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MINUTES OF P1547.6 MEETING (Presented as Annotated Agenda) P1547.6 Meeting Aug 3–4, 2006 IEEE P1547.6 Draft Recommended Practice for Interconnecting Distributed Resources with Electric Power Systems Distribution Secondary Networks Las Vegas NV, Embassy Suites Convention Center J. Koepfinger, Chair [email protected] J. Bzura, Vice Chair [email protected] T. Basso, Secretary [email protected] August 3, 2006 Thursday 8 a.m.–5 p.m. 8–8:30 a.m. Arrive/Register 8:30–9:15 a.m. Welcome/introductions. Presentation of P1547.6 and IEEE background material and draft agenda for meeting. Past minutes presentation and approval. Agenda review and approval. John Bzura introduced the scope of the work for the day (see Annex B). He indicated that papers had been presented by Murray Davis and Jim Daley and that Mr. Ferro would make a presentation on his work on network interconnections. 9:15–10:30 a.m. Status report on material for P1547.6 proposed new outline clauses: J. Koepfinger, J. Bzura, and writing team leads (approximately 30 minutes each), including team leaders’ responses to minutes February 2006 action items (minutes annexes F and G). o Clause 7, “Overview of Network Distribution Systems: Design, Components and Operation” Mr. Peterson discussed the work that has been done on this clause. For details, see Annex C. o Clause 8, “Primary Concerns of Operating DR on Networks” Presentation made by Mr. Moh Vaziri. See Annex D for the presentation material. o Clause 9, “Fundamental Requirements for Interconnection of DR on Networks” Presented by Dr. Bzura. See Annex E for the presentation material. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 1 o Clause 10, “Procedures to Alleviate Concerns of Operating DR on Networks” The presentation was made by Mr. Davis. See Annex F for presentation material. Methods to solve DR interconnections to networks were presented. NP will open on about 5% reverse power. Network relay can determine the difference and between reversed fault current from Dr generation and reverse load current. Spot Network solutions were discussed. Clearing time is 3–5 cycles. Some clearing times may approach 20 cycles. Time delay is sometimes used to coordinate NP with DG protection. Another solution is not to connect the DR directly to the network but connect it to an independent network feeder. One of the solutions was to take a trip signal from the NP to trip the DR if any of the DR saw reverse flow. In another installation, use was made of a Solid States Switch to switch the generator of the network to its dedicated load on reverse flow through the NP. Use of FO is possible as a channel for transfer trip. As the customer load decreases, the output of Dr is reduced to keep a fixed ration between DR output and customer load. There should be a note in the document that network grid DR connections are limited to none export applications. MTC Proposed R&D to Advance DR/Network Interconnections – William Ferro See Annex G for presentation material. This presentation discussed work done for a Northeast utility to develop a recommended practice for the interconnection of DR to spot networks that would not require the use of time delay of the NP to coordinate with the DR protection during a low reverse flow through the NP. Techno-economic issues yet to be discussed include: o o o o How to select the low reverse power setting for various types of DR Guidance on how to select the minimum necessary time delay to avoid false tripping of the NP DR size restrictions Caution on using the time delay technique, e.g. evolving faults and cross-town faults. Techno-legal issues yet to be discussed include: o De facto giving reverse power tripping control to a non-utility entity when the DR or facilitator owns and maintains the circuits which determine when a network under power limit has been reached. o Migrating this exposure to a non-utility protective function failure by limiting the size of the DR that can be interconnected to less than the minimum spot network load. o The non-time delay method is the use of breaker duty relief scheme, where the tripping of the NP is interlocked with the DR isolating device. This tripping is sequential. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 2 o The method for accomplishing a highly reliable scheme is posted on Massachusetts Technology Collaborative website: www.masstech.org/dg/collab.reports.htm. 12–1:15 p.m. Lunch 1:15–5 p.m. Breakouts for proposed new outline clauses 7–10. All WG members joined a group to review proposed clause outline and initial material, draft detailed proposed sub-outline, and draft revised and new material for respective clauses 7–10. August 4, Friday 8 a.m.–3 p.m. 8–8:30 a.m. Arrive/Register 8:30–10:15 a.m. Status reports by breakout leaders (20 minutes each), including progress, recommendations, and discussion questions for consideration by the WG as a whole. o Clause 7, presented by J. Koepfinger and R. Peterson This is complete except for the art work. A request was made for art work. Before it can be circulated, it will be necessary to include the graphics mentioned in the clause. See Annex H for this material. o Clause 8, presented by Moh Vaziri 30 issues were presented and discussed. The material presented is in Annex I. It was suggested that the material should avoid saying who should do what. The task force draft will be rewritten to take into consideration a concern that it should not appear to be of the nature that its sounds like a directive for EPS operations. o Clause 10, presented by Dr. Bzura Clause 9 has been integrated into Clause 10. The discussion material is found in Annex J. 10:15 a.m.–Noon Open discussion of P1547.6 topics and recommendations – J. Koepfinger. Presentation and discussion of the draft P1547.6 extended outline (based on 8/05 and 2/06 WG meetings and yesterday’s breakouts sessions) – John Bzura and Joe Koepfinger. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 3 Noon–1:15 p.m. Lunch 1:15–1:45 p.m. Summarize action items, plans, and the proposed next meeting. 1:45–3 p.m. (Adjourn) Breakout sessions reconvene based on morning’s discussions. Respectfully Submitted, Joe Koepfinger – Chair P1547.6; John Bzura – Vice Chair, Tom Basso – Secretary, and Amy Vaughn – NREL Communications Specialist. ------------------------- see annexes for further details -----------------List of Annexes: Annex A: Annex B: Annex C: Annex D: Annex E: Annex F: Annex G: Annex H: Annex I: Annex J: Attendees: P1547.6 Meeting, Las Vegas, Nevada, August 1–4, 2006 P1547.6 Draft Outlines P1547.6 Clause 7 Pre-Breakout Status Report P1547.6 Clause 8 Pre-Breakout Status Report P1547.6 Clause 9 Pre-Breakout Status Report P1547.6 Clause 10 Pre-Breakout Status Report Bill Feero Network Interconnection Presentation P1547.6 Clause 7 Post-Breakout Status Report P1547.6 Clause 8 Post-Breakout Status Report P1547.6 Clauses 9 & 10 Post-Breakout Status Report P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 4 ANNEX A: ATTENDEES: P1547.6 MEETING LAS VEGAS, NEVADA, AUGUST 1–4, 2006 Joe Koepfinger – Chair David Beach James Daley Murray Davis Richard DeBlasio Andris Garsils C. Travis Johnson John Bzura – Vice Chair Mike Miller Jock Moffat George Moskos Robert Peterson Amy Vaughn Mohammad Vaziri P1547.6 Meetings for August 3-4, 2006 Working Group Meeting Tom Basso – Secretary Tim Wall James Watts Charles Whitaker Steve Chalmers Bill Feero 5 ANNEX B: P1547.6 DRAFT OUTLINES IEEE P1547.6 Initial Draft Outline (August 5, 2005) 1. Introduction 2. Scope 3. Purpose 4. Limitations 5. References 6. Definitions/Acronyms 7. Types/characteristics of network and control systems 7.1. Spot networks 7.1.1 Consideration for integration of DR into spot networks 7.1.1.1. Map 1547 requirement to networks 7.1.1.2. Planning consideration 7.1.1.3. Protection Considerations and settings – impact of DR on 7.1.1.4. Communication Considerations 7.2. Grid Networks 7.2.1. Consideration for Integration of DR into spot networks 7.2.1.1. Map 1547 requirements to networks 7.2.1.2. Planning consideration 7.2.1.3. Protection consideration – impact of DR on 7.2.1.4. Communication considerations 8. Essential issues to be addressed for interconnection of DR on networks 8.1. Spot network 8.2. Grid network Annex A – Bibliography P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 6 Proposed Draft Outline Revisions J. Bzura P1547.6 Meeting Atlanta GA; February 2-3, 2006 7. Overview of Network Distribution Systems: Design, Components and Operation (Joe Koepfinger, Martin Baier, Dave Costyk, Jim Daley, Bob Peterson, Betty Tobin ) 7.1 Spot Networks 7.2 Area Networks 8. Primary Concerns of Operating DR on Networks (Moh Vaziri, Larry Gelbien, F. Bigenho, Jim Watts, Tim Wall, Dan Sammon, Chuck Whitaker, Travis Johnson, David Smith, other volunteers) 8.1 Reverse power flow 8.2 Fault current contributions 8.3 Effects of DR on area network load flows 8.4 Effects of potential network system component failures 9. Procedures to Alleviate Concerns of Operating DG on Networks (Murray Davis, John Bzura, Marty Baier, Murray Davis, Jim Daley, Jock Moffat, David Beach, Larry Gelbien, Moh Vaziri, Sam McAllister, _ Ebrahim, Tom Greely, other volunteers) 9.1 Measures to sense and ameliorate (prevent) reverse current flow 9.1.1 Minimum power level DR trip 9.1.2 Reverse power flow sensing for DR trip 9.2 Fault current minimization 9.2.1 Limitation by DR technology 9.2.2 Limitation by switching technology 9.3 Site-specific analysis of DG on area networks (Larry G to lead?) 9.4 Coordination of DR with network operations (Murray D to lead?) 9.4.1 monitoring and control specific to DR on networks P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 7 10. Requirements for Integration of DG on Networks (John Bzura, Martin Baier, Murray Davis, Jim Daley, Jock Moffat, David Beach, Larry Gelbien, Moh Vaziri, Sam McAllister, _ Ebrahim, Tom Greely) 10.1 Fundamental Hypothesis The primary function of a protective relay and control scheme for a proposed DG unit operating in parallel with a network grid is to separate the power source from the network immediately* on the occurrence of any anomaly in the network voltage, frequency or power flow direction. 10.2 Reverse Power Flow Criteria The Interconnection System (IS) shall prevent the occurrence of reverse power flow through the network protector(s) under all normal conditions and absolutely minimize reverse power flow under adverse conditions such that network protector capability is never impaired. There shall be at least two independent subsystems employed in the IS to accomplish this requirement. 10.3 Fault Current Contribution Criteria The IS will respond to any indication of a fault on the network by immediately* disconnecting the DG unit from the network so that the fault current contribution from the DG unit is either zero or minimized to the point of being inconsequential. 10.4 Area Network Load Flow Analysis and Conclusion The utility customer or the customer’s agent will work with the utility to analyze network load flow parameters at the proposed DG site to determine whether the proposed type of DG unit can be accommodated for operation. If the conclusion is negative, alternative measures such as reconfiguration for a radial interconnection shall be evaluated. _________________ * Immediately is defined for present purposes as within 3 cycles (50 milliseconds). P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 8 (Missing Pages 10 – 13) Proposed Draft Outline Revisions -- J. Bzura P1547.6 Meeting Las Vegas, NV; August 3–4, 2006 Slide 1 2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10 7. Overview of Network Distribution Systems: Design, Components and Operation (Joe Koepfinger, Bob Peterson, Martin Baier, Dave Costyk, Jim Daley, Betty Tobin ) 8. Primary Concerns of Operating DR on Networks (Moh Vaziri, Jim Watts, F. Bigenho, Tim Wall, Dan Sammon, Chuck Whitaker, Travis Johnson, David Smith, other volunteers) 9. Fundamental Requirements for Interconnection of DR on Networks (John Bzura …, Murray Davis, Martin Baier, Jim Daley, Jock Moffat, David Beach, Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely) 10. Procedures to Alleviate Concerns of Operating DR on Networks (Murray Davis, Jim Daley, Jock Moffat, John Bzura, Marty Baier, David Beach, Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely, others) 8/06 P1547.6 MTG J. J. BZURA 1 Slide 2 2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10 7. Overview of Network Distribution Systems: Design, Components and Operation (Joe Koepfinger, Bob Peterson, Martin Baier, Dave Costyk, Jim Daley, Betty Tobin ) 7.1 Spot Networks 7.2 Area Networks 8. Primary Concerns of Operating DR on Networks (Moh Vaziri, Jim Watts, F. Bigenho, Tim Wall, Dan Sammon, Chuck Whitaker, Travis Johnson, David Smith, other volunteers) 8.1 Reverse power flow 8.2 Fault current contributions 8.3 Effects of DR on area network load flows 8.4 Effects of potential network system component failures 8/06 P1547.6 MTG J. J. BZURA P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 2 9 Slide 3 2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10 9. Fundamental Requirements for Interconnection of DR on Networks (John Bzura …, Murray Davis, Martin Baier, Jim Daley, Jock Moffat, David Beach, Moh Vaziri, Sam McAllister, M. Ebrahim, Tom Greely) 9.1 Separation Requirement 9.2 Prohibition of Reverse Power Flow 9.3 Fault Current Contribution Limit 9.4 Determination of DR Interconnection Feasibility 8/06 P1547.6 MTG J. J. BZURA 3 Slide 4 2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10 10. Procedures to Alleviate Concerns of Operating DR on Networks (Murray Davis, Jim Daley, Jock Moffat, John Bzura, Marty Baier, David Beach, Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely, others) 10.1 Measures to sense and limit reverse power flow 10.1.1 Minimum power level DR trip 10.1.2 Reverse power flow sensing for DR trip 10.2 Fault current minimization 10.2.1 Limitation by DR technology 10.2.2 Limitation by switching technology 10.3 Site-specific analysis of DR on area networks (Moh V to lead?) 10.4 Coordination of DR with network operations (Murray D to lead?) 8/06 P1547.6 MTG J. J. BZURA P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 4 10 Slide 5 2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10 9.1 Separation Requirement On the detection of any anomaly in the network voltage, frequency or power flow direction, the Interconnection System (IS)* shall separate the DR unit from the network within 3 cycles.** 9.2 Prohibition of Reverse Power Flow The IS shall prevent the occurrence of reverse power flow through any network protector under all normal conditions of voltage and frequency. There shall be at least two independent subsystems within the IS to accomplish this requirement. Optional sentence – During abnormal conditions, reverse power flow shall be limited to X% of the network protector rating and be curtailed within 3 cycles.** *The Interconnection System (IS) is defined as a protective relay and control scheme designed to allow operation of a DR unit in parallel with a network grid. ** The exact number is open for discussion. 8/06 P1547.6 MTG J. J. BZURA 5 Slide 6 2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10 9.3 Fault Current Contribution Limit During a fault on the network, the IS shall limit the initial fault current contribution from the DR unit to Y%** of the normal network protector rating, and be curtailed within 3 cycles.** For network protector circuits already at 100% of calculated fault current capacity, the DR fault current contribution shall be 0%. *The Interconnection System (IS) is defined as a protective relay and control scheme designed to allow operation of a DR unit in parallel with a network grid. ** The exact number is open for discussion. 8/06 P1547.6 MTG J. J. BZURA P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 6 11 Slide 7 2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10 9.4 Determination of DR Interconnection Feasibility The utility customer or the customer’s agent will work with the utility to analyze network load flow parameters at the proposed DR site to determine whether the proposed type of DR unit can be accommodated for operation. If the conclusion is negative, alternative measures such as reconfiguration for a radial interconnection shall be evaluated. 8/06 P1547.6 MTG J. J. BZURA P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 7 12 ANNEX C: P1547.6 CLAUSE 7 PRE-BREAKOUT STATUS REPORT P1547.6 – proposed Clause 7 “Overview of Network Distribution Systems: Design, Components and Operation. Initial draft by Bob Peterson with comments by Joe Koepfinger and responses by Bob. [email protected] [mailto:[email protected]] ----------------------- --------------------------------- ------------------------------------ An Overview of Network Distribution Systems: Design, Components and Operation Background Discussion: Low voltgage alternating current networks were first developed in the 1920’s to provide highly reliable electric service to concentrated load centers mainly in the downtown areas of major cities. There are two types of low voltage networks, the secondary network (also referred to as an area network, grid network or street network) and the spot network. For the purpose of this guide secondary network will be referred to as a grid network. A minimum of two primary feeders are required to supply a network, The number of feeder to a network is dependent upon load requirement of the grid network or the spot network load. The grid network may consist of more that one area that are operated independently from each other. Several separate grids can be used to form the low voltage network within a city. Customers in a low voltage network area are typically take service from the network at the grids voltage level. In some cases large buildings may have a separate service not connected to the grid, this are called spot networks High reliability is achieved by designing the system to carry full load with n-1 primary feeder out of service and by rapidly removing any faulted primary feeder or transformer connection to the low voltage network. NETWORK TRANSFORMERS: Network transformers are typically liquied filled and air cooled, although some dry type network transformers have been used. Historically they were filled with a fluid that contained PCB’s continued use of such transformer is required by regulations to have lower thatn 100 ppm PCB, In most cases the coolant has a low flammability but newer units can be strictly mineral oil or be silicone filled. Newer vegetable oil based coolant with low flammability show promise for use in network transformers. (1. Joe: As I remember it wasn’t necessary to remove or retrofil the 120/208 Volt PCB filled network transformers. I think all you had to do was set-up a monitoring program for the transformers. At ComEd we chose to replace the 120/208 volt transformers and perhaps so did everyone else.) The network transformer may have a manually operated primary oil switch located directly on the transformer, which can be in the closed, opened or grounded position The network transformer is equipped network protector (explained later) mounted directly on the transformer P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 13 or mounted within close proximity of the transformer. In this latter case it is cable connected to the transformer. . Typical network transformer secondary voltages are 120/208Y and 277/480Y volts. The primary of the network transformer my be connected either in delta or ungrounded wye. The secondary of the network transformer is usually connected ground wye. to supply 120/208Y or 277/480Y voltage to the grid network or the spot network customer. (2. Joe: You mentioned ungrounded wye. We had some that were connected grounded wye. Might be worth asking how the other utilities with wye network transformers run them.) SPOT NETWORKS: A spot network consists of two or more network transformers connected by a common bus at a single location, such as in the basement of a building. In normal operation, all the spot’s network transformers will be feeding the bus simultaneously, from their respective primary feeders. The building may have additional spot networks on upper floors, but there is no connection between the vaults on the secondary side. Spot networks are installed with secondary voltages of 120/208volts and 277/480 volts. “PICTURE OF A SPOT NETWORK” In order that the spot network can continue to operate if a primary feeder becomes faulted, each network transformers is equipped with a network protector containing a low-voltage circuit breaker,and a protective package. The protective package includes a network relay or master relay that is sensitive to directional real and reactive power flo. It senses the reverse flow through the transformer for feeder fault or flow due to ythe feeder changing current or transformer magnetizing current. This protection operates to cause the network breaker to open and isolate the initiating condition. The network relay is a very sensitive reverse-power relay, with a pickup level on the order of 1 to 2 kW. It is the mission of the reverse power relay to be capable of sensing reverse power flow with no other feeder loads than the core losses of its own network transformer (With delta primary network transformers, little to no fault current will flow for a primary phase to ground fault.). Network protectors by themselves do not contain any forward looking over current protection. In many cases fuses are installed in series with the network protector. This fuse is sized well above the capability of one transformer and will have limit capability to operate for arcing type faults that are the most common in the network vault. It will operate for a bolted three phase fault within the vault. Multiple sets of secondary cables are typically installed between the network protector and the collector bus. These may be protected with inline fuses called cable limiters on each end, such that cable faults are isolated by the limiters. Limiters may also be installed on the service cables going to the customer’s switchgear. The primary pjurpoes of a limiter is to protected the conductors of a cable from thermal damage. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 14 (3. Joe: I don’t recall that cable limters provided cable overload protection. In the old Westinghouse T&D book it stated that limiters are installed to isolate cable faults and to protect the cable insulation from damage from the fault current.) The master relay also has another function, which is to supervise the closing of the network protector. The relay looks at the voltage on both side of the protector and if the transformer side is higher than the bus side (by perhaps 1 volt) the first close criteria is met. Next the phasing relay looks for the proper phase rotation between the two voltages before allowing the protector to close. Closing will occur if the two voltages are basically in phase with one another. A spot network is supplied by two or more primary distribution circuits, from a single substation and single bus section or multiple bus sections with closed bus ties. Occasionally feeders from separate substations have been used, but the flow of circulating currents between substations can result in excessive protector operations (Especially at light load). Primary feeders at the substation typically will have time-overcurrent phase and ground protection to see faults on the circuit. They may have an instantaneous ground element set to see faults on the primary side of the network transformer. Delta – wye connection of the network transformers limit the reach of the ground relays on one primary network feeder from seeing ground faults on the primary of another primary network feeder and over-tripping. Typically the substation relaying will not see faults on the secondary side of the transformer and considerable damage has occurred in vaults before any of the protection operates. “IEEE Guide for the Protection of Network Transformers” C37.108 goes into much more sophisticated schemes of protection, but is beyond the scope of this short discussion on networks. SECONDARY NETWORK GRIDS: A network grid could be thought of as several spot networks tied together with secondary cables. The low voltage cables may have customer service cables connected in manholes between the network transformer vaults. With a secondary network grid, it isn’t always necessary to put a minimum of two transformers in a vault, as the secondary cables (fed by network transformers connected to alternate primary circuits) can supply the load for a transformer or primary feeder outage. Transformers are located at various locations throughout the grid to supply power and support the grid voltage as required per studies. The same transformers and network protectors are used here as with Spot networks. Secondary grid networks are typically 120/208 volts although some 277/480 volts systems were developed. Secondary grids typically have multiple sets of secondary cables per phase running between network transformers” secondary. These cables can have inline fuses (Cable limiters) installed at each end to isolate a faulted cable and provide thermal overload protection for the cables without interrupting customers or the grid. If limiters are not present or the limiters don’t function the cables will burn clear for a fault. The number of sets of low-voltage cables installed is determined by performing load flow studies both under normal and emergency conditions to avoid conditions that would result in overload conditions for both normal and emergency conditions. Emergency condition are passed on planning criteria established by the Area EPS. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 15 (4. Joe: With paper lead cable our old philosophy for 120/208Volts was not to have limiters installed and to let the cable burn the fault clear. The old Westinghouse T&D book stated that limiters were developed and first applied in New York City in 1936. It also stated that with paper lead cable faults will burn clear if there is sufficient fault current. We install limiters when the cable is replaced with plastic insulated cables. The Westinghouse book also states that at 480 volts the cable may not burn clear and that limiters should be installed.) “PICTURE OF A GRID NETWORK” Different planning strategies may exist for a secondary grid network, but a typical scenario would be to allow for one primary circuit to be out of service (faulted) at peak load times and two primary circuits to be out of service (one for maintenance with a subsequent fault occurring on another) at non-peak times. Load flows must be run for all these scenarios, to insure customers receive adequate voltage and no equipment is overloaded. With the criteria stated above, the minimum number of feeders required for a network grid system is three but systems with more than 20 feeders exist. If the primary feeders come from different bus sections at a substation or different substations, a bus outage that can take out two or more network feeders must be considered in the load flows to see that a single contingency such as this does not cause network problems. It might be thought that utilities have instant access to loads and load flow directions as well as voltages on the grid. At most utilities this is not the case. The utility typically only has access to peak loads that occurred at the network center without any time stamp and customer peak demands, with or without time of day depending on the size. Periodic voltage measurements are made on the grid, but may not correspond to when specific load data was extracted. The utility also has substation loads for the primary feeders that are part of the grid. From this type of data the utility engineer is expected to run a load flow and plan secondary network grid upgrades. Without proper monitoring, distributed generation will lend another item of uncertainty in planning the grid. It will also complicate the running of load flows. Each load flow scenario must be run with the generator on and the generator off, as the utility has no control of forced DG outages. OPERATION: Normal operation of the grid would be to have the entire network feeders closed, all the network protectors closed, and all the secondary cables in service at both peak and light load times. While this is the preferred method of operation, secondary cable faults can occur at any time, which will be cleared by limiters or burn clear. These faulted cables will not be detected until a physical inspection of the grid is performed. Network protectors can be out of service for maintenance, a primary feeder fault or a failure of the protector to close (Typically a burned out close motor). A protector that failed in the open position will again not be detected until a physical inspection is performed, unless the protectors are supervised. A primary feeder can trip open due to a fault and this will cause all the protectors connected to that feeder to open. If P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 16 SCADA is present at the substation this would be detected immediately, but if SCADA is not present and the feeder serves only network load, this would not be detected until a physical inspection of the substation is performed. All of these possible abnormal conditions that can occur during normal operation of networks (Spot or Grid) make applying generation difficult. Network feeders are radial feeders that normally do not have ties on the primary to other feeders. Typically there are sectionalizing switches installed on the network feeders supplying network transformeres. If a fault occurs on a network feeder, the feeder will be out of service until the fault is located and repaird. Prior to repair, the protectors would be verified open and if present, the transformer primary switches put into the grounded position. This can be a lengthy process that distributed generation could make longer. (5. Joe: You changed the above to say there are sectionalizing switches in network grids. I don’t think typically this is the case. The only switches are on the network transformers themselves. The network feeders cannot be split up and re-livened, at least at ComEd without cutting the cable. Perhaps others have installed switches to be able to break up the feeder. This is one that the group could provide input on.) If an entire grid goes down it can be a lengthy process to get it restored. Typically there are no switches on the secondary cables in the grid. It may be necessary to make secondary cable cuts or unbolt secondary cables from buses to start picking up the grid in pieces. In some cases it may be possible to do a simultaneous group close of all the feeders in the grid (If they come from the same substation). P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 17 1 How does the DR provide Network Transformer protection function normally provided by the feeder’s protective relay? 2 What kind of communication is necessary between the protectors and the DR? X X 3 How might the DR cause false tripping of the protectors? X X 4 How might the DR prevent proper Opening protectors? X X 5 How might the DR prevent proper closing protectors? X X X P1547.6 Meetings for August 3-4, 2006 Working Group Meeting Technology Dependent Primary Fed Grid Issue Spot APPENDIX D: P1547.6 CLAUSE 8 PRE-BREAKOUT STATUS REPORT Area Protection/ Coordination DR Impact on Network equipment/operatio n DR Impact on Network equipment/operatio n DR Impact on Network equipment/operatio n DR Impact on Network equipment/operatio n Comments Potential Solutions DR connected to the Primary would be handled like any radial connected DR. Unclear what else this might address Possibly NP status via monitoring system, Also status of network transformer with open protector (energized or de-energized) Exporting across the NP; VAR swings? Var swings would have impact primarily if the watt-var trip characteristic is used in the NWP’s. Min impact with watt trip characteristic. Not sure how to cause this. If timedelay trip is added due to DR, and SLG fault on HV feeder, NWP tripping would be unnecessarily delayed for SLG fault Minimum import (Spot), limit DR capacity(Grid) Need to understand load levels necessary for proper closing Reduce network Xformer size, minimum import (spot), In Spot nwks, use circle rather than straight line close characteristic) DR capacity (grid) Testing Issue 18 Technology Dependent Primary Fed Comments DR Impact on Network equipment/operatio n DR Impact on Network equipment/operatio n DR Impact on Network equipment/operatio n If DR forms an island by opening of all NWP’s in a spot, the NWP interrupting capability may be exceeded. Grid Area Spot Issue Will any Network equipment be overstressed (Fault) due to the DR interconnection? X X 7 Will any Network equipment be over loaded (normal current) due to the DR interconnection? X X X 8 What effects will the DR have on the Network Protector relays, and what are the new relay setting criteria? What are impacts of increased time delay for low level rev power setting How will the presence of the DR affect the protectors’ response to faults outside of their protection zones? (e.g. response to adjacent feeder fault, AFF) Is the operation of a single-phase overcurrent device (protector fuse) a concern with the presence of DR? X X X X X DR Impact on Network equipment/operatio n DR requires addition of time delay tripping at low reverse powers, that otherwise would not be required. Test to determine potential impacts of delay May allow SLG fault to propagate into a three-phase fault In normal spot nwk, protection zone of NWP is from the LV terminals of the Nwk Xfr back to the primary feeder breaker. Should have minimal impact. X X DR Impact on Network equipment/operatio n Does not appear to be an issue. With one NWP fuse blown and balanced load conditions in two good phases, current for trip increases by 50 % with MNPR & MPCV Nwk relays 6 9 10 P1547.6 Meetings for August 3-4, 2006 Working Group Meeting X Potential Solutions Limit DR or replace overstressed equipment Install relaying and control to prevent formation of island. Not necessarily a “network” Limit DR or replace over issue loaded equipment See Feero report for possible relay settings. Requires replacing electro mechanical relays in NWP with microprocessor relays. Consider low level rev power time delays (similar to requirement for regn braking of elevators) 19 What conditions must be satisfied before paralleling is allowed? What will be the paralleling procedure? X X 12 Will a dedicated transformer for the DR be required? X X 13 How do requirements vary with the number of Network Transformers (eg. Dozens to hundreds spread out over a wide area? X 14 Will addition of DR impact arc detection (ozone, heat/smoke/flash)? Will requirements be different for 208 volt grid nwks, 208-V spot nwks, 480 volt spot networks, and 480-V grid nwks because of the different arcing characteristics? How are the arcing characteristics different? X Technology Dependent Grid 11 Primary Fed Spot Issue Area Comments X DR Paralleling requirements Minimum import (across NP), Sufficient NP’s closed, Sync tolerances met. Paralleling vs synchronization. Are different Sync tolerances required? Are NWP’s equipped with time delay trip if momentary reverse power during synchronization X DR Requirements Does not appear to be an issue (not a networkspecific issue) X Network configuration Does not appear to be an issue In spots, with the >50 % closed rule, utility may have more flexibility in large spots. With large spots, control & monitoring more complex X Network Configuration Testing needed to define issue. Some utilities have installed ground-fault protection schemes in 480volt spot networks. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting X Potential Solutions Micro processor relays on NWP, PLC or equivalent for monitoring and control, communication link between NWPs and DR More xformers could ease the requirements 20 15 Will the presence of, or lack of, Cable Limiters on the secondary cables result in different DR interconnection requirements? 16 17 (combined with 13) Will changes in power flow over the daily or weekly load cycle result in protector Cycling at a point remote from the DR’s PCC? Will different protection requirements apply to Network systems supplied from three-wire and four-wire primaries? With delta-wye or wyewye transformers? 18 X X X X P1547.6 Meetings for August 3-4, 2006 Working Group Meeting X Network Configuration Not aware of any different needs. Could have a big impact when considering DR on grid nwks. If utility does not know limiter status, secondary ties believed closed could be open Network Configuration If nwk fdrs come from same electric bus in sub, DR on spot nwks reduces load on primary feeders which should reduce angular differences between feeders (a positive). Network line configuration Nwk Xfr winding connection affects backfeed to ground faults on HV feeder with feeder breaker open,. If ground fault relaying used in 480volt spot networks, may affect relaying. With YY nwk xfrs, ground relay for primary feeder can not be set as sensitive as with Δ Y network transformers Better monitor status of limiters in grid type networks. Different relay settings and coordination 21 19 20 How will the protector be prevented from isolating distributed resources from the utility system? if the DR islands, will the Network Protector relay tolerate 180 deg out of phase voltage? If the DR islands, how will the Network master (/phasing?) relay be prevented from reclosing the protector switch during an out-ofsynchronism condition? X What would be an acceptable ratio of the minimum customer load current over the maximum DR output to eliminate any possibility of reverse power through a protector? X X X X Protector breakers are not designed to interrupt fault current from generators or withstand out-ofphase conditions across the open switch. Nwk relays were never intended to operate in “nonsynchronized systems. X P1547.6 Meetings for August 3-4, 2006 Working Group Meeting Reverse power through Network Protector Another islanding problem 1) Test NP to see if it can withstand 180 It is known that if a NWP is open, and then a voltage of twice line-toground voltage is applied across its contacts, it can withstand this. This also applies to Nwk Relays. This occurs under crossed phases with Δ Y Nwk Xfrs. Question is whether it can interrupt when the normal frequency recovery voltage is 2.0 per unit Replace NP Anti islanding >50% NP closed requirement Limit DR capacity Minimum import Install relaying such that island can never form, This is the FIRST thing to test!!! (see 3) Moh: I think a more reasonable criteria is “What must the net input from the spot be in per unit of the rating of one network transformer” This number is, I believe, a function of the number of units in the spot network. Then the difference between the DR output and the customer load at any load level must exceed this net import figure.. 22 21 What action needs to be taken with a sudden loss of large load with generation in operation? X X Reverse power through Network Protector Issue not understood Transient low load issue?, inadvertent export? Is this really a subset of 3? Time delay tripping of NWP, with sufficient time delay to allow other under power or reverse power relays time to disconnect the DG before NWP’s can trip Limit generator output such that dropping of largest load will maintain some minimum power import from the spot network 22 23 24 25 26 Can power swings or loss-ofsynchronism, loss of field by rotating generators cause reverse power through a Network Protector? Can insertion of customer PF caps cause reverse power through a Network Protector? X X X Reverse Power through Network Protector A testing issue X X X Reverse Power through Network Protector Testing issue (Moh) (Combined with 19) (Combined with 19) How can addition of DR contribute to or exacerbate cycling or pumping of NP X X X X X X P1547.6 Meetings for August 3-4, 2006 Working Group Meeting X Will have minimum impact on power flow in closed protectors. Can have significant impact on auto closing of NWP. From auto closing consideration, use in spot networks the circle rather than the straight line close characteristic in Nwk Relays. Needs testing; what constitutes “exacerbate”? Addition of DR can not improve stability of operation on NWP’s. May have no impact or negative impact, depending on particulars 23 27 28 29 Is there any fault detection (Phase or ground fault) required for DR? Should DR trip before NP? What equipment damage can occur due to increased time delay for low reverse power Modifications to Network equipment may be problematic and costly due to access limitations, equipment age, etc. X X X X X X Why? (MDGC issue) (MDGC issue) testing needed to determine impacts May result in SLG fault on primary feeder propagating into a multi-phase fault Addition of time delay tripping, control equipment, etc to allow application of DR can only result in a degradation of reliability because of the added complexity. However, quantifying this is not easy. X P1547.6 Meetings for August 3-4, 2006 Working Group Meeting Technology Dependent Grid Spot Issue Primary Fed 30 Area Comments Potential Solutions 24 31 32 3 How might the DR cause false tripping of the protectors? X X DR Impact on Network equipment/operatio n Exporting across the NP; VAR swings? Var swings would have impact primarily if the watt-var trip characteristic is used in the NWP’s. Min impact with watt trip characteristic. Minimum import (Spot), limit DR capacity(Grid) 5 How might the DR prevent proper closing protectors? X X DR Impact on Network equipment/operatio n Need to understand load levels necessary for proper closing 8 What effects will the DR have on the Network Protector relays, and what are the new relay setting criteria? What are impacts of increased time delay for low level rev power setting X X DR Impact on Network equipment/operatio n DR requires addition of time delay tripping at low reverse powers, that otherwise would not be required. Test to determine potential impacts of delay May allow SLG fault to propagate into a three-phase fault Reduce network Xformer size, minimum import (spot), In Spot nwks, use circle rather than straight line close characteristic) DR capacity (grid) Testing Issue See Feero report for possible relay settings. Requires replacing electro mechanical relays in NWP with microprocessor relays. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting X 25 20 What would be an acceptable ratio of the minimum customer load current over the maximum DR output to eliminate any possibility of reverse power through a protector? X 23 Can insertion of customer PF caps cause reverse power through a Network Protector? (See Issue 3) X 26 How can addition of DR contribute to or exacerbate cycling or pumping of NP X X X X P1547.6 Meetings for August 3-4, 2006 Working Group Meeting X X Reverse power through Network Protector This is the FIRST thing to test!!! (see 3) Reverse Power through Network Protector Testing issue (Moh) Moh: I think a more reasonable criteria is “What must the net import from the spot be in per unit of the rating of one network transformer” This number is, I believe, a function of the number of units in the spot network. Then the difference between the DR output and the customer load at any load level must exceed this net import figure.. Will have minimum impact on power flow in closed protectors. Can have significant impact on auto closing of NWP. From auto closing consideration, use in spot networks the circle rather than the straight line close characteristic in Nwk Relays. Needs testing; what constitutes “exacerbate”? Addition of DR can not improve stability of operation on NWP’s. May have no impact or negative impact, depending on particulars 26 APPENDIX E: P1547.6 CLAUSE 9 PRE-BREAKOUT STATUS REPORT 2nd REORGANIZATION OF P1547.6 - AREAS 7–10 7. Overview of Network Distribution Systems: Design, Components and Operation (Joe Koepfinger, Bob Peterson, Martin Baier, Dave Costyk, Jim Daley, Betty Tobin ) 7.1 Spot Networks 7.2 Area Networks 8. Primary Concerns of Operating DR on Networks (Moh Vaziri, Jim Watts, F. Bigenho, Tim Wall, Dan Sammon, Chuck Whitaker, Travis Johnson, David Smith, other volunteers) 8.1 Reverse power flow 8.2 Fault current contributions 8.3 Effects of DR on area network load flows 8.4 Effects of potential network system component failures 9. Fundamental Requirements for Interconnection of DR on Networks (John Bzura …, Murray Davis, Martin Baier, Jim Daley, Jock Moffat, David Beach, Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely) 9.1 Separation Requirement On the detection of any anomaly in the network voltage, frequency or power flow direction, the Interconnection System (IS)* shall separate the DR unit from the network within 3 cycles.** 9.2 Prohibition of Reverse Power Flow The IS shall prevent the occurrence of reverse power flow through any network protector under all normal conditions of voltage and frequency. There shall be at least two independent subsystems within the IS to accomplish this requirement. Optional sentence – During abnormal conditions, reverse power flow shall be limited to X% of the network protector rating and be curtailed within 3 cycles.** 9.3 Fault Current Contribution Limit During a fault on the network, the IS shall limit the initial fault current contribution from the DR unit to Y%** of the normal network protector rating, and be curtailed within 3 cycles.** For network protector circuits already at 100% of calculated fault current capacity, the DR fault current contribution shall be 0%. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 27 * The Interconnection System (IS) is defined as a protective relay and control scheme designed to allow operation of a DR unit in parallel with a network grid. ** The exact number is open for discussion. 9.4 Determination of DR Interconnection Feasibility The utility customer or the customer’s agent will work with the utility to analyze network load flow parameters at the proposed DR site to determine whether the proposed type of DR unit can be accommodated for operation. If the conclusion is negative, alternative measures such as reconfiguration for a radial interconnection shall be evaluated. 10. Procedures to Alleviate Concerns of Operating DR on Networks (Murray Davis, Jim Daley, Jock Moffat, John Bzura, Marty Baier, David Beach, Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely, others) 10.1 Measures to sense and limit reverse power flow 10.1.1 Minimum power level DR trip 10.1.2 Reverse power flow sensing for DR trip 10.2 Fault current minimization 10.2.1 Limitation by DR technology 10.2.2 Limitation by switching technology 10.3 Site-specific analysis of DR on area networks (Moh V to lead?) 10.4 Coordination of DR with network operations (Murray D to lead?) P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 28 APPENDIX F: P1547.6 CLAUSE 10 PRE-BREAKOUT STATUS REPORT (Old number 7.2.1.2.6 also this is prior write up minutes Feb 2006) (a) Secondary Grid Network Modifications for DR Interconnection Murray W. Davis 1. It is difficult to insure that reverse power flows, through the network protectors due to the DR generation, will not cause the network protectors to open. Typically, the network protector will open for reverse current of 5% or more of the network protector rating. If all the loads and all the generation is monitored on the grid, so that the generation never exceeds the load on the secondary grid then this could be an acceptable solution. 2. A network relay can determine the difference between reverse fault current from DR generation and reverse load current. The phase angles for fault currents are generally much greater than for load currents. Also, consideration must be given to the DR units causing high voltage during light load periods. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 29 7.2.1.2.6 (b) Secondary Spot Network What Does the Standard Say? 1. The connection of the DR’s to the Area EPS is only permitted if the Area EPS network bus is already energized by more than 50% of the installed network protectors. 2. The DR output shall not cause any cycling of network protectors. 3. The network equipment loading and fault interrupting capacity shall not be exceeded with the addition of DR’s. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 30 (c) Secondary Spot Network Modifications for DR Interconnection 1. The reverse power relay and breaker clearing time (i.e. sense time of the protective function and opening time of the interrupting device) is about 3 to 5 cycles. Some utilities have much longer clearing times, as much as 20 cycles, which allows more time for the reverse power relay (32) of the DR to operate at the PCC and thus prevent the network protector from opening. 2. Another solution is shown in Figure 1 where a separate generator and facility load bus are created with an additional breaker at the PCC including a (32) relay function. The breaker at the PCC opens under system fault conditions while the generator continues to serve the facility load. It should be noted that if three network protectors are serving load, two must be in service to meet more than the 50% criteria. The concern of the 50% rule above is the reduced reliability of the network if there is 50% or less of the network protectors remaining (considering protectors out of service for maintenance). P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 31 3. Another solution for installation of DR’s is shown in Figure 2. Here a new radial circuit serves the DR and facility load which allows for exporting power and alleviates the reverse power issue of directly connecting to the spot network. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 32 4. Another solution is given in Figure 3, where the network protector relays sense the reverse current under fault conditions and initiate a generator trip. Separate contacts are used in each reverse current relay to close and pick up the generator trip coil. “A” Contacts from each protector reverse current relay “A” PCC “G” Gen “b” 3 Protector tripping coil operates when gen. is offline and reverse current exists due to faults or normal network protector operation Figure 3. If the generator causes reverse power through the network protector under normal load conditions the reverse power relay (32) of the network protector causes one or more of the “A” contacts to close and trip the generator via “G” trip coil. If the reverse power condition is eliminated by tripping the generator breaker then there is no reverse power through the network protectors and same remain closed, thus avoiding a potential interruption. If the generator is operating when a fault occurs this causes reverse current through the network protector. The reverse current relay contacts “A” (not the main contacts of the network protector) close thus energizing the trip coil “G” of the generator breaker. This trip coil trips the generator breaker and isolates the DR from the network. Another option is to trip the breaker at the PCC which allows the generator to continue operating and serve facility load (if the capacity is large enough). It should be noted that the time delay tripping of the network protector may be required to permit resetting of the directional overcurrent relays to insure the relay contacts are open before the generator breaker auxiliary “b” contacts close. See Figure 3. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 33 5. Another solution is to use a Solid State Switch generator breaker to isolate the generator from the network protector secondary bus within 1/8 to ¼ of a cycle thus preventing the opening of the network protector (typically 5 cycles to open) for either normal reverse load current from the generator or reverse current due to a fault on the primary of the spot network. The sensing of reverse current for the solid state switch is typically on the load side of the interconnection breaker at the PCC of Figure 1., but the solid state switch is installed on the generator terminals, especially for multiple unit installations. 6. Finally, another solution is to install Fiber Optic communication links between any sensing point on the system and the generator breaker to cause a transfer trip when an abnormal system or generator output in excess of its local load condition occurs. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 34 APPENDIX G: BILL FEERO NETWORK INTERCONNECTIONS PRESENTATION Slide 1 MTC Proposed R&D to Advance DR/Network Interconnections Email [email protected] Suggested Advancements 1 Slide 2 Purpose • To advance the acceptability of DR on network service by encouraging changes in the network protector (NWP) relays and in the DR controls to react instantaneously to required switching conditions utilizing communications between the NWP relays and the DR controls. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 2 35 Slide 3 Approach • Held meetings with protector relay manufacturers, DR interface manufacturers, and utilities to determine what developments they feel are feasible and then, prepared a plan for a prototype demonstration project. Suggested Advancements 3 Slide 4 Observations • At present, grid interconnections of .1 to 2MW DR are not meeting widespread acceptance. The most obvious technical fix would require the installation of a gridwide, protection-speed communication and automatic adaptive control schemes. While conceptually feasible, the implementation cost appears to be well beyond any justification that can be envisioned. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 4 36 Slide 5 Observations (continued) • The prospect of developing Recommended Practice for spot network interconnections using presently available technology will hinge on achieving general acceptability of using NWP time delay tripping for low reverse power. Suggested Advancements 5 Slide 6 Observations (continued) • Techno-economic issues yet to be discussed are: 1.How to select the low reverse power setting for various types of DR; 2.Guidance on how to select the minimum necessary time delay to avoid false tripping of the NWPs; 3.DR size restrictions; and 4.Cautions on using the time delay technique, e.g., evolving faults and cross town faults. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 6 37 Slide 7 Observations (continued) • Techno-legal issues yet to be discussed are: • De facto giving reverse power tripping control to a non-utility entity when the DR or facilitator owns and maintains the circuits which determine when a network underpower limit has been reached. • Mitigating this exposure to a non-utility protective function failure by limiting the size of the DR that can be interconnected to less than the minimum spot network load. Suggested Advancements 7 Slide 8 Concerns of Many Utilities • Salient concerns expressed by many utilities are: • 1. The determination of abnormal system conditions on the utility system that would require network protector action or non-action absent DR interconnections should be controlled and maintained by the utility. • 2. Adding intentional time delay to provide coordination time intervals between independently acting relays (utility’s and DR’s) may adversely impact the utility system. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 8 38 Slide 9 Present DR Interconnecting Using a NWP Relay with Low Reverse Power Time Delay from Baier, Feero, Smith 2003 T&D Conference Paper Suggested Advancements 9 Slide 10 Required Advancements to Mitigate these Concerns • To alleviate concern #1, a suggested solution is a NWP microprocessor relay capable of providing: • A means of computing the power import by each protector and sending a trip signal to the DR (or to a vault control unit -later slide) if the imported power dropped below a selectable level such as 6% of the transformer’s rating. To prevent cycling of the DR, this relay should also have an over power setting to be exceeded before the DR could be connected online. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 10 39 Slide 11 Required Trip of the DR • Presently Required Trip (RT) of the DR is not Initiated by the NWP Relay. • In some cases the DR Interface Unit attempts to determine the Required Trip at its terminals. • More generally the Required Trip is determined at a summing point off the network bus in the customer’s facility. • Depending on the location of the summing point, the sensing relay is either a reverse power relay or a under power relay. Suggested Advancements 11 Slide 12 Operating Time of the NWP Relay in seconds The Suggested NWP Relay Conceptual Characteristic 0.75-- Network Protector Open 0.50 -- 0.25 -- Load Current in the NWP Zone of NWP Time Delay before Opening Reverse Current in the NWP DR DR RT Instantaneous Zone Trip Threshold Network Protector Closed Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 12 40 Slide 13 Required Advancements to Mitigate these Concerns – (continued) Vault Control Unit For spot networks with more than two transformers, an individual protector relay’s call for trip would have to be modified by some form of instantaneous acting AND circuit to only trip the DRs when 50% or more of the protectors required a DR trip Suggested Advancements 13 Slide 14 Black Box Conceptual Arrangement 13.8 kV Bus NWP#1 NWP#2 RT NWP#3 RT Black Box that Determines if 50% of the Protectors are open NWP#4 NWP#5 NWP#6 RT RequiredTrip command Line 480 volt bus Building Main Breaker DR Control Lines Load Trip Co mmands Load DR Controller 480/208 Volt Transformer Synchronous Generator Induction Generator Roof PV Array Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 14 41 Slide 15 Required Advancements to Mitigate these Concerns – (continued) • Concern #2 For utilities who do not wish to set any intentional time delay, a network relay system that could issue a DR trip command and then trip itself, if required, after receiving a confirmation signal that the DR had tripped-- a form of permissive tripping. This ability will also require some development by the DR manufacturers. Suggested Advancements 15 Slide 16 Operating Time of the NWP Relay in seconds NWP Relay Utilizing Permissive Trip Scheme 0.75-- Network Protector Open 0.50 -- 0.25 -- Delay Waiting on DR Trip Load Current in the NWP Reverse Current in the NWP DR DR RT Instantaneous Zone Trip Threshold Network Protector Closed Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 16 42 Slide 17 Conceptual Permissive Trip Circuit 13.8 kV Bus NWP#1 NWP#2 NWP#3 RT RT Black Box that Determines if 50% of the Protectors are open NWP#4 NWP#5 NWP#6 RT RequiredTrip command Line 480 volt bus Trip Completed Circuit mmands DR Control Lines Load Trip Co Building Main Breaker Load DR Controller 480/208 Volt Transformer Synchronous Generator Induction Generator Roof PV Array Suggested Advancements 17 Slide 18 Required Advancements to Mitigate these Concerns – (continued) • A variation might be to block any network protector tripping if all network protector reverse power relays were calling for a trip. The DR trip command would be sent and individual NWPs would be released to trip as soon as at least one unit’s power flow moved back into the import (non-trip) direction. This would guard against dumping the network bus for the adjacent feeder fault on the utility system when DRs are interconnected and yet not materially slow tripping for faults on one of the feeders supplying Suggested 18 the spot network. Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 43 Slide 19 Preliminary Discussions with both NWP Relay and DR Manufacturers • Discussed the concept of NWP relay centered control and the feasibility of receiving and sending trip communications between the NWP relay system and the DR interface system. • Reaction has generally been favorable and deemed not to be any significant technological hurdle. Suggested Advancements 19 Slide 20 Discussions with Select Utilities* • Three allow interconnections on Spot Networks by applying low reverse power time-delayed tripping. • Two do not allow time delay of the protector tripping and therefore have very few and small interconnections. • *Note some other utilities do allow PV systems small compared to loads on network systems. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 20 44 Slide 21 Discussions with Select Utilities(continued) • Of the three that allow interconnections: • One would like a better way that would increase reliability and reduce pre-engineering time. • One has not worried about it lately because of little interconnection activity • One has a form of Vault Control Unit and sets DR size limits that, with time delay, solves any problems of importance to the utility Suggested Advancements 21 Slide 22 Consider a Large Spot Network 13.8 kV Bus NWP#1 NWP#2 NWP#3 Trip command Line NWP#4 NWP#5 NWP#6 480 volt bus Under Power Detection Building Main Breaker DR Control Lines Induction Generator Load Load DR Controller Owned and Operated by the Customer Vault Control Unit Determines if 50% of the Protectors are open Current limiter 480/208 Volt Transformer Roof PV Array Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting Synchronous Generator 22 45 Slide 23 One Utility’s Approach • Spot Networks are designed to an N-2 criteria, so for a 10 MVA max load they would install six 2.5 MVA units. • The minimum network import permitted would be 1 MVA for such a spot or 167 KVA per unit. • With a 6% minimum criteria, they have reasonable margin even with 20% unbalance. • Max DR MVA allowed <minimum load MVA1MVA. Suggested Advancements 23 Slide 24 The Tie-line Control Approach • Requires: – Low Reverse Power Time Delay of NWPs which is long enough for tie-line corrections. – A Vault Control Unit to determine when 50% of the protectors are open. – DR size limited to less than minimum load or customer maintenance of a tie-line control which meets or exceeds local utility quality and maintenance practice. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 24 46 Slide 25 Tie-line Control Works, BUT • The use of time delay increases the utility’s exposure to additional fault damage, at the point of fault or cross town, i.e., other phase remote. • It relies on good maintenance by the customer or – DR rated output restrictions at initial installation, and, – Future awareness of any drop in minimum load. – In the event of a reduced minimum load, network reliability is only as good as the tie-line control’s reliability. Suggested Advancements 25 Slide 26 Next Steps • The Massachusetts Technology Collaborative, MTC, has developed and posted on its web site an RFP for these suggested NWP relay developments that might be possible by the responding team(s). A team would likely consist of a relay manufacturer, a utility, and at least one DR manufacturer. • www.masstech.org/dg/collab.reports.htm • Attachment F: Relaying and Control Technology Development for Spot Networks. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 26 47 Slide 27 GOALS OF MTC’s RFP • To advance the acceptability of DG on network service by encouraging changes in the network protector (NWP) relays and in the DG controls to react instantaneously to required switching conditions utilizing communications between the NWP relays and the DG controls. Suggested Advancements 27 Slide 28 GOALS OF MTC’s RFP (continued) • Encourage protector relay manufacturers, DG interface manufacturers, and utilities to determine what developments they feel are feasible, develop a prototype relaying and control system, and prepare a plan for a prototype demonstration project on a spot network test bed. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 28 48 Slide 29 GOALS OF MTC’s RFP (continued) • Increase the acceptability of DG interconnection with network service by utilities by assuring that all conditions that can cause protector operations are controlled by utility owned and maintained relays and controls. • Decrease the complexity and site-specific variability for DG suppliers in designing network interconnection systems. Suggested Advancements 29 Slide 30 GOALS OF MTC’s RFP (continued) • Advance communication and control exchanges between network protectors and DG to achieve high levels of security while increasing operating range flexibility. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 30 49 Slide 31 Conclusions • The relay advancements that are suggested in this presentation are an attempt to offer tools to utilities who don’t permit time delays and won’t accept customer controls that can impact their network’s reliability. • The functions that could be performed in the suggested relay development and the ability to deal with two-way communications will also be a key step in resolving the grid interconnection issue. Suggested Advancements P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 31 50 ANNEX H: P1547.6 CLAUSE 7 POST-BREAKOUT STATUS REPORT P1547.6 – proposed Clause 7 “Overview of Network Distribution Sysytems: Design, Components and Operation. ----------------------- --------------------------------- ------------------------------------ An Overview of Network Distribution Systems: Design, Components and Operation Background Discussion: Low voltage alternating current networks were first developed in the 1920’s to provide highly reliable electric service to concentrated load centers mainly in the downtown areas of major cities. There are two types of low voltage networks, the secondary network (also referred to as an area network, grid network or street network) and the spot network. For the purpose of this guide secondary network will be referred to as a grid network. A minimum of two primary feeders are required to supply a network, The number of feeders to a network is dependent upon load requirement of the grid network or the spot network load. The grid network may consist of more that one area that are operated independently from each other with in a city Customers in a low voltage network area typically take service from the network at the grids voltage level. A spot network supplies grid like service to a particular customer installation to achieve, high level of reliability and is designed to carry full load with a minimum of n-1 primary feeder out of service. To achieve high reliability faulted primary feeder or transformer connection to the low voltage network are isolated within a few cycles. NETWORK TRANSFORMERS: Network transformers are typically liquid filled and air cooled, although some dry type network transformers have been used. Historically they were filled with a fluid that contained PCB’s continued use of such transformer is required by regulations to have a low PCB content or comply with the applicable environmental regulations. In most cases the coolant has a low flammability Newer vegetable oil based coolant with low flammability show promise for use in network transformers. In some cases, mineral oiled filled transformer have been used. However use of this filling material maybe subject to acceptance by local authorities. The network transformer may have a manually operated primary oil switch located directly on the transformer, which can be in the closed, opened or grounded position The network transformer is equipped with a network protector) mounted directly on the transformer or mounted within close proximity of the transformer. In this latter case it is cable connected to the transformer. . Typical network transformer secondary voltages are 120/208Y, 125/216Y, and 277/480Y volts. The primary of the network transformer my be connected either in delta or grounded wye. The secondary of the network transformer is usually connected ground wye. to supply 120/208Y or 277/480Y voltage to the grid network or the spot network customer. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 51 SPOT NETWORKS: A spot network consists of two or more network transformers connected by a common bus low voltage side at a single location. Each network transformer and protector for the spot may be located in a separate vault below the sidewalk or street, with the parallel connections on the LV side made in a separate bus hole or compartment. With this arrangement, the equipment is in a harsh environment, which may be frequently submersed, complicating the interfacing with other control equipment. In normal operation, all the spot’s network transformers will be feeding the bus simultaneously, from their respective primary feeders. The building may have additional spot networks on upper floors, but there is no connection between the vaults on the secondary side. Spot networks are installed with secondary voltages of 120/208volts and 277/480 volts. “PICTURE OF A SPOT NETWORK” FIGJURE 1 SPOT NETWORK In order that the spot network can continue to operate if a primary feeder becomes faulted, each network transformers is equipped with a network protector containing a low-voltage circuit breaker, and a protective package. The protective package includes a network relay or master relay that is sensitive to directional real and reactive power flow. It senses the reverse flow through the transformer for feeder faults or flow due to the feeder charging current or transformer magnetizing current. This protection operates to cause the network breaker to open and isolate the initiating condition. The network relay is a very sensitive reverse-power relay, with a pickup level on the order of 1 to 2 kW. It is the mission of the reverse power relay to be capable of sensing reverse power flow with no other feeder loads than the core losses of its own network transformer (With delta primary network transformers, little to no fault current will flow for a primary phase to ground fault.). It should be noted that with low-loss network transformers and the reverse current trip setting used by some utilities, the network protector will not trip on just the core losses of the transformer to which it is connected. However, this does not mean that the protector will not open when the feeder breaker is opened in absence of a fault, or with a SLG fault on the primary feeder. Under these conditions, there are circulating flows between closed protectors due to difference in voltages throughout the network. Also, when a protector opens, the core losses of its transformer are supplied from those protectors that are still closed. The last protector to open is supplying the core losses of all network transformers on the feeder. Network protectors by themselves do not contain any forward looking over current protection. In many cases fuses are installed in series with the network protector. This fuse is sized well above the capability of one transformer and will have limited capability to operate for arcing type faults that are the most common in the network vault. It will operate for a bolted three phase fault within the vault. The main purpose of the network protector fuse is to act as a backup to the network protector for a fault on the primary feeder in the event the network protector fails to open for the fault on the primary feeder. This could be due to a network relay or network protector malfunction. Further, under this backfeed condition the fuse is to provide through fault protection to the back feeding network transformer. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 52 Multiple sets of secondary cables are typically installed between the network protector and the collector bus. These may be protected with inline fuses called cable limiters on each end, such that cable faults are isolated by the limiters. Limiters may also be installed on the service cables going to the customer’s switchgear. The primary purpoes of a limiter is to protected the insulation of the conductors from excessive thermal damage. The master relay has another function, which is to supervise the closing of the network protector. The relay looks at the voltage on both side of the protector and if the transformer side voltage higher than the bus side (by perhaps 1 volt) the first close criteria is met. The phasing relay looks at the angle between the phasing voltage (voltage across the open contacts of the protector – on just one phase with the electro-mechanical relays) and the network line-to-ground voltage. If the phasing voltage is leading the network line-to-ground voltage, or is not lagging by a large angle as determined by the setting of the phasing relay, the phasing relay will make its close contact. Basically, the phasing relay permits closing if the transformer side line-to-ground voltage is leading the network side line-to-ground voltage at the open protector. Currently electro mechanical master relay and phasing relay functions have been combined into a single relay, that may be either solid state or micro processor type relay.. Typically, a spot network is supplied by two or more primary distribution circuits, from a single substation and single bus section or multiple bus sections with closed bus ties. Occasionally feeders from separate substations have been used, but the flow of circulating currents between substations can result in excessive protector operations (Especially at light load). Primary feeders at the substation typically are protected by time-overcurrent phase and ground protection to see faults on the circuit. They may have an instantaneous ground element set to see faults on the primary side of the network transformer. Delta – wye connection of the network transformers limits the reach of the ground relays on one primary network feeder from seeing ground faults on the primary of another primary network feeder and over-tripping. Typically the substation relaying will not see faults on the secondary side of the network transformer and considerable damage has occurred in vaults before any of the protection operates for sustained faults in 480-volt network protectors. “IEEE Guide for the Protection of Network Transformers” C37.108 goes into much more sophisticated schemes of protection, but is beyond the scope of this short discussion on networks. SECONDARY GRID NETWORK: A grid network could be thought of as several spot networks tied together with secondary cables, sometimes called secondary mains or street ties. The low voltage cables may have customer service cables connected in manholes between the network transformer vaults. With a secondary network grid, it isn’t always necessary to put a minimum of two transformers in a vault, as the secondary cables (fed by network transformers connected to alternate primary circuits) can supply the load for a transformer or primary feeder outage. Network transformers are located at various locations throughout the grid to supply power and support the grid voltage as required per studies. The same transformers and network protectors are used here as with spot networks. Secondary grid networks are typically 120/208 volts although some 277/480 volts systems were developed. Secondary grids typically have multiple P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 53 sets of secondary cables per phase running between network transformers. These cables can have inline fuses (cable limiters) installed at each end to isolate a faulted cable and provide for high-current faults and thermal overload protection for the cables without interrupting customers or the grid. If limiters are not present or the limiters don’t function, the cables will burn clear for a fault a fault condition. The number of sets of low-voltage cables installed is determined by performing load flow studies both under normal and emergency conditions to avoid conditions that would result in overload conditions for both normal and emergency conditions. Emergency conditions are bassed on planning criteria established by the Area EPS. Since 480 volts cable may not burn clear limiters should be installed.)1 “PICTURE OF A GRID NETWORK” FIGURE 2 GRID NETWORK Different planning strategies may exist for a secondary grid network, but a typical scenario would be to allow for one primary circuit to be out of service (faulted) at peak load times and two primary circuits to be out of service (one for maintenance with a subsequent fault occurring on another) at non-peak times. Load flows studies must be run for all these scenarios, to insure customers receive adequate voltage and no equipment is overloaded. With the criteria stated above, the minimum number of feeders required for a network grid system is three but systems with more than 20 feeders exist. If the primary feeders come from different bus sections at a substation or different substations, a bus outage that can take out two or more network feeders must be considered in the load flows to see that a single contingency such as this does not cause network problems. Some substations for networks are designed such that a bus fault does not cause the loss of more than one primary feeder to a network. Shown below is a simplified one-line diagram of a substation for supply of three-six feeder networks. With this design, a bus fault, or fault in a bustie breaker results in a loss of just one primary feeder to each network. Other designs are available which provide similar performance for bus faults, and bus tie breaker faults. The effectiveness of the substation ground can have an influence on the possibility of sympthatic faults on non-faulted cables due to the rise in voltage on the unfaulted phase during the ground fault. 1 Westinghouse Distribution Book, P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 54 69 KV BUS 2000 AMP 69 KV LINE B 69 KV LINE C 69 KV LINE A 69 KV LINES ARE PIPE-TYPE CABLES 69 KV BREAKERS 3500 MVA IR XFR. # 1 XFR. #2 XFR. #3 NOTE: 3 OHM RESISTOR IN NEUTRAL OF EACH TRANSFORMER 11.5 KV BUS # 1 NWK 1 FDR 1 NWK 2 FDR 1 NWK 3 FDR 1 11.5 KV BUS # 2 NWK 1 FDR 2 NWK 2 FDR 2 NWK 3 FDR 2 11.5 KV BREAKERS ARE VACUUM 1000 MVA INTERRUPTING 11.5 KV BUS # 3 NWK 1 FDR 3 NWK 2 FDR 3 NWK 3 FDR 3 11.5 KV BUS # 5 NWK 1 FDR 5 11.5 KV BUS # 4 NWK 1 FDR 4 NWK 2 FDR 4 NWK 3 FDR 4 NWK 2 FDR 5 NWK 3 FDR 5 11.5 KV BUS # 6 NWK 1 FDR 6 NWK 2 FDR 6 NWK 3 FDR 6 FEEDER BREAKER CONTROLS ARRANGED TO PERMIT SIMULTANEOUS RECLOSING FOR EACH NETWORK NWK D 22, SUB 8.FCW FIGURE 3 TYPICAL NETWORK FEEDER SYSTEM It might be thought that utilities have instant access to loads and load flow directions as well as voltages on the grid. At most utilities this is not the case. The utility typically only has access to peak loads that occurred at the network center without any time stamp and customer peak demands, with or without time of day depending on the size. Periodic voltage measurements are made on the grid, but may not correspond to when specific load data was extracted. The utility also has substation loads for the primary feeders that are part of the grid. From this type of data the utility engineer is expected to run a load flow and plan secondary network grid upgrades. Without proper monitoring, distributed generation will lend another item of uncertainty in planning the grid. It will also complicate the running of load flows. Each load flow scenario must be run with the generator on and the generator off, as the utility has no control of forced DG outages. Further, load flows must be run with all feeders in service, as well as with each feeder out of service, and perhaps with any two feeders out of service (double contingency). If a P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 55 network has N feeders, and double contingency response is to be analyzed, the number of load flows to be run is N*(N-1)/2 if distributed generation is not accounted for. Including the distributed generation will add significantly to the number of case that must be considered. The detail of the load full case may be significantly impacted by the number of distributed resources connected to the grid. The results of these studies are use by the planning engineer to ascertain the impact of the distributed resources upon the grid operation and reliability OPERATION: Normal operation of the grid would be to have the entire network feeders closed, all the network protectors closed, and all the secondary cables in service at both peak and light load times. While this is the preferred method of operation, secondary cable faults can occur at any time, which will be cleared by limiters or burn clear. These faulted cables will not be detected until a physical inspection of the grid is performed, unless the loss results in a low-voltage complaint, or overloading of in-service cables with resultant smoking, fire, or other noticeable activity.. Network protectors can be out of service for maintenance, a primary feeder fault or a failure of the protector to close (Typically a burned out close motor). A protector that failed in the open position will again not be detected until a physical inspection is performed, unless the protectors are supervised. A primary feeder can trip open due to a fault and this will cause all the protectors connected to that feeder to open. If SCADA is present at the substation this would be detected immediately, but if SCADA is not present and the feeder serves only network load, this would not be detected until a physical inspection of the substation is performed. All of these possible abnormal conditions that can occur during normal operation of networks (Spot or Grid) make applying generation difficult. Network feeders are radial feeders that normally do not have ties on the primary to other feeders. Typically there are no sectionalizing switches installed on the network feeders supplying network transformers accept for the disconnect switch on the primary of the network transformer. If a fault occurs on a network feeder, the feeder will be out of service until the fault is located and repaird. Prior to repair, the protectors would be verified open and if the transformer primary switches are available they put into the grounded position. If an entire grid network (secondary) goes down it can be a lengthy process to get it restored. Typically there are no switches on the secondary cables in the grid. It may be necessary to make secondary cable cuts or unbolt secondary cables from buses to start picking up the grid in pieces. In some cases it may be possible to do a simultaneous group close of all the feeders in the grid. In addition the overcurrent protection setting have to consider the impact of the additional inrush current that is associated with an extended outage of the grid network. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 56 ANNEX I: P1547.6 CLAUSE 8 POST-BREAKOUT STATUS REPORT MO’s Notes Discussion of the 30 issues Issues Related to NP Tripping (opening) : George NSTAR discussed bus differential scheme that one customer installed. There are three schemes: bus differential, Fenwal and ABB arc guard. (Variety of different schemes being used by utilities) Bus differential may require an NEC variance (Jock) Make sure the NP is not the first device to trip, DG must come off first. Don’t want manhole covers to fly: therefore, delay is not recommended. Don’t want to introduce delay. The main concern with all these systems is arcing faults. (this maybe an existing problem exacerbated by addition of DG) Reduction of arc flash incident energy is a major concern. Jock discussed a system that will allow temporary settings while personnel are working in a vault. All time delays removed for this work period. Eaton asked to develop a system to accomplish this. Arc fault suppression and reduction is a concern. Asynchronous interrupting, Jock discussed Magnum breakers and their design. They will interrupt 100 kA, but may not achieve the number of operations desired (10,000). Mo – two spot network: low level reverse flow – is there a concern with the NP opening? Jock- this fault is limited by transformer impedance. Low until sub breaker opens, then the current is higher through the NP. with a delta high side, the DG does not see the phgnd fault. When wye-wye, the DG would see the fault. (For most cases, detection Phase/Ground faults on the utility system maybe difficult to accomplish by the DG. Transfer Trip or other schemes requiring communication maybe cost prohibitive with little/no added value! – Need to investigate further!) For faults on the station bus, ph-gnd fault, what happens? For low level faults, tripping of NP is not an issue. (Consensus) with or without DG being in parallel operation) P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 57 What assurance do we have that the customer’s system will be properly maintained and routinely tested to ensure tripping? Can the utility monitor customer’s relays, settings, status etc. periodically? (Maintenance Issue) How do we monitor the >50% closed status of the NPs? Trip signal sent to DG when 2 nd of three opens. What if the customer breaker doesn’t trip? Periodic testing is required. Monitoring is beneficial for status etc. George: often customer breakers don’t trip. They send letters periodically to advise customers to maintain their equipment. Reports are requested from customers. (Maintenance Issue) Monitoring at PLC is desired, in addition to breaker status. Time Delay concept: low level reverse feed, tripping is slow now. With differential scheme, there is little damage, but the trouble is hard to find. With the Fenwal, there is a burn making it easier to find. Contamination is an issue when burning takes place. What about faults in the network secondary spot bus. Will the customer DG trip? (Detection/communication are issues to investigate) Network voltage during light loading is a concern(unnecessary opening) The voltage may rise and this may cause electro-mechanical relays to open the NP. Some of the old GE breakers are a concern with the method of relaying. Electro-mechanical breakers must be replaced (Consensus) with addition of DG (Machine based?). Old NPs are a concern, based on X/R ratio. The newer higher kVA are 12-13 X/R ratios. The R values are very low. The NP may not even trip for a number of fault conditions because of the X/R ratio. The DR increases the X/R ratio. This may require a change in the NP relay that is used. Is the issue the relay’s ability to see the fault, or the ability of the NP to interrupt the fault? Also, the old NPs had no fault close capability, the newer ones do. Some installations will require newer NPs. Fault Detection: the DR shall detect faults on the system. How does the DR detect phgnd faults on the primary side of the network transformer? The DR does not see these faults if the network transformer is a delta on the primary side. As long as the utility has an NP closed, the DR does not need to see the fault and separate. The DR must be able to see ph-ph faults also. Should the DR separate if there are at least 50% of the NPs closed? If the fault occurs on the substation bus, how does the DR detect the fault? If the sub bank breaker opens, the DR will be overcome by load. Is it practical to install communication to transfer trip for faults seen by the substation breaker. Communication would be required from all breakers feeding the spot. Fault detection by DR in a network P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 58 system will be contrary to IEEE 1547 requirements. KISS! Communication (transfer trip) is complicated, but should be owned and maintained by the utility. Review/Modification of Network Design Criteria ( Long term Issue – Depends on Control jurisdiction) N-1 is a design criteria. Putting on too large of DG would be a serious design concern. Over-sizing the transformer would make the relays hunt and the NPs pump. Relays would have to be de-sensitized to accommodate the larger transformer. These are a function of impedances and voltages. The DG takes load off the transformer, unloading the transformer and increasing the chances of the NP pumping. Should the DG be under the control of the utility. Utility would likely install the DG at the substation bus, not on the spot network. Controls for the protection of the network should stay under the control of the utility. Controls for the protection of the DG should be under the control of the DG owner. Design criteria: if the utility has control of the DR, the utility can include the DG in the design (planning) of the network. If the utility does not have control of the DG, it should not consider the DR in its design (planning). Can the NP relays be programmed with alternate settings that are implemented automatically when the DR is on line? ==================== Closing Issues: (Prevention of “Proper” closing , initiation of “Improper” closing) Closing back is another issue when the load in the building has dropped off. Synch check must be performed at the customer’s tie breaker (if the customer elects to have the capability of operating the generator to supply some critical loads during system outages). What functions are required? This may require sync check at two customer breakers. One of the requirements is for under-power, not reverse power. Relays look at, normally, apparent power. (Simple Diagram to show PCC and Gen Breakers and different tripping/closing schemes) Frequency Issue (during closing) Frequency: Martin’s paper addresses frequency. NP relay is not adequate for synchronizing. But with the 50% NP rule, this condition should not occur unless there is some failure. For a successful closure of the NP there is a minimum amount of phasing voltage required, that is a function of the impedance of the transformer and the load current. The bigger the transformer is, with a corresponding lighter load the smaller the phasing voltage and the less likely it is that the NP will close and stay closed without pumping. The addition of DR reduces the transformer load, with a corresponding decrease in phasing voltage, increasing the likely hood of pumping. An evaluation of the relay settings at steady output of the DR is recommended. Review close and trip settings on a case by case basis. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 59 90o Adjustable Over-Voltage Close Curve 1 Adjustable Over-Voltage Close Curve 2 PV2 PV1 0o 180o Φ (System Impedance Angle) I2 I1 270o Figure X – Network Relay Closing Characteristics Cold start-up (network is out totally) the customer’s PCC breaker must be open. The customer PCC breaker cannot close until network has been restored for some period of time. How does the utility insure that the customer’s PCC breaker is open? Is this size dependent? Does the utility need to know when all or certain size generators are brought back on line with the network? Are communication circuits needed for this? If the network is totally out, the NPs won’t change state. It is important that the DR comes off high speed and that the utility has assurance that the DR is disconnected. The customer’s PCC breaker must be battery powered DC trip. If the network breakers trip (15 cycles), will the NPs trip? Will the DR provide enough voltage to trip the NPs? We need to monitor the 52B contacts to ensure that closing out of sync does not occur. We cannot delay restoring the network because of the DR. Can we depend on undervoltage tripping? The automatic transfer timing is an issue. Will a second breaker be required to account for stuck breaker possibility? Can the DR breaker serve as the second breaker for stuck breaker. It is unlikely the customer would want to open the PCC and DR tie breaker. The customer will usually chose one of the two to trip. P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 60 ANNEX J: P1547.6 CLAUSES 9 & 10 POST-BREAKOUT STATUS REPORT Section 9 & 10 Working Group Notes of Meeting August 3, 2006 (J. Bzura revised 8/15/06) Note: The concerns of the old Clause 9 have been integrated into this new Clause 9, “Recommendations for Interconnection of DR on Networks”. 9. Means of Interconnecting DR on Networks (All writing team members) Introduction: The methods below are intended to ensure: no backfeeding of NPs no connect or disconnect of DG via NP no false tripping of NP don't prevent an NP from closing appropriately fault current limitations are considered operational failures of components are addressed 9.1 Spot Networks - Considerations of Facility Load and DR Output (Daley, Watts) Controlling DR Output and Facility Import Where a utility deems necessary ... May need a NPs "interaction with DR" system May need a DR control system to manage the operation of the DR to ensure satisfactory or "normal" NP operation May need a "No go" signal from NP "interaction with DR" system May need a "Low load" signal from NP "interaction with DR" system May need a "Full operation allowed" signal from "interaction with DR" system How to determine minimum level of feeder load Net import matters Issue: double-ended unit substation (multiple facility feeds) Control system manages the flow of power into the facility Load management and shedding Power rating and max power (can be different) Reactive load variations (example light load NP conditions) How DR typically controlled Response time of automatic voltage regulators (dynamics issue?) 9.1.1 "De Minimus" DR Power Rating (Bzura) What % of service connection is de minimus? (Example: 1/15th of load in MA) Rating of DR relative to spot load relative to season relative to time and type of day demand Minimum expected facility load for when DR is operating "This concept assures a high probability of no reverse power flow" P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 61 9.1.2 DR Capacities Greater than De Minimus (Davis, Daley) Active control of import power levels Ability to accept loss of single largest facility load without falling below import criteria Ability to respond to facility load reductions that would cause power flow into the spot network bus from the DR Minimum load threshold (unload the DR) Actual reverse real and reactive power (stop the DR) Time sensitivity? Control strategies to address the import power level 9.1.3 NP Auxiliary Contact Generator Trip Protection (Davis) 9.2 Area Networks: Considerations of Facility Load and DR Output (Daley, Watts) For DR greater than de minimus, studies may be required (fault current, network component loading, and area load flow) Effect of DR on network load flow (distribution of power on the grid from generators) (Davis) Multiple feeds to facility (main-tie-main) “The focus of this guide is for power import from the network to the facility. Power export from DR to the network will be a topic under consideration for a future revision.” Size and number of DR relative to the location of their connection points and to the locations of the loads and network transformers in the area grid (Davis) Controlling DR Output and Facility Import Control system manages the bidirectional flow of power between the grid and the facility between various internal facility components between ... (tbd) Load management and shedding Power rating and max power Reactive load variations (example light load NP conditions) Considerations for when the number of connected NPs is reduced in emergency situations (Sammon) 9.2.1 "De Minimus" DR Power Rating (Daley, Whitaker, Bzura) What % is de minimus? (Example: PG&E policy) Rating of DR relative to area grid load relative to season relative to time and type of day demand relative to location (impedances) Minimum expected facility and area grid loads for when DR is operating Special interconnection agreement provisions (for example: time of generation) P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 62 9.2.2 DR Capacities Greater than De Minimus (Davis, Daley) Control strategies to address the power flow Active control of DR power levels Ability to accept loss of single largest facility load without falling below criteria determined by study Ability to react to facility load reductions that would cause power flow into the network from the DR (Example: DR located at same facility as largest load in the network, impact on area grid operation?) 9.3 Fault Considerations For All Secondary Networks (Costyk, Beach, Bzura) Fault current interrupting rating of NP Fault current contributions of DRs; inverters, induction, synchronous Current-limiting fuses on spot network buses Current-limiting technologies for DRs Fast solid state switches that interrupt within 1/8 to 1/4 cycle Fault contribution of the system and how affected by the DR De-sensitizing of system fault protection 9.4 Breaker failure schemes (ex: stuck breaker, not responding, etc.) (Beach) Require minimum of two interrupting devices or functions between the DR and the NPs P1547.6 Meetings for August 3-4, 2006 Working Group Meeting 63