from DG System's equipment. 4. Breaker Failure requirements. 5. Deadline operating restraints. 6. VAR requirements. 7. MVA limitations of generation because of location on the LIPA feeder. 8. Protective relay coordination for three phase and line to ground faults on the LIPA system and the DG System's generator installation. 9. Protective Relay Alarm Breaker Trip (required for DG Systems utilizing only one microprocessor relay). B. Equipment Requirements The following requirements apply to the interconnection of equipment of all generators operating in parallel with the LIPA distribution system: 1. All additions or changes required to protective relay and control equipment on the LIPA system shall be installed by PSEG Long Island at the DG System's expense. All additions or changes to relay and control equipment required at the point of interconnection shall be paid for and installed by the DG System. 2. The DG System shall be solely responsible for synchronizing its generator(s) with the LIPA system. 6

7 3. The DG Systems may provide a primary voltage interconnection breaker or secondary voltage breaker based on the total installed generator nameplate kva rating. The breaker shall be located in the DG System's substation. If the interconnection breaker is a switchgear breaker, it shall be a drawout type with provisions for installing a ground and test device supplied by the DG system. 4. The interconnection breaker shall be capable of withstanding 220% of the interconnection breaker rated operating voltage. 5. For interconnection breakers rated at 480 Volts or less operating voltage the breaker shall be rated to withstand the greater of 220% of the operating voltage or two times the rated operating voltage of the interconnection breaker plus one thousand (1000) volts. 6. An isolation disconnect switch (Utility Disconnect Switch) that is readily accessible to PSEG Long Island at all times located within 10 feet of the PSEG Long Island metering point or within 10 feet of the LIPA service entrance, lockable with a 3/8 inch shank LIPA lock, visible-break and load break rated shall be installed to isolate the generator from the LIPA system. If the breaker is a drawout type and the DG System provides a ground and test device acceptable to PSEG Long Island, PSEG Long Island will evaluate allowing the DG System to omit the isolation disconnect switch. 7. DG Systems may be isolated from the LIPA system by means of an isolating transformer. If this option is selected, the DG System shall have a wye grounded/delta or a wye grounded/delta/wye transformer with the wye grounded winding configuration on the LIPA side. See Appendix B for the technical explanation of this requirement. A ground fault current limiting neutral reactor shall be installed if required by LIPA on non-dedicated feeder installations. 8. The DG system can opt not to use the wye-grounded (utility side)/delta (DG side) isolation transformer if all of the following conditions are met: a) The primary connected transformer must be a wye-grounded/wyegrounded transformer, and the generator must be effectively grounded. The generator neutral reactor is normally used to limit ground fault current and protect the generator windings. The generator neutral reactor must be sized such that it both prevents overvoltages and allows enough ground fault current to be detected by the DG System s relaying for faults on the LIPA distribution feeder. b) The DG System must provide protective relaying that detects faults on the LIPA system, including ground faults. c) The DG System must meet the harmonic requirements of the interconnect guide and test data supporting this is provided. 9. A DG System with a total connected primary and/or secondary interconnect generator nameplate rating of greater than 1000 kva shall require a SCADA (Supervisory Control and Data Acquisition) system RTU (Remote Terminal Unit). PSEG Long Island may also require SCADA to be installed on 7

8 installation smaller than 1000 kva if deemed necessary for the safe operation of the LIPA system. The RTU, if required, will be purchased by PSEG Long Island and paid for by the DG System or may purchased by the DG System to PSEG Long Island s specifications and delivered to PSEG Long Island. The RTU shall provide PSEG Long Island with supervisory trip control of the interconnection breaker(s). It shall also provide telemetry of key operating parameters of the DG System's facility, which shall include but not be limited to: a. Status indication of interconnection breaker(s), generator breaker(s), and all other devices that are in series with these breakers. b. Status indication of various alarms such as loss of DC to interconnection breaker(s), loss of DC to RTU, loss of AC to RTU battery charger, loss of relaying communication channel, microprocessor relay alarm, etc. c. Digital metering telemetry for current, voltage, watts, VARS, and power factor for all interconnection breaker(s). d. Pulse accumulation of MWHR (in/out) and MVARHR (in/out) for the facility Access to the pulse metering signal will be made available to PSEG Long Island for the installation of additional metering and communications equipment if required. The location of the RTU shall depend on the proximity of the DG System to the interconnecting LIPA substation. The DG System shall not be allowed to operate in parallel if the RTU or its associated lease line is out of service. The RTU shall be maintained and repaired by PSEG Long Island at the DG System's expense. All costs for additional hardware and software for LIPA's mainframe supervisory computer that are required for its interconnection shall be charged to the DG System. Whether the RTU is purchased by the DG System or by LIPA, it shall be delivered to PSEG Long Island for testing and programming. At this time, loss of AC/DC relays, fuses, and various terminal blocks will be installed within the RTU cabinet by PSEG Long Island at the DG System's expense. The DG System shall make provisions adjacent to the supervisory control cabinet to terminate the supervisory control four (4) wire dedicated telephone lease line(s) on a double pole double throw open blade cut off switch(es) (diagram Appendix C). The lease line(s) shall be ordered by LIPA and owned by LIPA. Installation, maintenance and subsequent monthly charges shall be charged by LIPA to the DG System. 8

9 10. For facilities interconnected to LIPA by means of a dedicated feeder, a breaker shall be installed at the DG System's expense in the LIPA substation. For a non-dedicated feeder, a disconnect device controlled by LIPA shall be installed at the DG System's expense at the point of interconnection with the LIPA system. 11. The DG System shall be responsible for tripping its interconnection breaker if a fault occurs on the electric facilities serving its installation. Whenever the LIPA supply is de-energized, the DG System's interconnection breaker shall be tripped by voltage and/or frequency relays and transfer tripped from LIPA's interconnection substation. The interconnection breaker shall be automatically locked out and prevented from closing into a de-energized or partially de-energized (loss of one phase) LIPA system. The interconnection breaker close circuit shall include a synch check and an over/under voltage permissive contact to prevent closing the breaker when unfavorable voltage conditions exist. 12. The direct transfer trip (DTT) receiving terminal shall provide two outputs: a trip output and an alarm output to indicate a loss of transfer trip condition. The trip output shall energize a utility type target relay with multiple output contacts. One (1) output contact of the target relay shall trip the interconnection breaker. A second output contact of the target relay and the alarm contact of the DTT terminal shall be wired to the RTU. The DTT terminal and associated target relay shall be mounted indoors. 13. The alarm for the loss of a DTT lease line must come from the DG System s SCADA or by having a bi-directional tone equipment that can give the alarm at the LIPA substation. If no SCADA is provided, a transfer trip receiver and transmitter with 4 wire lease line shall be provided. In the event of DDT lease line loss, the DG System shall cease parallel operation with the LIPA system. For DG systems less than 1000 KVA, the transfer trip system will be used for LIPA supervisory trip. 14. The required dedicated transfer trip lease line shall be ordered by LIPA. Installation, maintenance and subsequent monthly charges shall be charged to the DG System. The DG System shall make provisions to terminate the lease line with a double pole double throw open knife blade switch adjacent to the transfer trip equipment (Appendix C). The DG System will not be allowed to parallel with the LIPA system if its transfer trip or associated lease line is out of service. 15. For DG System s utilizing only one microprocessor relay, the interconnection breaker or the generator breaker(s) must be tripped when the DG System s protective relaying system goes into an alarm condition. This trip shall also trip a lock-out relay that requires manual intervention before the breaker(s) can be reclosed following successful clearing of the relay alarm condition(s). 9

10 16. The alarm for the loss of a DTT lease line must come from the DG System s SCADA or by having a bi-directional tone equipment that can give the alarm at the LIPA substation. If no SCADA is provided, a transfer trip receiver and transmitter with 4 wire lease line shall be provided. In the event of DDT lease line loss, the DG System shall cease parallel operation with the LIPA system. For DG systems less than 1000 KVA, the transfer trip system will be used for LIPA supervisory trip. 17. The required dedicated transfer trip lease line shall be ordered by LIPA. Installation, maintenance and subsequent monthly charges shall be charged to the DG System. The DG System shall make provisions to terminate the lease line with a double pole double throw open knife blade switch adjacent to the transfer trip equipment (Appendix C). The DG System will not be allowed to parallel with the LIPA system if its transfer trip or associated lease line is out of service. 18. For DG System s utilizing only one microprocessor relay, the interconnection breaker or the generator breaker(s) must be tripped when the DG System s protective relaying system goes into an alarm condition. This trip shall also trip a lock-out relay that requires manual intervention before the breaker(s) can be reclosed following successful clearing of the relay alarm condition(s). 19. The following are the minimum relay requirements for the interconnection breaker: a. Phase overcurrent relays (one per phase) with instantaneous and voltage restraint time delay elements are required as well as one ground overcurrent relay with instantaneous and time delay elements. Each element of the phase and ground relays shall have its own target. b. Over/under voltage relays and over/under frequency relays are required on LIPA s side of the interconnection breaker. c. Directional power relays may be required to limit power flow to contractual agreements. d. Directional overcurrent relays shall be required at sites where the DG System s load requirements from LIPA exceed the DG Systems generating capability. Any exceptions to this requirement shall be approved by LIPA. e. Transformer differential relaying shall be required for interconnections using transformer banks greater than 1500 kva. f. Negative sequence overcurrent relays. g. All interconnection breaker relays and required generator breaker relays shall be approved by LIPA. Interconnection breaker relays must be 10

11 capable of being calibrated and tested in their installed position to verify proper application of all relay settings and full functionality of the relay circuit(s). 20. All breakers shall be D.C. trip and close. Trip and close circuits of the interconnection breaker must be separately fused. If SCADA is provided then loss of D.C. and low DC voltage alarms shall be wired to the RTU. 21. Control, CT, and telemetering leads which interconnect to LIPA shall have a minimum size and stranding of 19/25, 19/22, and #18 STP, respectively. All control, CT, and telemetering leads must be terminated using ring type connectors. 22. The station battery shall be sized for an eight hour duty cycle in accordance with IEEE Standard At the end of the duty cycle the battery shall be capable of tripping and closing all breakers. 23. All solid state relays requiring an auxiliary power source shall be powered from the station battery. AC to DC converters is unacceptable. 24. All relaying CTs shall have a minimum accuracy of C200. Saturation current shall not be more than 10% of fault current. Interconnection relaying and telemetering shall have dedicated CTs. 25. Three PTs shall be installed on the LIPA side of the interconnection breaker and shall be connected wye-grounded/wye-grounded. Three red indicating lights, one per phase, connected phase to ground in the PT secondary, shall be installed to provide visual verification of potential on each phase. Three (3) single phase over/under voltage relays, associated with the high side breaker, shall be connected phase to ground to these PTs. 26. During emergency conditions, all interconnection breakers shall be capable of being tripped by LIPA via supervisory control. LIPA will consider tripping the generator breaker instead of the interconnection breaker if the system configuration permits. Interconnection breaker and generator breaker(s) status will be transmitted to LIPA via the RTU. The supervisory equipment shall be installed and paid for by the DG System. A digital meter or MW, MVAR, current, voltage and power factor transducers mounted in flexitest drawout cases shall be connected to the interconnection breaker CTs and line PTs and wired to the analog inputs of the RTU. LIPA shall furnish the DG System with the necessary wiring drawings to connect the transducers to the supervisory equipment. 11

12 27. Synch check relays are required across the interconnection breaker of a synchronous generator unless otherwise specified. A total of four potential transformers shall be required on the interconnection, three on LIPA's side of the breaker (as specified in #22) and one on the DG System's. Synch check relays shall be installed for manual synchronizing. Automatic synchronizing equipment shall be optional, however, it shall not permit the exclusion of a synch check relay. 28. The LIPA substation feeder breaker may require a set (3) of line side potential transformers to monitor the presence of voltage on the distribution feeder and to provide voltage to a synch check or voltage relay, which shall prevent closing the breaker into an unsynchronized DG System's generator. All costs incurred to purchase and place this system in service shall be at the DG System's expense. 29. The kvar requirements of an induction generator, operating at 100% load, will be determined and the DG System will be charged that portion of the cost to install one or more 900 kvar supervisory controlled distribution capacitor banks to provide the reactive supply. 30. Voltage and frequency relays shall be installed at the LIPA substation to disconnect the DG System's generator from the LIPA bus in the event that this bus becomes isolated from the LIPA system and the DG System's generator continues to carry the connected LIPA load. These relays shall be installed at the DG System's expense. 31. Interconnection breaker(s) for DG System owned generator(s) on the distribution system, unless otherwise specified, shall be automatically tripped for all trips of the LIPA substation feeder breaker. A generator breaker contact may be used to disable transfer trip of the interconnection breaker when the generator breaker is open. The communication tripping channel and transfer tripping equipment at the LIPA substation and at the DG System's facility shall be purchased and installed at DG System's expense, as part of the relay protection scheme. The transfer trip equipment and associated transfer trip communication channel shall be specified by LIPA. 32. The transformer configuration of an existing LIPA transformer that is to become customer-owned in a new primary metered installation must be verified in the field. The DG Systems will bear the cost of a replacement wye-wye transformer, which may be greater than the cost of purchasing the in-place LIPA transformer. 12

13 IV. Non-inverter Interfaced DG Screening Criteria It is the policy of LIPA to permit any applicant to operate a DG System in parallel with the LIPA electric system whenever such operation can take place without adversely affecting other PSEG Long Island customers, the general public, LIPA equipment and PSEG Long Island personnel. To minimize this interference, the DG System shall meet the following criteria: A. Voltage The DG System shall produce voltages within ± 5% of nominal when operating in parallel with the LIPA system. (Nominal voltages on the LIPA distribution system are 13.8 and 4.5 kv). The DG System shall provide an automatic means of disconnecting its generating equipment from LIPA's facilities as follows: Voltage Range (% of base voltage) Clearing Time (seconds) V < V < < V > V Base voltages are nominal LIPA system voltages. The clearing time is the time between the start of the abnormal condition and the DG System ceasing to energize the LIPA system. The clearing times indicated are default times and may be adjusted based upon application specific requirements subject to PSEG Long Island review and approval. B. Flicker The DG System shall not cause voltage variations on the LIPA system exceeding those defined on the Border Line of Visibility in Appendix E - Voltage Flicker Curves. C. Voltage Dip The voltage dip on a primary circuit due to inrush current should not exceed 2 Volts on a 120 Volt base. D. Frequency The DG System shall provide an automatic means of disconnecting its generating equipment from LIPA's facilities for over and under frequency situations. No under frequency tripping shall take place between 59.9 Hz and 58.0 Hz. The final under frequency set point shall be determined to best support the operation of the LIPA system. The equipment must be disconnected within 0.16 seconds for a frequency of 60.5 Hz or more and within 1.0 second for a frequency of less than 58.0 Hz. 13

14 E. Harmonics The total harmonic voltage or current distortion created by a DG System must not exceed 5% of the fundamental 60 Hz voltage or current waveform. The harmonic current injection shall be exclusive of any harmonic currents due to harmonic voltage distortion present on the LIPA system without the DG System connected. Any single harmonic shall not exceed 3% of the fundamental frequency. Where: hi 2 % Total Harmonic Distortion (THD) = i=2 x100 h1 1 While a Single Component % Distortion = hi h x h i = The magnitude of the i th harmonic of either voltage or current. h l = the magnitude of the fundamental voltage or current. For non-type tested units, as defined in the New York Standardized Interconnection Requirements and listed on the New York Public Service Commission website, the DG System(s) shall provide manufacturer s harmonic testing reports. F. Power Factor DG Systems utilizing synchronous generators shall produce or absorb VARS such that the overall power factor at the delivery point (location of LIPA's revenue metering equipment) is between 0.90 and 1.0 leading or between 0.90 and 1.0 lagging. LIPA's System Operator may request DG System to adjust the power factor at the delivery point, within the above stated limits. For DG Systems utilizing induction generators with a nameplate power factor below 1.0, PSEG Long Island shall provide, at the DG System's expense, VAR capacity from its system to bring such generators' power factor to 1.0. G. External Fault and Line Clearing The DG System shall be responsible for disconnecting from the LIPA system within 8 cycles of the occurrence of a fault on the LIPA distribution system using it s relaying. Backup relaying must coordinate with LIPA's protective relaying. Note: The maximum available symmetrical short circuit current from LIPA on the 13 kv distribution system is 16,000 amperes and is exclusive of any other DG Systems that may be connected to the same LIPA substation. 14

15 H. DC Injection The DG System shall not inject dc current greater than 0.5% of the full rated output current at the point of interconnection with the LIPA system. I. Unintentional Islanding In the event that an unintentional island in which the DG System energizes a portion of the LIPA system across the interconnection point, the DG System shall detect the island and cease to energize the LIPA system within two seconds of the formation of an island. 15

16 V. Inverter-Interfaced DG Screening Criteria A. Introduction Distributed generation (DG) can have an adverse impact on the operation, protection, equipment duty, and power quality of a distribution feeder. These impacts are a function of the types of DG and the total amount of DG relative to the characteristics of the feeder. Long Island Power Authority (LIPA) has established a process for review of DG interconnection requests in order to determine impacts and identify specific mitigation measures necessary to interconnect the DG. B. Key Assumptions The preparation of this screening methodology is intended to be specifically focused on the design characteristics of LIPA s distribution systems. A number of key assumptions have been made, which are specific to the LIPA system. Thus these criteria may not be applicable to other distribution systems, nor are the screening criteria necessarily comparable to any other utility s or standards body s criteria. LIPA Distribution System Design and Operating Characteristics Feeders are relatively short, shorter than ten miles with relatively few exceptions. Feeder step voltage regulators are infrequently applied in LIPA distribution systems. Substation transformers use line drop compensation on the LTC controls. Distribution capacitor banks are controlled by time clocks or via pager, and are not primarily controlled based on local distribution feeder voltage. Fixed capacitor banks are infrequently used on feeders. Pager-controlled capacitor banks are switched off during light load conditions. Time clock controlled capacitor banks may be switched on during lighter-load periods (e.g., shoulder seasons), but would not be on during nighttime minimum-load periods. Three-phase distribution transformers are nearly always configured grounded-wye grounded-wye. Distribution transformer resistances are almost always less than 2%IR. Feeder voltages may be as high as 126 V (on a 120 V base). C. LIPA DG Interconnection Policies The consideration of the need to provide a ground source to avoid excess overvoltages is part of the development of the fast-track screening thresholds defined in this report. Any inverter-interfaced DG passing the proposed process (i.e., rating less than the defined thresholds) can be deemed to not need to provide a ground source to the LIPA feeder. Any DG exceeding the thresholds defined in this report requires further study to determine the technical requirements for interconnection, including the provision of a feeder ground source. Customer service voltages driven out of range by that customer s DG is not a criterion for impact assessment or screening. 16

17 Flicker imposed on a customer by that customer s variable DG output is not a criterion for impact assessment or screening. Flicker imposed on other customers, including those served by the same distribution transformer, is to be considered. LIPA may choose to require direct transfer trip (DTT), potentially for reasons beyond the direct distribution system impact discussed in this report (e.g., overall LIPA system energy management). Installation of DTT inherently requires engineering effort to interconnect the DTT system to the feeder protection, and to provide appropriate controls to transfer the DTT connection when the associated feeder section is transferred to other feeders during any operational feeder reconfiguration. This engineering effort, by definition, is inconsistent with the fast track process. Therefore, any DG interconnection requiring DTT will be assumed to not qualify for the fast-track process. D. Inverter-Interfaced DG Impacts The various impacts of DG have been amply described in many technical papers, as well as in IEEE Standard In this section of the report, the various types of impacts are catalogued and briefly described. Specific quantitative screening criteria are established which can be used to screen interconnection requests for inverter-interfaced DG. E. Steady-State Voltage Deviations 1. Primary Feeder Voltage Profile DG output reduces the net load served by the distribution system, and at high penetration, can potentially reverse the flow of power in the feeder. This can cause feeder voltage profile deviations, which may result in customer service voltages outside of ANSI C84.1 Range A. Screening criteria need to identify any significant risk that a DG interconnection could result in service voltages outside of this range, for any reasonably anticipated operating condition. Because DG reduces, or reverses, power flow, the usual effect on steady-state voltage is to cause an increase of voltage. This is not always the case, however, when DG interacts with voltage regulating devices using line drop compensation, or automatic capacitor switching controls. These interactions can potentially result in a voltage decrease. (Voltage regulating devices, in this context, includes line voltage regulators and distribution substation transformer on-load tap changers.) A very serious voltage deviation can occur if power through a feeder voltage regulator is reversed, and the regulator controls are configured to use reverse power flow as an indication that the feeder has been reconfigured such that the substation is now connected to the former load side of the regulator. Regulator controls with this reverse power sensing will switch the side that is regulated. If the power reversal is caused by DG output, and the substation remains connected to the same side of the regulator as before the power reversal, the switch of regulation to the substation side will cause the regulator tap to go to max boost or max buck tap setting. This is because the regulated side needs to be opposite the side from which has the most stiffness, or short-circuit strength. Inverter DG can provide power, but do not provide significant stiffness. Therefore, the reversal of 17

18 regulator control configuration, caused by DG-induced power reversal, results in the regulator attempting to regulate the strong side. As the tap changes, the regulated side voltage will not change appreciably, but the other side (where the DG is connected) will. The tap control will not be satisfied e.g., a high sensed voltage will cause the regulator to increase buck, and the sensed voltage will increase as a result thus causing the regulator to go to the maximum buck limit, resulting in very low voltages on the DG side of the regulator. Feeder voltage regulators are infrequently used in the LIPA system, but LIPA distribution substation transformer LTC controls have automatic voltage regulators with line drop compensation. LIPA feeder capacitors are pager controlled by system operators or are controlled by time clocks. Thus, the steady-state voltage impacts of DG on the LIPA system, for feeders without time clock controlled capacitor banks, are limited to the more straightforward condition of voltage rise caused by reversed power flow. The DG output need not exceed the total feeder load demand in order for power to be reversed on a portion of the feeder, and for excessively high voltages to occur. Figure 1 illustrates a case where the output of a large DG connected to the end of a feeder is less than the total feeder demand, but the voltage at the end of the rises outside of the acceptable range. Figure 1 Illustration of high voltage caused by DG with a capacity less than feeder load demand If a feeder of uniform per-mile impedance and load density is assumed, and it is also assumed that load power factor is periodically corrected along the feeder, then a concentration of DG located at the end of the feeder with output equal to 50% of the feeder demand results in a U shaped voltage profile where the substation end and remote end voltages are approximately equal. This scenario is illustrated in Figure 2. With these same assumptions, output of DG uniformly distributed along the feeder, with an aggregate output equal to 100% of feeder demand, results in a flat voltage profile. 18

19 Figure 2 Approximate voltage profile for a uniform, power-factor compensated feeder with a DG located at the remote end with output equal to 50% of feeder demand. Some LIPA feeders have capacitor banks that are controlled by time clocks. These capacitors are switched in for the daytime and evening hours, independent of the day of week or season of year. Thus capacitors will tend to be on during days when loading is quite light, such as weekend days during the shoulder seasons. Thus, these capacitors can overcompensate the feeders during these times, and feeder voltages at the capacitor bank locations can be substantially elevated. By standard, the voltage should not be raised greater than 126 V (this value may be exceeded in some locations in some instances). However, by raising primary voltage to this level, insufficient margin remains for any secondary voltage rise caused by DG. Likewise, substation bus voltage or feeder voltage regulator load-side voltage regulated to the maximum 126 V value also result in lack of margin for secondary voltage rise. These issues are discussed later in the section covering secondary voltages. LIPA substation transformers have on-load tap changer controls with line drop compensation (LDC), which increase substation bus voltage in proportion to the total loading on the transformer. This application of LDC has the inherent assumption that the loading patterns on the feeders are relatively similar, and that all of the feeders have similar voltage drops. Thus, control of the substation voltage with LDC can achieve reasonably good control of the feeder-end voltages. Even without DG present, this assumption is often quite imperfect. For example, a typical substation may have certain feeders supplying predominately commercial load, and others serving predominately residential load. Additional voltage range margin is needed in the feeder voltage management planning to account for the dissimilar loading pattern and voltage drops. The presence of DG can aggravate the differences in feeder voltage drop if the DG power production is dissimilar on the various feeders supplied by the substation. This can result from either differences in the installed DG capacity, or differences in the relative output of the DGs due to availability of their energy source (e.g., in the 19

20 case of possible future wide scale PV deployment, a cloud could shadow the geographic area served by one feeder while PV generators on another feeder are receiving full sunlight). Because the LDC at the substation transformer responds to the total load, and thus controls the average voltage drop, high DG penetration could cause voltages on certain feeders to be either too high or too low. This is illustrated in the extreme case shown in Figure 3, where high DG output on the top feeder causes excessive voltage at the end because the substation voltage has not been lowered enough, and an undervoltage condition on the end of the bottom feeder because the substation voltage has not been boosted enough for the voltage drop due to the loading on that feeder. Because feeder voltage regulation design must allow for the normal dissimilarities in feeder loading, there is inherently the capability to accommodate some degree of DG-caused net load dissimilarities, as well, unless the dissimilarity in DG production far exceeds the load dissimilarities. Figure 3 Illustration of DG interaction with substation transformer tap changer control line-drop compensation 2. Steady-State Primary Voltage Criteria To allow for feeder voltage drop without DG contribution, LIPA may wish to operate its distribution substation bus voltages up to 126 V (equivalent, on a 120 V base), the upper limit of Range A. Thus, any DG output that causes voltage anywhere on the feeder to exceed the substation bus voltage is undesirable. Within the idealized assumptions described previously for the example shown in Figure 2, it could be concluded that DG output up to 50% of the minimum feeder load is acceptable if the DGs are concentrated at the feeder remote end. If the DGs are widely distributed small units, the acceptable limit could reach 100% of minimum feeder load. 20

21 Practical feeders, however, seldom exhibit the uniformity assumed to derive these thresholds. Reduced conductor size may be used remote from the substation, because the current in these feeder sections is typically less. Thus, per-mile impedance may increase as distance from the substation increases, increasing voltage rise due to DGcaused reverse power flow at the remote feeder ends. Loads are also typically not uniformly distributed along a feeder. Feeders may be overcompensated, by line and cable charging during light-load conditions, further increasing remote end voltage. (It is assumed that switched capacitor banks would be off during light-load conditions, and LIPA infrequently uses fixed capacitor banks.) Thus, it is prudent to allow extra margin in the criteria to allow for these non-ideal circumstances, as well as to allow for dissimilarity in the net load of feeders supplied from the same substation. A 50% margin is deemed sufficient to minimize risks of adverse steady state voltage impact. The following criteria are recommended to indicate interconnections where impacts are not deemed significant: P single <0.5/(100% + 50%) = 0.33 P fdr_min [3.1] P total <1.0/(100% + 50%) = 0.66 P fdr_min [3.2] Where: P single is the rating of the DG application being screened P total isthe sum of all the DG ratings connected to the feeder, including the DG under screening P fdr_min is the minimum load demand of the feeder. The criterion for P total in Equation 3.2 is based on the assumption of widely distributed small DG. There could be acase where all the DGs are concentrated at an adverse location, such as a feeder remote end. In this case, all the DG together could have the impact of one large DG. The screening can be conservatively simplified to the following: P total <0.33P fdr_min [3.3] It is expected that a large percentage of the inverter-interfaced DG that will seek interconnection to the LIPA system will be PV solar. This form of generation can only produce during daylight hours. Thus, it may be unduly conservative to compare PV generation with feeder absolute minimum load which generally occurs during hours of darkness. Other forms of inverter-interfaced DG are generally uncorrelated with time of day. The following steady-state screening criteria are recommended to provide reasonable consideration of the time-dependent output of solar generation: P total <0.33P fdr_min_day and P total_non-solar <0.33 Pfdr_min [3.4] Where: P total_non-solar is the sum of all the DG ratings, other than solar, connected to the feeder, including the DG under screening if it is non-solar. P fdr_min_day is the minimum load demand of the feeder during daylight hours (nominally, between 7 a.m. and 7 p.m). 21

22 All other variables are defined as previously.in addition to a screen of the overall feeder DG capacity and load, similar screening also should be applied for a DG interconnecting to a single-phase feeder lateral. Lateral voltage rise would generally be inconsequential for a lateral supplied by the main feeder at a point remote from the substation. However, rise on a lateral near the substation could result in customers near the end of that lateral receiving excess voltage. DGs connected to a lateral can be expected to be of small rating, and thus it is reasonable to assume that if the aggregate rating of DG on the lateral is sufficient to be of consequence, the DGs can be assumed to be distributed on the lateral. If distribution of the DG capacity is perfectly uniform, then DG capacity up to the lateral s minimum load should not cause voltage rise. However, the DG capacity will be somewhat unevenly spread in practice, so a 25% margin is recommended as shown in Equation 3.5. Because capacitor banks are not typically installed on laterals, this recommended degree of margin can be less than the 50% margin recommended for the feeder as a whole. P lat <0.80 Plat_min_day and P lat_non-solar <0.80 P lat_min [3.5] Where: P lat is the sum of all the DG ratings connected to the lateral, including the DG under screening P lat_non-solar is the sum of all the DG ratings, other than solar, connected to the lateral, including the DG under screening if it is non-solar P lat_min_day is the minimum load demand of the lateral during daylight hours (nominally, between 7 a.m. and 7 p.m). P lat_min is the minimum load demand of the lateral Actual lateral peak and minimum loading are often not available data, but can be reasonably estimated. For the purposes of this criterion, the ratio of lateral minimum load to connected transformer capacity on the lateral can be assumed to be the same as the ratio of feeder minimum load to total distribution transformer connected to the entire feeder. This assumption is based on the fact that, with sufficient loads to have good diversity (typically ten or more), the lateral load cycle will be reasonably consistent with the overall feeder load cycle. If the lateral has a small number of customers, then in the case of the LIPA system (in contrast with some rural utilities) it is reasonable to assume that the lateral is very short and lateral voltage drop/rise is not of significance. 3. Secondary Voltages The voltage criteria which have been so far described are intended to maintain a satisfactory voltage profile on the distribution primary feeder and its primary laterals. In addition to possible impacts on primary voltage, DG interconnection will also affect secondary voltages. Whereas significant primary voltage impacts will usually require a significant number of DG installations, a single DG may cause voltage issues at the secondary level. The impact of DG on secondary voltages may be considered separately for residential single-phase services, and large commercial three-phase services. There are significant differences between residential and commercial services in terms of load diversity, effect on other customers, and typical distribution transformer impedances. 22