Biogas Monitoring Project (Biogas Association)

Transcription

1 Biogas Monitoring Project (Biogas Association) Monitoring of Biogas Based Small Generators Connected to 3Phase 4Wire Distribution Feeders Final Report Sponsored by: Biogas Association and Hydro One Prepared by: Pankaj Sharma Protection & Control Planning Manager HYDRO ONE Jim Rockett Sr. Protection & Control Specialist Consultant, HYDRO ONE Contributed by: Aidan Foss Biogas Consultant Dale Williston Biogas Consultant COPYRIGHT 2012 BIOGAS ASSOCIATION AND HYDRO ONE NETWORKS INC. ALL RIGHTS RESERVED 1 - -

2 LIMITATION OF LIABILITY AND DISCLAIMER Biogas Association and Hydro One Networks Inc. s ( Hydro One ) or any person employed on their behalf, makes no warranties or representations of any kind with respect to this report of Biogas Monitoring Project (Monitoring of Biogas Based Small Generators), including, without limitation, its quality, accuracy, completeness or fitness for any particular purpose. Biogas Association and Hydro One will not be liable for any loss or damage arising from the use of this report, any conclusions and/or recommendations a user derives from the information in this report or any reliance by the user on the information it contains. Biogas Association and Hydro One reserve the right to amend any of the contents of this report at any time. 2

3 Table of Contents List of Tables... 4 List of Figures... 5 Executive Summary... 6 Terms and Definitions Introduction Background Power System Evolution wire feeder voltage unbalance Customer impacts Distribution System feeder outages Customer impacts Connection Requirement alternatives to accommodate small Biogas Biogas Monitoring Project Scope Interconnected System Characteristics Distribution System Supply Characteristics DG Facility Equipment Feeder Protections Faults Studies Utility Feeder Protections DG Protections Monitoring Methodology Monitoring At DG Sites Power Quality Monitoring At Hydro One DS and DG facilities Events and Observations Events at Terryland Farms Events at Fepro Farms Events at Ledgecroft Farms Discussion of Events and Observations Protection Settings Feeder Faults Power Swings Voltage Unbalance Total Harmonic Distortion Conclusions Recommendations Reference Documents Appendix A Terryland Farms Terryland Farms Site Overview Stardale Feeder F3 Overview B Fepro Farms Fepro Farms Site Overview Beachburg Feeder F2 Overview C Ledgecroft Farms Ledgecroft Farms Site Overview Battersea Feeder F1 Overview

4 List of Tables Table 1 Summary of Supply feeder Table 2 Hydro One Conditions of Service for Voltage unbalance Table 3 DGIT Details and winding configurations Table 4 Generator Specifications Table 5 Minimum Feeder In feeds to Faults on the DG side of the PCC Table 6 DG lowest fault in-feed conditions Table 7 DG HV Fuse Table 8 Interconnection Protection Specifications Table 9 Interconnection Protection Elements that Respond to DG Island Conditions Table 10 Interconnection Protection Elements that Respond to Feeder faults Table 11 Other Interconnection Protection Features Table 12 Generator Protection Design Table 13 Generator Protection Elements that may respond to Island conditions Table 14 Generator Protection Elements that may respond to Fault conditions Table 15 Interconnection Protection Monitoring Table 16 Terryland Protection Element Response to 3 Phase Active Power Swing Events Table 17 Terryland Feeder Fault Events Table 18 Fepro Feeder Fault Events Table 19 Beachburg Feeder Faults (beyond Downstream Recloser) Table 20 Fault on Other Beachburg DS Feeders Table 21 Fepro Supply Feeder Current Transients Table 22 Ledgecroft Feeder Fault Events

5 List of Figures Figure 1 Voltage Unbalance at DG Figure 2 Total Harmonic Distortion at DS and DG Figure 3 Terryland Trip Event Records Figure 4 Terryland Hour of Day distribution for Event Types Figure 5 Terryland Power Swing Events Hour of Day distribution Figure 6 Terryland Vector Shift (1P) Fast Trip Figure 7 Terryland 1P Vector Shift Detection No Trip Figure 8 Terryland 3P Vector Shift (3P) Fast Trip Figure 9 Terryland ROCOF Trip Figure 10 Terryland Power Export Trip Figure 11 Terryland Negative Sequence elements response to Other Feeder Faults Figure 12 Terryland Element responses to Stardale F3 SLG Feeder Fault Figure 13 Fault on Supply Feeder to Stardale DS Figure 14 Typical Terryland Element Responses Feeder Unbalance Figure 15 Terryland Breaker Open Event Figure 16 Fepro Trip Event Records Figure 17 Fepro Biogas Hour of Day distribution for Event Types Figure 18 Typical Beachburg F2 Feeder Fault Figure 19 Typical Feeder Fault (beyond Downstream Recloser) Figure 20 Typical Fault on Supply Feeder to Beachburg DS Figure 21 Typical Fault on Other Beachburg DS Feeders Figure 22 Fepro Power Swing Event Figure 23 Typical Supply Feeder Current Transients Figure 24 Ledgecroft Trip Event Records Figure 25 Ledgecroft Farms Biogas Hour of Day distribution for Event Types Figure 26 Typical Battersea F1 Feeder Fault (Main Trunk) Figure 27 Typical Battersea F1 Feeder Fault (Lateral Branch) st Figure 28 Typical Ledgecroft Generator Trip Cause Unknown (Trip on 1 Swing) Figure 29 Typical Ledgecroft Generator Trip Cause Unknown (Trip on 2nd Swing) Figure 30 Typical Ledgecroft Generator Trip Gas Control problem Figure 31 Ledgecroft small Power Swing trip Figure 32 Stardale F3 Feeder Simplified Diagram Figure 33 Protection Schematic Terryland Farms G Figure 34 Protection Schematic Terryland Farms G Figure 35 Beachburg F2 Simplified Diagram Figure 36 - Protection Schematic Fepro Farms Figure 37 Battersea F1 Feeder Simplified Diagram Figure 38 SLD Ledgecroft Farms

6 Executive Summary The Biogas Monitoring Project was undertaken as a combined effort of the Biogas Association and Hydro One Networks Inc. (Hydro One), with funding from the Ontario Ministry of Agriculture, Food and Rural Affairs, and Hydro One Networks Inc. (Hydro One). The primary objective of this Project was to monitor and assess the electrical performance of three small scale Biogas Distributed Generation (DG) installations less than 500kW, connected to Hydro One rural 3- phase, 4-wire distribution feeders. These biogas installations, Ledgecroft Farms, Terryland Farms and Fepro Farms, fall into an important category of Ontario s Green Energy program, providing improved economical and ecological utilization of farm livestock waste production. The biogas DG installations were selected for study by the Biogas Association (formerly Agrienergy Producers Association of Ontario APAO). The Introduction (Section 1) of this report summarizes relevant background information about the three biogas connections to kv and 8.32 kv (F Class) Feeders on Hydro One s rural Distribution System. The Appendix includes detailed descriptions of the biogas generator sites with illustrations of the protection schemes implemented at each site and associated supply feeder characteristics shown in simplified feeder diagrams. The use of single-pole reclosers on F Class Feeders allowed a series of cost saving design choices, improving the economic viability for these small projects. First, individual phase isolation of phase-ground faults results in much lower Temporary Over- Voltages (TOV) caused by ungrounded generation sources connected to 4-wire distribution than the ganged 3-phase reclosers and breakers used at higher 4-wire distribution voltage levels. Although TOV will still be greater with effectively ungrounded generation present, it remains within an acceptable range when the generation facility is not too far from the utility (Hydro One) ground source of the supply station, which remains connected on the unfaulted phases. In these cases low cost solidly-grounded HV star - LV star connected winding configurations can be used for the step-up interconnection transformer (DGIT). Section 3 - Interconnected System Characteristics provides a description of the specific characteristics of these distribution feeders and the biogas generator connections. Second, the biogas design choice of solidly-grounded HV star - LV star DGIT made possible additional cost saving design for the generator facility interconnection protections, which can detect ground faults on the distribution feeder when connected to low voltage (generator side) instrument transformers. Finally, DG projects having capacity of 500kW or less are exempted from the costly transfer trip schemes. The cost savings outlined above required some sacrifices in protection selectivity, resulting in increased vulnerability to nuisance trips. In the earliest stages of operation, the Biogas DGs were perceived to suffer from a high number of nuisance trips from unnecessary DG interconnection and generator protection operations. This motivated the project undertaking to help identify possible root causes and design refinements that could reduce their frequency. 6

7 Section 4 - Feeder Protections provides a description of the utility and generator facility interconnection protections and summarizes the results of feeder fault studies that determine the required sensitivity of the generator interconnection protections. Section 5 - Monitoring Methodology outlines the Monitoring Methodology used for the Project. The Project utilized oscillograph and sequence of events (SER) capability of the biogas interconnection protection relays to capture transient waveforms and protection element response associated with generator trip events as outlined in Section 5.1. Registered revenue meters with power quality recording functionality (ION 8600) were installed at the biogas generation sites. Similar unregistered revenue/power quality meters were installed at the Distribution Station supply point locations of the respective distribution feeders as outlined in Section 5.2. The revenue/power quality meters captured trend data for voltage unbalance and total harmonic distortion, presented in Sections and They also captured current and voltage records triggered by abnormal voltage transients to provide complementary data for the generator trip events. Monitoring was in place for over a one year and numerous records were captured. Section 6 - Events and Observations outlines the analysis of 140 generator trip events recorded during the phase two of this project between March and September. Careful analysis of these events revealed important information which was useful improving protection performance settings at these installations. Section 7 - Discussion of Events and Observations provides additional discussion of Events and Observations, with a particular focus on protection settings, feeder faults, power swings, voltage unbalance and total harmonic distortion. Sections 8 and 9 provides detailed Conclusions and Recommendations.. A summary of recorded generator trip events is shown below, broadly classified as Feeder Faults and Disturbances, Oscillatory Power Swings and a small number of unidentified events where the available data was insufficient. Summary of recorded events 7

8 The total number of feeder fault trip events at Ledgecroft Farms (37) is higher than Terryland Farms (16) and Fepro Farms (17). The higher number can be attributed to the greater length of the Ledgecroft Farms overhead supply feeder exposing it to more transient power system faults. The 37 events shown as Feeder Fault & Disturbances for Ledgecroft Farms do not signify that the voltage supply at Ledgecroft Farms was interrupted for all of these occurrences. Out of these 37 incidents on 19 occasions Hydro One three-phase supply voltages were not interrupted at Ledgecroft site which indicates that these faults and/or disturbances occurred on laterals and not on the main trunk line. Also the presence of voltage at Ledgecroft site confirms that none of the three upstream reclosers opened as the faults must have been cleared by fuses or reclosers protecting lateral or its portion. Similarly supply voltages were not interrupted for 6 out of 19 Feeder Fault & Disturbance events at Fepro, and for 8 out of the 9 Feeder Fault & Disturbance events at Terryland. These are examples of nuisance generator trip operations caused by the stand-alone DG interconnection protections. Fepro Farms had the lowest percentage of nuisance trips, most likely because Transfer Trip was installed in May 2011, which allowed increased time delays for the DG interconnection protections. This appears to support the expectation that the stations without transfer trip suffer more frequent nuisance generator trip operations for faults at other feeder locations. Ledgecroft Farms and Terryland Farms suffered a high number of generator trips associated with oscillatory power swings that were not power system faults. The root cause of most of these power swings was not identified but 9 of the 28 Power Swing events for Ledgecroft Farms were attributed to known generator s gas control problems. DG protection records for several power swing trip events were not complemented by revenue/power quality meter records because the latter are programmed to trigger on voltage excursions only. In those cases the voltage excursions measured by the revenue/power quality meter were below the fixed trigger thresholds. This limitation did not significantly affect the capture of fault events by the Hydro One DS meters. More detailed discussion of events for each site are provided in Sections 6.1, 6.2 and 6.3 where the events have been further sub categorized specifically for individual sites and analyzed in detail. A list of observations and conclusions resulting from this project are provided below with recommendations provided in italics. There is no attempt to estimate the costs associated with implementation of these recommendations. Costs associated with implementation of recommendations would be allocated according to accountabilities defined by the Ontario Distribution Code, legislation and contractual obligations relevant to the specifics of the DG connection. It is expected that any decisions to proceed will be based on regulatory and contractual obligations or cost considerations. 8

9 Key Observations and Recommendations 1. Based on the analysis of numerous events, it is observed that there are large numbers of both correct and unnecessary nuisance trip operations observed at the biogas generation sites. The trips were mainly due to: a) Faults occurring on the distribution feeder b) Sensitive interconnection and/or generator protection relay c) Generator prime mover s internal combustion abnormalities d) Voltage and current unbalances on the distribution feeders because of the single phase loads which is a characteristic of the rural nature of the F-class feeders. 2. With respect to power quality issues: a) Hydro One is responsible for maintaining the Distribution System as required by the Distribution System Code and as outlined in Hydro One Conditions of Service. b) As per Hydro One Networks Inc. Distribution Customers Conditions of Service, Hydro One maintains a 24-hour call answer service (Section 1.5) for the purpose of receiving inquiries from Customers regarding power interruptions, power quality incidents, and incidents related to the integrity or safety of its Distribution System. c) The Hydro One 3-phase, 4-wire system Distribution System is vulnerable to transient and persistent power faults requiring momentary or sustained outages, voltage and current unbalances and customer disturbances by nature of its practical design. That includes long lengths of over-head conductors exposed to the elements, a high level of single-phase connections and random customer load demands. d) 3-phase Biogas synchronous generators are more sensitive than most load customers to unbalance voltage conditions, power system faults, and momentary supply interruptions. e) There were 30 Hydro One supply interruptions attributed to faults on the feeders directly supplying the 3 biogas projects. The monitoring period occurred during the months when the frequency of faults is statistically the highest for overhead feeders. f) The settings for the negative-sequence generator protection must be appropriately selected to provide adequate protection for the generator but should not be so sensitive that it results in frequent nuisance tripping. When the generator is on line, monitoring of negative-sequence currents and voltages can be used to determine whether the unbalance exceeds Hydro One Conditions of Service g) On a few occasions voltage unbalance on the feeder was found to be above 5% requiring emergency corrective action by Hydro One. Ledgecroft Farms generator unbalance protections were found to operate for voltage unbalance less than 5%, and needed to be reviewed by the generator. Generators sourced from countries where 3- wire distribution is most commonly used may have ratings or protection settings that are intolerant of the range of voltage unbalances experienced on 4-wire distribution systems. h) Reliability and the power quality of the distribution system were not observed to be negatively impacted by connection of the biogas DGs. The enhanced monitoring features of the DG protections and revenue/power quality meters provided much useful information about DG response to Distribution System conditions such as 9

10 recurring faults (e.g. intermittent tree contacts), voltage unbalance and harmonic distortion. Exploiting this capability effectively can facilitate early detection of troublesome conditions and expedite faster corrective action. i) Total Harmonic Distortion (THD) on voltage was on the high side of normal at Ledgecroft Farms, but within acceptable limits. There was no adverse effect reported at any of the locations and the detailed harmonics analysis wasn t pursued. Recommendation: Protection performance issues needs to be effectively resolved as they occur. Appropriate monitoring and data capture of Distribution System voltages and currents and protection responses at locations relevant to problems of concern, to distinguish Supply Condition issues from Protection Design issues and to invoke appropriate corrective actions. Equipment ratings and protection design must allow Distribution System conditions as outlined in Hydro One Conditions of Service. That includes a voltage unbalance of up to 5% for extended periods (see Hydro One Conditions of Service for voltage unbalance - Table 2). Generators should determine the suitable tolerance limits of the small synchronous generators (less than 1MVA capacity) to withstand utility system voltage unbalances and harmonic distortions. 3. With respect to protection dependability: a) Hydro One accepts DG design that meets or exceeds both TIR and ESA requirements. b) Generators are responsible for DG design that meets both TIR and ESA requirements. Subject to those constraints DG design is free to make design choices to achieve a balance of protection system costs, operational costs, protection performance and risks that are acceptable to them. c) Based upon observed performance of the DG interconnection protections for the three Biogas facilities over the project monitoring period, the DG interconnection protections responded to all 37 fault events for which they were required to operate (without Transfer Trip). d) 3-phase islanding events are expected to be rare events on 4-wire F Class feeders that use single-phase reclosers. There were no true 3-phase island conditions observed during the study period that required the operation of the of the DG anti-islanding protections. Therefore the effectiveness of the enhanced DG passive anti-islanding protections could not be determined. ROCOF and Vector-shift or Reverse Reactive Power are both required for DGs that chose to connect without the normal Transfer Trip protection. Recommendation: Ensure any design changes intended to improve selectivity of DG interconnection protections (reduce frequency of nuisance trips) does not compromise the dependability of these protections to function as required. 10

11 4. With respect to nuisance trips: a) Protection design requires a balance between sensitivity, security and speed. Balance is more challenging for DG facilities that do not utilize communication intelligence (such as Transfer Trip) to selectively distinguish conditions that require the DG to disconnect. b) The Generator is accountable for the design of all DG protection, including the adequacy of settings and ongoing operational performance. c) Hydro One may accept proposed Generator design that reduces sensitivity or speed to improve security, but will hold the Generator accountable for adverse impacts to the Distribution System or other customers. Hydro One is not accountable for detrimental repercussions to Generator equipment as a result of DG design. d) Protection design choices and modifications considered to improve security from nuisance trips cannot compromise safety and dependability of these protections to prevent equipment damage or cause the performance of the distribution system to deteriorate. Proposed changes to DG Interconnection protections or power equipment that can impact the Distribution System must be submitted to Hydro One for review and acceptance. e) Although there were no identified concerns with the dependability of alternate protection designs developed to save costs for the Biogas connections a high percentage of nuisance trips was observed. The number of nuisance trips (33) was almost as high as the number of necessary trips (37). f) Anti-islanding vector-shift protection elements at Terryland Farms and Ledgecroft Farms responded to many non-island conditions, in particular power swings and faults. The root cause of the power swings has not been determined and it is not known whether the Power Swing events are benign or potentially harmful to either the generator or the Distribution System. g) At Terryland 150 ms time delay was added to the unbalance fault detection elements and the protection algorithm for the vector-shift protection element was changed from 1- phase to 3-phase. It is difficult to make any conclusive observation because these changes were made in the later stages of the project, but are expected to reduce the frequency of nuisance trips for faults on other feeders. h) There may be are further opportunities to optimize time delays and set points to reduce the frequency of nuisance trips without impairing the dependability of these protections. i) Any delays in protections required to detect feeder faults must recognize the relatively short transient time constants of these small biogas generators (80 to 220ms). Time delays should not exceed the relevant time constant of the DG fault contribution. Alternatively the pick-up level of the protection elements could be based on sub-transient or transient fault levels, with a drop-out level based on synchronous conditions to allow for decaying DG fault current in-feed. Recommendation: Generators can consider increasing the operational time delay for Interconnection protection elements that have been proven to cause nuisance trips. Decaying DG fault contribution due to short transient time constants needs to be considered. This can be increased to the lesser of: a value that would result in 200 ms total clearance time OR the DG generator 11

12 transient reactance time (T d). A delay to the 200 ms total clearance time can be used if the protection element pick-up settings are based on sub-transient or transient fault levels but a drop-out level is used based on synchronous conditions to allow for decaying DG fault current in-feed. Further changes to the 46 and 47 elements to avoid nuisance trips for low level faults and switching transients on other feeders may be considered. Monitoring of negative-sequence currents and voltages would be required to determine new settings. The cost savings of not using Transfer Trip is offset somewhat by increased operational costs of the nuisance trips. Consider the costs of further efforts to reduce the frequency of nuisance trips. Recognize that without Transfer Trip there may be a limit to the number of nuisance trips that can be avoided by further fine-tuning of DG interconnection protections. Subject to their possible importance for protecting the generator for oscillatory power swings or other needs, consider changes to vector-shift protections to reduce nuisance trips as follows: i) Relay manufacturers should be consulted to better understand operation, application and setting of vector-shift protection elements. Examine experience and developments in other areas, particularly Europe. ii) Terryland Farms can consider raising the setting of the vector-shift protection at up to a maximum of 15 degrees. iii) Ledgecroft Farms may wish to establish exactly which generator protection element at was causing nuisance trips for unbalanced faults on lateral sections of the feeder. Heretofore it was assumed but not confirmed to be vector-shift. If it is confirmed to be vector-shift, consider modifications (similar to those implemented at Terryland) to prevent operation on single-phase or phase-phase voltage transients. Changes to the Ledgecroft Farms generator vector-shift protection will need to be acceptable to the DG owner, in consultation with the generator supplier. iv) Hydro One should consider accepting elimination of vector-shift elements, providing at least 2 enhanced passive anti-islanding protection element are used (rate-of-change-offrequency and reverse reactive power). 5. With respect to oscillatory power swings trips: a) There were 62 oscillatory power swing events that caused biogas trips. b) The trips were caused by the DG interconnection protection anti-islanding elements and some cases undefined generator protection operation. c) Although for the most part the characteristic of the power swings appeared similar for events at each location where records were captured, they appeared different between locations. d) The oscillatory power swings appeared as large current transients at the generator terminals. e) The oscillatory power swings did not appear to cause significant power quality problems (excessive voltage fluctuations) for the Distribution System. 12

13 f) The root cause of the power swings has not been determined and it is not known whether the Power Swing events are benign or potentially harmful to either the generator or the Distribution System. g) Hydro One cannot model DG dynamic behavior at the present time because information about DG inertia, governor and excitation systems is lacking. The cost of gathering this information and executing tests to develop dynamic models on a routine basis such as is done for large generation connections to the transmission system may be prohibitive, because of the vast amount of DG connections. Recommendation: Assess whether the Power Swing events are potentially harmful to the Distribution System. If they are harmful to the Distribution System a Power Quality investigation will be necessary to eliminate the problems. If the Generator determines that they are harmful to the generator only, provide the Generators with sufficient Distribution System information as required for them to mitigate the problem. Assess whether the Power Swing events are potentially harmful to the generators. If they are harmful to either the Distribution System or the Generators, a Power Quality investigation will be necessary to eliminate the problems. The Power Quality investigation may require specialized monitoring, testing and modeling of the fuel, governor and excitation systems by the Generator. Changes to generator controls may be necessary by the Generators. 6. The design of Hydro One feeder protections and DG interconnection protections requires an effective information exchange between the DG owner and the Hydro One. Hydro One provides fault data exchange details to DG. Accurate details of Generator equipment characteristics are required to be incorporated into the utility electrical model for the Distribution System. The model is then used to generate extreme fault conditions that the protections are required to respond to. However, the required information exchange details from DG can vary widely with specific DG design details, the complexity of the local Distribution System and other connected generators: Recommendation: A uniform and consistent interconnection protection philosophy and relay setting guide with standard format information exchange data-sheets should be developed for DG interconnection protections incorporating refinements learned from recent past experiences. This would harmonize the development and acceptance of DG protection design and relay settings. From a protection perspective this will moderate many ground level implementation issues presently encountered by developers of Biogas facilities and utility protection engineers. This initiative may require participation of Hydro One and DG stakeholders and would be beneficial to all types of generation, not just to Biogas. 13

14 Terms and Definitions Anti-Islanding protection Breaker Clearing Time COMTRADE DG DGIT DG Facility DG Interconnection Transformer DG Owner Distributed Generation (DG) Distribution Lines Distribution System DO DS Effectively Grounded F Class Feeder Feeder Harmonics High Voltage HONI HVDS A protection system aimed at detecting islanded conditions (see island) and disconnecting the DG facility from the Distribution System if an island forms Fault Interrupting Device: this may be a breaker, circuit switcher, HVI, LVI See Trip Time Common Format for Transient Data Exchange See Distributed Generation See DG Interconnection Transformer All equipment including generators, interface transformer, protections, and line on the DG side of the PCC The transformer used to step up the voltage from the DG to distribution voltage levels The entity which owns or leases the DG facility Power generators connected to a Distribution System through a Point of Common Coupling (PCC). Distribution System lines that operate at nominal line-line voltages at or below 27.6 kv Any power line facilities under the operating authority of the Wires owner (HONI or LDC) that operate at nominal line-line voltages of 50 kv or below. This includes sub-transmission power lines that operate at 27.6 kv or 44 kv and distribution lines that operate below voltages of 27.6 kv Drop Out An electrical station that is used to step down a sub-transmission voltage to a distribution voltage for distribution to the end use customer. A system grounded through sufficiently low impedance so that COG does not exceed 80%. This value is obtained approximately when, for all system conditions, the ratio of the zero-sequence reactance to the positivesequence reactance, (X0/X1), is positive and 3, and the ratio of zerosequence resistance to positive-sequence reactance, (R0/X1), is positive and < 1. Distribution feeder emanating from a HONI DS or HVDS A single-phase or three-phase line emanating from a substation to supply load Sinusoidal voltages and currents at frequencies that are integral multiples of the fundamental power frequency (60Hz). In this document, high voltage refers to the HONI system voltage and can be referred to as medium voltage. Hydro One Networks Inc. High Voltage Distribution Station: the distribution station connected directly to HONI transmission system which steps down transmission voltage to distribution voltage for distribution to the end use customer. 14

15 IEEE The Institute of Electrical and Electronics Engineers IED Intelligent Electronic Device Interrupting The device used to disconnect generation from HONI s Distribution System: Device this may be a high voltage interrupter (HVI) or through a low voltage interrupter/breaker (LVI). Island An operating condition where a DG(s) is (are) supplying load(s) that is electrically separated from the main electric utility. Load The amount of power supplied or required at a specific location. LVI Low Voltage Interrupter M Class Feeder Distribution feeder emanating from a HONI TS NDZ Non Detection Zone range where passive anti-islanding protection may not operate within required time due to the small mismatch between generation and load NGR Neutral Ground Resistor Nuisance Trip A nuisance trip is an unnecessary disconnection of the DG by a protection. Examples of this are a response by a protection to an out-of-zone fault or a response to a power system disturbance that is not a fault. Oscillograph An instrument primarily for producing a record of the instantaneous values of one or more rapidly varying electrical quantities as a function of time or of another electrical or mechanical quantity. A sudden, non-power frequency Oscillatory change in the steady-state condition of voltage or current that includes either transient positive or negative polarity value. PCC Power Swing PT PQ PU ROCOF RMS SLD THD TIR TOV Trip Trip Event Transfer Trip TS Point of Common Coupling. It is the point where the DG Facility is to connect to Hydro One s Network s Inc. Distribution System See Oscillatory transient Potential Transformer Power Quality Pick Up Rate-of-change-of-frequency Root Mean Square Single Line Diagram Total Harmonic Distortion a measurement of the harmonic distortion present. It is defined as a ratio of the sum of the powers of all harmonic components to the power of the fundamental frequency Abbreviation for HONI DG Technical Interconnection Requirements Temporary Overvoltage oscillatory power frequency overvoltages of relatively long duration from a few cycles to hours. The action associated with the opening of a circuit breaker or other interrupting device. An event that involves a Trip TT - A signal sent over communication channels from upstream devices commanding the DG to disconnect from HONI's Distribution System. An electrical station that is used to step down transmission voltage to a subtransmission voltage for distribution to the end use customer and DS 15

16 1 Introduction This section outlines some fundamental design features of the overhead circuit distribution system, historically designed to economically serve load customers. It shows how generators are more likely to suffer prolonged production interruptions caused by momentary transient fault conditions. This section also outlines some general technical requirements for connecting generation to the 4-wire distribution system and how these requirements can be costly for small capacity connections such as 500 kw biogas generators. However it shows that some distinct features of the Class F portion of the distribution system to which the subject biogas generators were connected provided an opportunity to reduce many of these connection costs. These cost savings usually require some sacrifices in protection selectivity, resulting in increased vulnerability to nuisance trips. 1.1 Background Power System Evolution For most of the 20th century, Ontario s power system was developed to efficiently transfer power from generation sources to end use customers to meet the provinces demand for electricity. In the early years, transmission voltage levels were limited and generation practically needed to be located fairly close to load customers in order to be economically viable. Many small islands of hydro-electric generation were developed by power and light companies to distribute electricity directly to rural customers over short distances using low voltage distribution circuits. As demand for electricity grew, the distribution system expanded but became focused on serving load customers. The exceptions to load-only distribution customers were the centuryold small hydro-electric generation that was an integral part of some parts of the Ontario rural distribution system and limited amounts of non-utility (NUG) generation that was developed in the 1980 s and 1990 s, mostly from industrial and commercial co-generation opportunities. New generation sources took the form of large hydro-electric mega-projects such as Niagara Falls Sir Adam Beck GS and St. Lawrence R.H. Saunders GS. Higher voltage transmission circuits needed to be developed to more efficiently transfer power over longer distances to the urban load centers and rural distribution systems. Full development of available large scale hydro-electric generation gave way to large coal and nuclear thermal generation stations with more complex environmental issues. A vast high voltage transmission system network evolved interconnecting the large generation stations and tie-lines to the neighboring provinces and US states. Ontario s power system became part of a massive eastern North American power system. This forms an electrical backbone that was carefully designed and managed to dynamically balance power generation with load consumption maintaining a high level of voltage and frequency stability at the transmission system level. The HV circuits of the transmission system is interconnected at transformer stations where the voltage is also transformed to lower distribution system voltages to directly serve end-use customers. The use of multiple circuits avoids loss of load to transformer stations for most single circuit contingencies. The interconnected transmission system grid also allows power brokerage between utilities with economic load dispatch, utilizing the least expensive generation sources available at all times and running more costly generation only as required to meet peak loads. 16

17 The distribution systems supplied from the transmission system in this way takes advantages of the inherent reliability of supply and economic advantage that access to a huge generation pool provides, and very stable supply voltage and frequency. Unlike the transmission system, distribution system power delivery is vulnerable to single circuit feeder contingencies, because customers are usually connected to one feeder supply only. Compared to the transmission system that had to accommodate power flows from continuously changing generation to load customers in all directions, power flows through load-focused distribution systems became mostly unidirectional. Predictable unidirectional power flows from the transmission system sources only allow relatively simple and inexpensive voltage regulation and protection systems to be used. Many ungrounded 3-wire distribution systems were changed to grounded 4-wire distribution systems with a 4 th grounded neutral conductor. That allowed the majority of single-phase customers to be supplied directly from one-phase of the distribution system conductors only using a phase-neutral connection. This allowed the use of less expensive transformers that required less insulation and greatly reduced the number of customers affected by single-phase faults. This status quo drastically changed when Bill 150, Green Energy and Green Economy Act, 2009 aimed to promote the increased use of renewable energy sources and technology, including generation facilities connected to the distribution systems. The response was dramatic. Distributors such as Hydro One were flooded with applications from interested generation developers. Hydro One engineers, equipment suppliers and engineering consultants entered a steep learning curve to address the many technical challenges associated with wide scale penetration of additional generation into the distribution system. The integrity of the distribution systems needed to be preserved. That included maintaining steady-state and transient conditions on the distribution system that respects current and voltage ratings of customer and utility equipment, preserving reliability of supply, protection performance, acceptable power quality and avoiding additional rate-base costs. Policies, processes and technical requirements were refined to accommodate the many different types of renewable energy generation, including Biogas. Today, these same distribution systems are being used to connect very large numbers of distributed generators, including biogas generators, resulting in power flows in both directions. Hydro One has received the majority of connection applications under the RESOP, FIT and Micro FIT programs that have been launched by the Ontario Power Authority over the last few years. As a result, Hydro One s distribution system will see significant numbers of generator connections. In particular, these generators will inject more power flow into some areas of the distribution system than the existing power flow that was serving the load customers, and the wire size is no longer right-sized for these new power flows. As the needs of generators may be different, their generators will require more tolerance. The needs of generators may be quite different from those of load customers. As discussed in 1.3 below, although some industrial or commercial load customers are sensitive to momentary outages or minor power quality fluctuations, the vast majority of load customers do not notice momentary outages or sometimes even sustained outages, and they are not impacted by minor power quality fluctuations that remain within standards. 17

18 The distribution system is dynamic, with automatic as well as manual switching operations that occur to improve reliability or allow planned maintenance. Load constantly changes throughout the entire system as well as on any small portion of the system because it is entirely customerdependent. As a result, the Distribution System Code does not mandate that distributors maintain a perfect distribution system because that would be impossibly expensive with such a dynamic system, but instead it is designed to allow distributors to keep rates low for those ratepayers. The Distribution System Code does allow distributors to upgrade their distribution systems at the request of generators. However, in order to keep rates low for ratepayers, these types of upgrades would normally be completed at the cost of the generator as the load customers do not require it nor would benefit in any material way wire feeder voltage unbalance Customer impacts Voltage unbalance on 4-wire distribution is inherently much higher than voltage unbalance on the transmission system and 3-wire distribution. As discussed in Section 3.1.1, single-phaseground load connections of 4-wire feeders are strategically connected with the intent of balancing the kva loading on each phase conductor to minimize voltage unbalance on the feeder. Practical limitations make it difficult to achieve an average phase current unbalance less than 10-20% of total feeder load. A 10% current unbalance corresponds to a voltage unbalance of approximately 2% and a 20% current unbalance corresponds to a voltage unbalance of approximately 4%. Hydro One s Condition of Service requires emergency action when voltage unbalance exceeds 5%, but no action when the voltage unbalance is less than 3% Single-phase load customers should not be impacted by feeder voltage unbalance, providing the unbalance does not cause individual phase-neutral voltages to traverse beyond the range stipulated by Hydro One s Condition of Service (±6% of nominal). 3-phase load customers, particularly those with 3-phase rotating machines (motors or generators) have lower tolerance for 3-phase voltage unbalance. As per IEEE Red Book, when unbalanced phase voltages are applied to three-phase motors, the phase-voltage unbalance causes additional negative-sequence currents to circulate in the motor, increasing the heat losses primarily in the rotor. The most severe condition occurs when one phase is opened and the motor runs on single-phase power. Voltage unbalance effectively reduces the rating of 3-phase machines. A 2% voltage unbalance may correspond to a 95% derating factor, a 5% voltage unbalance may correspond to a 75% derating factor. The impact of voltage unbalance on 3-phase synchronous machines (biogas generators) is discussed in Section Designers and purchasers of generators for 4-wire distribution connection need to be cognizant of the higher level of voltage unbalance that is inherent on these systems. 1.3 Distribution System feeder outages Customer impacts The vast majority of power outages on an overhead circuit distribution system are momentary caused by transient faults. Transient faults on over-head line conductors constitute approximately 85-90% of all faults, caused by lightning, wind, icing, tree branches or other objects falling or blown, and animal or other momentary foreign contact. 18

19 Hydro One protection for feeders with over-head line conductors use sensitive and fast-acting protections to quickly isolate the fault on the first operation. Automatic reclosure is used to quickly re-energize the circuit, usually within 2 seconds. This minimizes fault duration and equipment damage and provides the fastest restoration of supply to all customers, avoiding manual replacement of fuses etc. The instantaneous low-set protections are used only for the first protection operation and will successfully clear most faults. If the fault condition is no longer present (transient) service to load customers will be restored within the first automatic reclosure time frame. Providing the load customers processes can ride out the 2 second interruption, the momentary interruption may be no more than a minor annoyance. This is usually the case for most residential customers. Some industrial and commercial customers with extreme power quality sensitive motor controllers or processes may suffer production losses for short-time interruptions. They often address this distribution system limitation by adding an alternate feeder supply, uninterruptable power supply (UPS) or direct connection to the transmission system. Distributed Generation is much more impacted by all feeder interruptions. When the utility supply is interrupted the DG must disconnect also. The generator must ensure restore supply to the feeder is stabilized (voltage within 6% of nominal and the frequency is between 59.5Hz and 60.5Hz) for a period of up to 5 minutes before reconnecting. Following the first protection operation the Hydro One low-set protection elements will be blocked for a short period, usually 10 seconds. That allows other time-coordinated protections to selectively clear persistent or permanent faults. Time coordinated protections require significantly longer times to clear low level faults, particularly those near the feeder-end. Timed protections will normally operate within 1.5 to 2.5 seconds for the clearance of feeder-end 3- phase faults and 1.5 to 2 seconds for the clearance of feeder-end SLG faults. However under emergency conditions these clearance times may be as long as 3 seconds. DG must remain disconnected during the Hydro One reclosure attempts to avoid complications with protection coordination. 1.4 Connection Requirement alternatives to accommodate small Biogas Hydro One produced new comprehensive Distribution Generation Technical Interconnection Requirements in Most technical requirements are generic and apply equally to all fuel types (wind, hydro, solar, biomass,) and generator types (synchronous, asynchronous and inverter-based). Some requirements involve items for which the cost is largely independent of project size and posed significant barriers to the economic viability for the smaller scale projects, especially for small-scale Biogas generating systems (<500kW). Fixed-cost items include the provision of effective grounding of the generator connection with respect to the Distribution System and interconnection protections that can be relied on to disconnect generation and DG ground sources for abnormal conditions such as power system faults and the formation of DG islands. Connection of small biogas connections to kv and 8.32 kv (F Class) Feeders on Hydro One s rural 4-wire distribution system provided some unique opportunities for some relaxed Hydro One Technical Requirements and reduced costs. These requirements and reduced costs for the biogas are discussed briefly below. 19

20 Requirement for Effective DG Grounding Effective grounding for DG connections to 4-wire distribution circuits often requires separate grounding transformers or more expensive star-delta interconnection transformers with neutral reactors. This equipment limits maximum and minimum ground fault current to be with a carefully restricted range. A minimum amount of ground current is required for 4-wire connections to respect maximum phase-neutral over-voltages that occur during line-ground faults (TOV). TOV must be restricted to 130% to avoid damage to customer connections. DG grounding must be carefully checked by fault study to ensure the connection does not cause the TOV limit to be exceeded. However the DG ground current contribution must not be allowed to exceed short-circuit limits or to impair Hydro One ground protections from selectively detecting and isolating faulted sections of the distribution system. The use of single-pole reclosers on F Class Feeders provides individual phase isolation of phase-ground faults. Hydro One study has shown that single-phase isolation of SLG faults results in much lower Temporary Over-Voltages (TOV) when ungrounded DG sources are connected than complete isolation by 3-phase reclosers and breakers. Although TOV will still increase with ungrounded generation present, TOV may remain within an acceptable range providing the generation facility is not too far from the Hydro One DS ground source. Such was the case for the 3 biogas connections under study. This provided freedom for the Generators to choose low cost solidly-grounded HV star - LV star connected winding configurations can be used for the step-up interconnection transformer (DGIT) Requirement to Disconnection DG Ground Sources When a fault first occurs on a distribution system feeder, the Hydro One feeder protection uses an instantaneous (low-set) protection element to detect the fault and to immediately open the Hydro One feeder breaker or recloser to disconnect the Hydro One supply source from the fault. Clearance of a first fault avoids blowing fuses when possible since most faults on overhead distribution feeders are transient in nature and a blown fuse will leave the customers served by the fuse without power for a prolonged period. The low-set protection also initiates automatic reclosure, quickly restoring power to load customers usually 0.5 to 2 seconds. After the first protection operation, the low-set protection elements are blocked. Time coordinated protection elements are then used to delay tripping, allowing downstream fuses to permanent faults, such as a fallen conductor. A high voltage interrupter (HVI) may be required to disconnect DG grounded sources from the distribution feeder before Hydro One recloses after the first trip. That allows simple radial fuse coordination practices to be retained for the isolation of permanent faults along the feeder, minimizing the number of disrupted customers to those connected to the faulted section served by the blown fuse. Otherwise much more complex and expensive protection solutions of the type required to protect bidirectional transmission systems would be required. Since the 3 biogas connections under study are not ground sources, an HVI was not required. 20

21 1.4.3 Interconnection Protection Requirements a. Detection of Feeder faults All DG must have reliable interconnection protection fault detecting elements quickly disconnecting the generator (and associated ground sources) when there are faults on the supply feeder. These fault detecting elements must be fast enough for the DG to be disconnected and for the fault current path of transient faults to be extinguished before Hydro One automatically reconnects. The use of star-delta DGIT windings to provide effective DG grounding usually requires the use of more expensive instrument transformers connected on the Distribution feeder side of the interconnection transformers to detect ground faults. Since the 3 biogas connections under study used solidly-grounded HV star - LV star DGIT winding configurations, it is possible to detect ground faults on the feeder using less expensive instrument transformer connected the generator terminals. b. Detection of Island Conditions All DG must also have reliable interconnection protection anti-islanding protection elements that are capable of detecting an island condition with no measurable fault present. A DG island condition could be created if a fault is not sustained after the Utility disconnects or is immeasurable by the DG protection. The anti-islanding protection elements must also be fast enough for the DG and other customer rotating machines to be disconnected before Hydro One automatically reconnects. There is concern that any DG (or combination of DG with other DG or rotating machines) that is capable of sustaining island voltages within the re-closure time-frame could result in asynchronous reconnection of the utility source. That could result in severe electrical and mechanical stresses and damage to series component associated with the asynchronous reconnections, including in-line breakers, transformers, generators and motors. c. TT and DGEO Utility feeder protections must be capable of selective detection and isolation of all faults on the distribution system. With no DG connected to a feeder, Hydro One feeder protection can usually use simple over-current protection to protect the feeder, because fault current flows for faults on the feeder. If DG is connected fault current can flow in both directions and a more sophisticated protection may be required. From the vantage point of the Hydro One feeder protection the current polarities will reverse depending whether the faults are downstream on the feeder being protected or upstream within the supply station or on another feeder. Directional elements use the phase relationships between the currents and voltages to establish the fault direction. If the DG infeed through the utility feeder protection to an upstream fault exceeds the over-current settings required to detect feed-end faults, directional elements are required to distinguish when the feeder needs to tripped and when it should not be tripped. Protection modifications required to maintain performance as a result of DG connections are identified at the early stages of connection application (Impact Assessment). Agreements and arrangements are made for the DG to cover the cost of implementing the changes required for their connection. With respect to the DG protection, all distribution system faults are in the same direction. Also DG infeed to a fault on either side of a Hydro One supply breaker or recloser is virtually identical 21

22 in magnitude. Therefore it is not generally possible for DG interconnection protections to use fault magnitudes and fault direction alone to distinguish between faults on the supply feeder and faults on other feeders. To avoid DG disconnection for faults on other feeders, DG tripping must be delayed until after the Hydro One source is disconnected from the fault (typically less than 150ms). If the Hydro One protection operation isolates the DG from the fault, then DG infeed to the fault will be interrupted, protection elements will reset and unnecessary DG tripping is avoided. Prolonged delays greater than 200 ms should be avoided to minimize fuse melting and ensure DG are disconnected and faults are extinguished before automatic reclosure takes place. Decaying DG fault contribution is also a concern that needs to be considered. The use of protection intelligence between Hydro One feeder protection and the DG Interconnection protection can provide fast DG fault disconnection and is the most secure means of reliably disconnecting DG only when required. Transfer Trip (TT) and Distributed Generation End Open (DGEO) are required when the DG is too large for reliable detection and timely disconnection for a DG island condition using local frequency and voltage detection elements only. Whenever the Hydro One feeder protection trips the feeder TT is sent to the DG to disconnect it. When the DG is disconnected DGEO is sent from the DG to the Hydro One protection for confirmation, allowing automatic reclosure to proceed. The cost of TT and DGEO is prohibitive for small biogas installations <500kW, so Hydro One removed these requirements for DG of this size. However Hydro One cannot predict with certainty how the DG voltage and frequency will dynamically respond to DG island conditions because of limited information about DG inertia, governor and excitation systems. The cost of gathering this information and executing tests to develop dynamic models such as is done for large generation connections to the transmission system is prohibitive. To minimize risk of the uncertain, Hydro One has required the use of enhanced anti-islanding protection, Rate of Change of Frequency (ROCOF) and Vector shift or Reverse Reactive power to improve the probability of successful islanding detection. The 3 biogas connections under study elected not to use TT and DGEO. This provided an opportunity to monitor the performance of the stand-alone DG interconnection anti-islanding protections. 1.5 Biogas Monitoring Project The Biogas Monitoring Project was undertaken as a combined effort of the Biogas Association and Hydro One Networks Inc. (Hydro One), with funding from the Ontario Ministry of Agriculture, Food and Rural Affairs, and Hydro One Networks Inc. (Hydro One). The primary objective of this Project was to monitor and assess the electrical performance of three small scale Biogas Distributed Generation (DG) installations less than 500kW, connected to separate Hydro One rural 3-phase, 4-wire distribution feeders. These biogas installations, Ledgecroft Farms, Terryland Farms and Fepro Farms, fall into an important category of Ontario s Green Energy program, providing improved economical and ecological utilization of farm livestock waste production. 22

23 The first phase of monitoring was completed in 2009/2010. Power Quality monitoring equipment was installed at distribution station on respective feeders supplying these biogas generation facilities and also at three biogas generation sites. Terryland Farm is connected to the distribution feeder F3 of Stardale Distribution Station (DS), Fepro Farm is connected to the distribution feeder F2 of Beachburg DS and Ledgecroft Farms is connected to the distribution feeder F1 of Battersea High Voltage DS. The power quality meters at Terryland and Fepro Farms were installed during second phase of the project. Thus only partial monitoring was possible during first phase. The second phase of the monitoring project intends to understand issues of power quality, voltage fluctuations, power interruptions, equipment protection strategies and characterize the electrical performance of rural 3-phase 4 wire distribution feeder connecting to the three phase small scale (<500kW) biogas generating systems. The equipment installation was completed in the early part of 2011 allowing for the implementation of Phase 2 which started in March, This enabled enhance data capture and correlation of events to help characterize the overall system performance. The project team is comprised of APAO and Hydro One engineers, and electrical consultants. 2 Scope The overall scope of this project is outlined in the following points: a) Study and analyze three-phase biogas generation on utility s primary three-phase, four-wire distribution feeder. b) Assess system performance and electrical characteristics associated with behavior/response of synchronous generators during utility feeder faults and/or disturbances. c) Optimize the inter-tie protection relay settings to minimize nuisance trips observed by biogas generation. d) Identify power quality issues of utility feeder which affects biogas based generation facilities and provide recommendations. e) Identify the capability of the synchronous generator to withstand utility system disturbances and recommend suitable tolerance limits. f) On completion of the monitoring project, develop a comprehensive final report citing key observations, potential barriers in interconnecting biogas based generation, solutions achieved, and recommendations for improvement. 23

24 3 Interconnected System Characteristics This section provides a Tabularized overview of the three biogas generation connections that where studied by this project. 3.1 Distribution System Supply Characteristics Table 1 Summary of Supply feeder Details Terryland Farms Fepro Farms Ledgecroft Farms DS to In service date Location St. Eugene Cobden Seeleys Bay Supply station Stardale DS 44/8.32kV Beachburg DS Battersea HVDS feeder F3 F2 F1 Feeder Class Class F Class F Class F Voltage 8.32 kv kv kv Conductors 3-phase, 4-wire 3-phase, 4-wire 3-phase, 4-wire Distance) 3.4 km 6.2 km 23 km Z j Ω j Ω j Ω PCC Z j Ω j Ω j Ω PCC to DGIT 0.1 km 0.06 km 0.3 km Feeder Reclosers Other DG s on Feeder 100 kw 3125 kw None Each Biogas farm in this study is connected to Hydro One F Class Feeders supplied from small Distribution Stations (DS). These feeders are 4-wire supplying single-phase load customers at kv or 8.32 kv. Reclosers are used to automatically detect and isolate faults along the feeder. 1 This includes DS recloser. All reclosers use single pole operation to isolate only faulted phases 24

25 3.1.1 Voltage unbalance Single-phase-ground load connections of 4-wire feeders are strategically connected with the intent of balancing the kva loading on each phase conductor to minimize voltage unbalance on the feeders. However there are practical limitations to effectiveness of this hard-wired connection approach for maintaining balanced voltages on a 4-wire feeder. Also short-term load unbalances may be considerably more than the average. Discrete load connections make it difficult to achieve an average phase current unbalance less than 10-20% of total feeder load. A 10% current unbalance corresponds to a voltage unbalance of approximately 2% and a 20% current unbalance corresponds to a voltage unbalance of approximately 4%. The Distribution System is subject to small differences in voltages across the three phases of supply due to unbalanced customer loads or unbalanced loading of the distribution circuits by single-phase customer loads. Since an unbalanced voltage can be detrimental to some customer 3-phase electrical equipment Hydro One will to endeavor to minimize voltage unbalance and will apply the following guidelines when voltage unbalance is found to exist. Table 2 Hydro One Conditions of Service for Voltage unbalance Measured Voltage unbalance Corrective Action to Be Taken < 3% No Action 3% - 5% Correct on a planned basis (within 12 months) > 5% Correct on an emergency basis Larger short-term load unbalances arise because individual phase currents continually vary along the feeder depending on changing load dynamics of individual customer demands that do not change uniformly on each phase over time. This results in continually varying voltage unbalances along the feeders that often follow similar hourly and daily patterns. These shortterm unbalances on 4-wire distribution cannot practically be eliminated and their unavoidable presence and impact on 3-phase generators needs to be considered. Unbalanced voltages have both negative-sequence and zero-sequence components. When unbalanced phase voltages are applied to three-phase machines, the phase-voltage unbalance causes negative-sequence currents to circulate in the machine, increasing the heat losses primarily in the rotor. See below for Impact of 4-wire feeder Voltage unbalance on Generator unbalance currents. The most severe condition occurs when one phase is opened and the machine runs on single-phase power. Figure 1 shows the DG voltage unbalance trends for the 3 farms over the study period. 25

26 Figure 1 - Voltage Unbalance at DG The worst voltage unbalance was at Terryland, in particular over the period from June to August 2011 when the voltage unbalance frequently exceeded 3%. 5 unbalance trips occurred during this period (see Section 6.1.3). The feeder loading was rebalanced and the average voltage unbalance was improved. The average voltage unbalance was less than 1.5% at Fepro and less than 3% at Ledgecroft. Figure 1 shows that there are short-term load unbalances considerably more than the average. Most of these can be attributed to switching events (singlephase recloser operations). 26

27 3.1.2 TOV and Grounding Requirements Hydro One TIR requires that Temporary Overvoltage (TOV) should not exceed 125% on the 3- phase 4-wire Distribution Systems and under no circumstance shall exceed 130%. TOV levels are determined by Thevenin s equivalent sequence impedances at unbalanced fault location. That depends primarily on the ratio of the zero-sequence reactance to the positive-sequence reactance (X 0 /X 1 ), but the resistance components of the impedances also have an effect. The Thevenin equivalent sequence impedances depend on the following factors: a) Utility source impedances (positive and zero-sequence) b) DG source impedances (positive, negative and zero-sequence of DGIT and generator). These are affected by DGIT and Generator capacity and neutral ground connections c) Feeder conductor characteristics (conductor types) d) Distance to the fault in relation to the sources (circuit impedances between the fault and the sources); and e) Location of the Utility and DG sources in relation to each other (circuit impedances between the sources) An SLG fault will be jointly fed by the utility and the DG sources until the protections operate, as discussed in Section 4. During this period the TOV will depend upon the Thevenin equivalent sequence impedances derived from all the sources in the network. The effect of Three-phase or Single-phase opening of the breaker/recloser is further described in following paragraphs Effect of Three-phase (gang-operated) and Single-phase reclosers on TOV When all poles of a 3-phase gang-operated recloser open to isolate Hydro One sources from a single-line fault, any 3-phase DG that remains connected on the faulted side of the recloser is completely islanded with the fault. Then TOV is then determined entirely by the Thevenin s impedances of the DG source impedances to the fault location. Effective grounding of the DG sources is always critical to maintaining TOV to less than 130% wherever Hydro One uses 3- phase gang-operated interrupters. Such is the case for M Class feeders. This is not the case for F Class feeders that use Single-phase reclosers as discussed below. Hydro One study has confirmed that Temporary Overvoltage (TOV) does not increase on unfaulted phases after only one recloser pole-interrupter opens to isolate a ground fault on the feeder. TOV continues to be curtailed by the ground sources at the supply DS that remain connected to the un-faulted phases. If the DG facility is not effectively-grounded the amount of increased TOV caused by the presence of DG depends primarily on the proximity of the DG to the DS. Because the distances of the F Class feeders are relatively short, the DG facility may not need to be effectivelygrounded to respect Hydro Ones maximum TOV limit of 130%. The requirement for DG facility grounding to respect TOV limits is determined by Hydro One at the Connection Impact Assessment stage. 27

28 3.1.4 Total Harmonic Distortion Rectifiers, inverters, arc furnaces, static VAR systems and other non-linear loads generate harmonic voltages and currents. These harmonics may interfere with the operation of the Distribution System by conductive interference and/or may interfere with communication systems by inductive interference. Limits for Voltage and Current Harmonics are outlined in Section Of Hydro One Technical Interconnection Requirement (TIR). Total Harmonic Distortion (THD) shall be a maximum of 6.5% on 4-wire feeders. Hydro One maintains a 24-hour call answer service for the purpose of receiving inquiries from Customers regarding power interruptions, power quality incidents, and incidents related to the integrity or safety of its Distribution System. In response to a Customer s power quality concern, where the utilization of electric power affects the performance of electrical equipment, Hydro One will work with the Customer to perform investigative analysis to identify the underlying cause. Figure 2 shows the Total Harmonic Distortion for the 3 farms over the study period. 28

29 Figure 2 - Total Harmonic Distortion at DS and DG The worst THD was at Ledgecroft, for three days in the last week of May when the THD exceeded 6.5%. The THD at Battersea DS was generally last than 2% but also increased up to 3% in the last week of May. The average THD was less than 3% at Terryland, Fepro and at their supply DS s. 29

30 3.2 DG Facility Equipment Interconnection Transformers (DGIT) Table 3 DGIT Details and winding configurations Project Terryland Farms Fepro Farms Ledgecroft Farms Transformer name T2 T1 T1 kva 300 kva 750 kva 750 kva HV winding LV winding 8.3 kv : Y-gnd (solid ground) 480 V : Y-gnd (solid ground) kv : Y-gnd (solid ground) 600 V : Y-gnd (solid ground) kv : Y- gnd (solid ground) 600 V : Y-gnd (solid ground) Reactance (p.u.) 0.021p.u p.u p.u Generators Table 4 Generator Specifications Project Terryland Farms Fepro Farms Ledgecroft Farms Generator name G1 G2 G1 G1 Prime mover Bio-gas Bio-gas Bio-gas Bio-gas Manufacturer Stamford Stamford Stamford Stamford Model HCI4C HCI4C HCI 634 H2 HCI 634-J Generator type synchronous synchronous synchronous synchronous Voltage 480 V 480 V 600 V 600 V kw 180 kw 180kW 499 kw 499 kw Power factor 0.8 p.f. 0.8 p.f. 0.8 p.f. 0.8 p.f. kva (generator impedance base) 312kVA 312kVA 669 kva 1300 kva X d 0.13 p.u p.u p.u p.u. X d 0.20 p.u p.u p.u p.u. Xd 3.09 p.u p.u p.u p.u. X p.u p.u. 0.1 p.u p.u. X p.u p.u p.u p.u. T d sec sec sec sec T d 0.08 sec 0.08 sec 0.22 sec sec T d sec 1.7 sec 2.44 sec 3.03 sec NGR Solidly grounded 55.4 ohms 69.3 ohms 69.4 ohms 2 Estimated for Fepro generator according to T'd T'd 0 (X'd)/(Xd), where T'd 0 (open circuit transient time constant) Reference [] 30

31 3.2.3 Generator Capacity Considerations All of the subject generators were rated and approved to produce 500 kw or less. All of the generators are synchronous machines that are directly connected without the use of inverters. With this direct generator connection, the generator impedances directly impact the magnitude of fault current contribution from the generators and the unbalanced negative and zerosequence current that flows in the generator caused by voltage unbalance on the feeder. All generator impedance information must be verified to be correct from manufacturer data sheets prior to fault studies. Also, the kva rating upon which the per-unit impedances are based is extremely important. Higher kva generators yield higher fault currents. The data sheets provided for the biogas generators revealed kva ratings that are considerably higher than the approved kw rating of the facility. The sub-transient (T d) and transient time constants (T d) determine how quickly the generator ac fault currents decay. The generator data sheets also revealed transient time constants (T d) that ranged from to seconds. These times are much shorter those of larger synchronous machines that are typically from 0.5 to 2 seconds. Steady-state (synchronous) fault studies may be required to establish settings for timed protection elements when the time delays approach the generator transient time constants. The quality of the gas and fuel delivery system can result in the occasional sudden momentary fluctuations in power delivery that can contribute to power swings and in extreme cases reversepower (motoring) conditions DG Grounding Considerations All of the subject interconnection transformers (DGIT) are Y-gnd:Y-gnd and all of the generators are star-connected. These winding configurations were preferred because of cost considerations for the DGIT and interconnection protections as detailed below. With the Y-gnd:Y-gnd DGIT configuration, the impedance of DGIT winding neutral connections and the generator neutral connection impact the effectiveness of DG facility grounding. Small impedances, especially in the LV grounded neutral connections, can cause profound reductions in zero-sequence DG current in-feeds to faults on the Distribution System. Although the subject DGIT neutral connections are all solidly-grounded, they do not provide an effectively grounded connection to the Distribution System unless the generator neutral connection is also solidlygrounded. Solid grounding of a generator neutral is not generally used for large generator greater than 10 MVA since this practice may result in high mechanical stresses and excessive fault damage in the machine. 3 According to IEEE C , the maximum stresses that a generator is normally designed to withstand is that associated with the currents of a three-phase fault at the machine terminals. Because of the relatively low zero-sequence impedance inherent in most synchronous generators, a solid phase-to-ground fault at the machine terminals will produce winding currents that are higher than those for a three-phase fault. Therefore, to comply with 3 IEEE Std C IEEE GUIDE FOR AC GENERATOR PROTECTION Section

32 this standard, generators of this size must be grounded in such a manner to limit the maximum phase-to-ground fault current to a magnitude equal to, or less than, the three-phase fault current. Only one of the generator neutrals (Terryland G1) is solidly-grounded to provide an effectively grounded connection to the Distribution System. This was done in consultation with the generator supplier and the utility. All of the other generators are grounded through neutral grounding resistors. The rationale for solidly grounded G1 is beyond the scope of this report Impact of Voltage Unbalance and Supply interruptions In comparison to load customers, 3-phase generators are much more sensitive to unbalance voltage conditions and momentary supply interruptions. DG sources are required to have sensitive interconnection protections to detect and disconnect for unbalance voltage conditions, faults at all locations of the supply feeder and island conditions. These conditions can be difficult to distinguish from transient conditions that do not require them to disconnect. There is no requirement for load customers to have protections to detect faults on the Distribution System. 3-phase machines have zero tolerance to loss-of-phase conditions associated with single-phase recloser operation and low tolerance to 3-phase unbalance voltage conditions. 3-phase synchronous generators are prone to over-heating and damage when negativesequence current becomes too large. The most common causes are system asymmetries (untransposed lines), unbalanced loads, unbalanced system faults, and open phases 4. These system conditions produce negative-sequence currents which induce a double-frequency current in the surface of the rotor, the retaining rings, the slot wedges, and to a smaller degree, in the field winding. These rotor currents may cause high and possibly dangerous temperatures in a very short time. As a result generator protections are required to respect the continuous and short-time negative-sequence current ratings of the generators. Negative-sequence current unbalance in the generator is directly proportional to the negativesequence voltage unbalance at the PCC location. The negative-sequence current is limited only by the sum of the DGIT impedance and generator negative-sequence impedance (X 2 ). Negative-sequence impedances for the DGIT and generator are independent on neutral grounding connections and cannot practically be changed by external components. Slower restoration of generation following momentary supply interruptions has more profound effects on production losses and costs. This is because generators must wait for voltage and frequency to stabilize before reconnection. This delay could be up to 5 minutes, whereas load is automatically reconnected as soon as the supply is restored. 4 IEEE Std C IEEE GUIDE FOR AC GENERATOR PROTECTION Section

33 4 Feeder Protections Protections are required to isolate all sources of supply from any fault (short-circuit condition) that can occur along the feeder. Hydro One uses feeder protections to trip circuit breakers at Transformer Stations (TS) and reclosers at Distribution Stations (DS). Also, for long rural feeders, Hydro One feeder protections may include in-line reclosers along the main feeder trunk and fuses on the branches of lateral connections. These downstream protections are used to partition the feeders into smaller sections reducing the number of customers that will be without power to the faulted sections only. Distributed Generators are also required to have Interconnection (or Inter-tie) Protections to detect and isolate their supply sources from any fault that can occur along the feeder. The magnitude of current in-feeds to faults at the protection locations varies widely depending on the feeder impedance from the source location to the fault. Since feeder impedance is basically a linear function of distance (ohms/km), the current in-feeds effectively vary with the distance from the source to the fault. The magnitude of total fault current is increased as additional DG supply sources are connected to a feeder. However, in the presence of additional sources, the magnitude of individual current in-feed from each separate source can be significantly reduced because of this increased total fault current. This occurs when the fault location is on a portion of the feeder that is beyond the interconnection point where the currents from each source sum together. The higher total fault currents from the summation point to the fault location results in higher voltages at the summation point. The higher voltage at the summation point decreases the voltage difference from each source to the summation point, effectively reducing the current in-feed from each source to the fault. This is referred to as the apparent effect and must be taken into account when designing the protection settings. The apparent effect is most pronounced for the weaker (DG) sources whose source impedances are generally much higher than the Hydro One source. Current in-feeds from slower-clearing sources will increase when other faster-clearing sources isolate themselves from the fault. For DG s that effect may be offset by the naturally decaying fault in-feed that occurs as time progresses from sub-transient to steady-state conditions. 4.1 Faults Studies Faults at PCC Table 5 shows the minimum expected in-feed from Hydro One (and other DG sources on the feeder where present) to faults at the PCC. This current would flow through the fuses located at the PCC for the faulted phases for a fault on the DG side of the PCC. 33

34 Table 5 - Minimum Feeder In-feeds to Faults on the DG side of the PCC Fault Type Terryland Farms Fepro Farms Ledgecroft Farms 3Ø 1450 A 1142 A 409 A Ø-Ø 1256 A 988 A 340 A Ø-gnd 1161 A 951 A 288 A Ø-Ø gnd 1344 A 1064 A 364 A Fault Studies to determine minimum in-feed conditions Fault studies are based on models that are only approximations to real life conditions. The accuracy of the fault studies depends on the accuracy of the impedance models of all sources connected to the feeder as well as the feeder circuit impedances. Protection settings must incorporate sufficient margin to allow for cumulative inaccuracies for system models, fault resistance and instrumentation etc. To minimize inaccuracies, the studies should be based on the best available installed equipment information for the Distribution System and the DG facilities. Fault studies for protection design need to consider the extreme conditions required for protection sensitivity. The protection at every supply point to the feeder must be set to detect the lowest fault in-feed condition at the point where the voltages and currents are measured. In order to establish the lowest fault in-feed condition at a given supply point, the following basic rule of thumb is used. Select a pre-fault operating condition whereby the source under study is at the minimum expected capacity and all other sources connected to the feeder are at the maximum expected capacity. The pre-fault load conditions of the generators and load customers on the feeder also have an effect on the distribution of fault currents from the sources. Unloaded generators that are synchronizing or shutting down contribute lower fault current. All of the Interconnection Protections for the Biogas DG connections have been designed to measure currents and voltages on the generator side of the DGIT. Table 6 shows the results of fault studies used to determine the lowest fault in-feed conditions at these locations. This Table includes different values for sub-transient, transient and steady-state periods. These correspond to sub-transient, transient and synchronous impedances associated with the synchronous generators that are classically used by fault studies to approximate their exponentially decaying fault current in-feeds. 5 Sub-transient fault values should be used for instantaneous protection elements (without any intentional time delay). Transient fault values should be used for protection elements that use short time delays to the Transient time (T d). Steady State values should only be required for time delays beyond T d. Medium to large generators are seldom concerned about the Steady State studies because the generator T d is typically 0.5 seconds or longer, much longer that the time delays used by the protection elements. However T d for the small biogas generators are 5 Reference 17 34

35 much shorter (as low as 80 ms) and may need to be considered when incorporating delays to avoid nuisance trips. The values shown in Table 6 are results from most recent studies. These fault studies were conducted with both Hydro One and DG connected. Some results are different than those used at the time of the protection design because of subsequent software revisions to correct some latent calculation problems. The more recent fault studies include steady-state (synchronous) studies for Fepro and Ledgecroft. Steady-state studies are not shown for Terryland because the software product used did not have a Steady State study option. Table 6 includes the positive, negative and zero sequence values as well as the individual phase values. The following observations can be made: a. For 3Ø faults, the individual phase values and the positive-sequence currents are the same. Protection settings for current elements used to detect phase faults are usually based on these values. b. The phase fault currents for Ø-Ø and Ø-Ø-gnd faults are similar and are slightly less than the 3Ø fault values. Phase over-current elements set to 50% of the 3Ø fault values should be effective in clearing Ø-Ø and Ø-Ø-gnd faults also. c. The phase currents for SLG fault levels are lower than for 3Ø faults. Generally ground elements (3I0 or 3V0) or negative-sequence current or voltage elements are used to detect these types of faults. Hydro One standard practice is to conduct only 3Ø fault and SLG fault studies since those studies should be sufficient for the derivation of protection settings. 35

36 Table 6 DG lowest fault in-feed conditions Terryland Farms G2 Fepro Farms G1 Ledgecroft Farms G1 Fault type / Location Transient Transient Steady State Subtransient Subtransient Subtransient Transient Steady State Node Ø Ø-Ø SLG Ø-Ø gnd I A 486 A 340 A 2136 A 1743 A 173 A 3018 A 2574 A 300 A I B 486 A 340 A 2136 A 1743 A 173 A 3018 A 2574 A 300 A I C 486 A 340 A 2136 A 1743 A 173 A 3018 A 2574 A 300 A I+ 486 A 340 A 2136 A 1743 A 173 A 3018 A 2574 A 300 A V+ 100 V 98 V 273 V 262 V 216 V 199 V 179 V 84 V V Ø-g 36% 35% 79% 76% 62% 57% 52% 24% Node I A 404 A 340 A 2024 A 1796 A 947 A 2597 A 2366 A 1364 A I B 429 A 368 A 1753 A 1565 A 915 A 2648 A 2468 A 1457 A I C 25 A 73 A 479 A 288 A 739 A 170 A 107 A 1138 A I+ 243 A 171 A 1289 A 1061 A 125 A 1595 A 1381 A 186 A I- 239 A 238 A 898 A 891 A 863 A 1432 A 1412 A 1313 A V+ 113 V 112 V 310 V 303 V 274V 255 V 244 V 186 V V- 13.9V 13.9V 39V 39V 38V 57 V 56 V 52 V V Ø-g 37% 37% 81% 79% 71% 64% 61% 46% Node I A 193 A 164 A 528 A 413 A 271 A 1573 A 1465 A 815 A I B 105 A 94 A 804 A 679 A 319 A 859 A 819 A 706 A I C 88 A 76 A 1072 A 941 A 396 A 729 A 646 A 634 A I+ 97 A 68 A 763 A 630 A 76 A 851 A 746 A 107 A I- 96 A 95 A 331 A 330 A 324 A 723 A 722 A 714 A 3I A 0.31 A 0.42 A 0.43 A 0.42 A 1.03 A 1.03 A 1.02 A V- 5.6 V 5.6 V 13.7 V 13.6 V 13.4 V 30.7 V 30.7 V 30.4 V 3V V 21.4 V 90.9 V 90.5 V 88.9 V 215 V 215 V 213 V V Ø-g 39% 39% 84% 83% 79% 54% 52% 42% Node I A 404 A 325 A 2006 A 1745 A 775 A 2621 A 2352 A 1153 A I B 434 A 359 A 1822 A 1590 A 755 A 2653 A 2436 A 1251 A I C 94 A 34 A 770 A 517 A 544 A 620 A 401 A 891 A I+ 285 A 200A 1460 A 1201 A 141A 1821 A 1574 A 210 A I- 197 A 196 A 716 A 710 A 685 A 1202 A 1182 A 1089 A 3I A 0.26 A 0.48 A 0.48 A 0.47 A 1.26 A 1.25 A 1.16 A V V 11.4 V 31.4 V 31.2 V 30.1 V 48 V 47 V 44 V 3V V 18.7 V 98.9 V 98.1 V 94.7 V 257 V 253 V 234 V V Ø-g 36% 36% 76% 74% 65% 49% 46% 29% 36

37 4.2 Utility Feeder Protections Feeder Fuses Fuses are used at the HV connection point to the HV windings of all customer transformers. They are also used on single-phase lateral connection points. Fuses are intended to selectively isolate all permanent faults on the feeder or within a customer facility to minimize interruption to customers connected to un-faulted sections of the feeder Feeder Reclosers The Hydro One reclosers installed on the F Class feeders use single-pole interrupters. Reclosers are located at the DS and in-line reclosers are used strategically along the main feeder trunk and on 3-phase lateral branch connection points. The protections used for these single-pole interrupters isolate only the poles connected to the faulted phases. For a single-phase-ground (SLG) fault on the feeder, only recloser pole interrupter connected to the faulted phase will be opened, leaving the un-faulted phases connected to the Hydro One supply. Recloser protections typically have one fast and three slow inverse-time operating characteristics. The fast characteristic is used only for detecting and clearing the first occurrence of a fault. Operation of the fast characteristic for the first fault is intended to minimize melting of fuses along the feeder for transient faults 6. It is required that all significant sources of in-feed along the feeder operate without any intentional time delay. That includes all utility (Hydro One) sources and all DG that are judged to supply sufficient fault current to operate any in-line fuses along the feeder. Some delay can be tolerated for DG supplying only low-level fault in-feeds providing that the delay does not cause fuses to be damaged and the DG disconnect time does not impair automatic restoration attempts. Protections that operate without any intentional time delay are inherently non-selective and result in momentary interruption of all customers along the feeder. However after the first automatic reclose attempt, all customers are quickly restored if the fault does not reoccur following re-energization of the feeder. This is a necessary trade-off to maintain reliability to load customers on the Distribution System. Only the slow inverse-time operating characteristics are used during subsequent automatic reclosing operations. This allows the simple inverse-time radial coordination of utility protection equipment (reclosers and fuses) along the feeder to selectively isolate any permanent faulted sections and avoid prolonged interruption of load customers connected to un-faulted sections. DG must be disconnected for this coordination to be effective. Reclosers along the main feeder trunk between the DG and the supply DS are directioned as required to prevent operation from DG back-feeds. That avoids unnecessary recloser operation 6 The vast majority of faults on feeders with over head conductors are transient, caused by lightning, wind, tree contact etc. 37

38 for upstream faults (on the utility supply side of the recloser), on lateral feeder branches or on other feeders connected to a DS. The Beachburg DS recloser required directioning for this reason. Opening of one or two recloser poles for unbalanced faults on the feeder (SLG and LLG) can create a large momentary voltage unbalance on the feeder, downstream of the open recloser. This unbalance will persist until healthy 3-phase balanced voltages can be restored. Prolonged 3-phase voltage unbalance cannot be avoided for permanent unbalanced faults where automatic reclosing will be unsuccessful. Prolonged 3-phase voltage unbalance can potentially harm customers that use 3-phase rotating machines (3-phase motors or generators). It is expected that such customers utilize adequate unbalance protections to protect their machines from any prolonged harmful voltage unbalance conditions that cannot be avoided on 3-phase 4- wire Distribution Systems. 4.3 DG Protections The Interconnection (Intertie) Protection Scheme The main purpose of the Interconnection protection is to protect the utility. The protection scheme is comprised of a combination of: a) Protective elements, such as over current elements that respond to high levels of currents b) Timers which can be set to delay the trip output or sustain a trip output c) Status inputs that monitor the position of a device such as the circuit breaker that connects the generator to the grid Logic is used to put all the above into a scheme that provide the desired output response under a number of normal and abnormal power system conditions. Normal conditions, from the DG s perspective, are when generator is connected to grid and delivering power. There are two abnormal conditions that the intertie protection must detect and disconnect the generator from the grid. The first abnormal condition is a distribution system fault, such as a short circuit. The intertie protection has a sub-category, line protection, which is designed to detect the fault condition and trip the generator. The second abnormal condition is when the grid breaks up into sections and a portion of the grid remains connected to the generator. This is referred to as a generation island. This situation can result in poor power quality being delivered to customers in the generation island to the point where utility or customer equipment is damaged. The intertie protection has a sub-category, anti-islanding protection, to detect this condition and disconnect the generator. Ideally, the DG line protection should only operate for faults that are not going to be isolated by the utility protection. However, it is often impossible for the DG line protection to discern between faults at one location where it should operate, and another where it should not. One way to improve the performance and make the protection more selective is to add communications between the utility terminal and the DG. Transfer trip is one such communication scheme. When a fault or island condition occurs on the utility, a signal is sent from the utility to the DG to disconnect from the grid. Another approach to achieving the 38

39 selectivity is to add time delays. For two of the installations, time delays were utilized for economic reasons. Ideally, the DG anti-islanding protection should only operate if there is a generation island. However, since the scheme is comprised of a series of protection elements similar to the line protection, these elements are often unable to discern between a fault condition and an island condition. In situations where the fault location is such that the desired response is for the generator to remain connected to the grid, operation of this protection is not ideal DG HV Fuses HV fuses are used at the PCC to provide protections for the DGIT and HV faults within the DG facility. Table 7 - DG HV Fuse Project Terryland Farms Fepro Farms Ledgecroft Farms Manufacturer S&C Positrol S&C Positrol Cooper Type K-speed K-speed QA Current rating 30 A 50A 50 A DG Interconnection Protections Table 8 Interconnection Protection Specifications Project Terryland Farms G2 Fepro Farms Ledgecroft Farms Manufacturer GE Schweitzer (added May 2 for TT) GE Model G650 SEL-351S-7 F60 CT location 52-L breaker (Generator side) 52G (Utility side) LED-52 breaker (Utility side) CT ratio 300:5A 600:5 A 800:5 A VT location 52-L breaker (Utility side) 52G (Utility side) LED-52 breaker (Utility side) VT ratio 277 / 120 = :1 347 / 69.3 = 5:1 Device tripped 52-L2 52G LED-52 Operation time 6 ms 30 ms 57 ms (fault clearing time) All of the interconnection protections are connected to VT s and CT s connected on the generator side of the DGIT. This results in cost savings for protections, avoiding the higher costs of HV instrument transformers DG Anti-islanding Protections Based on IEEE Standard Section 4, DG s connected to Distributions Systems are not allowed sustain an island beyond 2 seconds. Shorter Hydro One recloser times require faster disconnection of DG. The DG must also cease to energize the Distribution System for abnormal conditions such as power faults and insure that they do this prior to reclosure by the 39

40 utility, to avoid asynchronous paralleling. Providing the DG capacity is low enough to guarantee disconnection within the required times, DG can meet these requirements by using basic voltage and frequency based timed protection elements, supplemented with enhanced protection elements such as reverse power flow, rate of change of frequency (ROCOF) and voltage vector-shift elements. When the DG capacity is too large for such assurance, Transfer Trip from the Utility protections is usually required, as discussed below. Table 9 Interconnection Protection Elements that Respond to DG Island Conditions Fault type IEEE # Function Terryland Farms Ledgecroft Fepro Farms G2 Farms TT Transfer Trip Not used Installed in May Not Used 27-1 under-voltage 88% 88% sec 1.6 sec 80% - 2 sec 27-2 under-voltage 50% sec 50% sec 75% sec 59-1 over-voltage 110% sec 110% sec 110% - 1 sec 59-2 over-voltage 120% sec 120% sec 120% sec 81 over-frequency 60.5Hz sec 60.5Hz sec 60.5Hz sec Anti-islanding 81-1 under-frequency 59 Hz sec Not used 59.8Hz sec Elements 81-2 under-frequency 57 Hz sec 57 Hz sec 57 Hz sec 81R ROCOF 0.4Hz/sec sec 6 Hz /sec 78 vector-shift 4 See generator protection 32 power export limit Active kw (120%) 0.4 sec (export limiting) Not required with TT Reactive kvar.25 sec Hydro One interrupting devices (reclosers or circuit breakers) have an inherent advantage over protections at DG connection points because they are located near the strongest source and measure the largest fault currents. Operation of these devices creates DG island conditions. Thus, these protections are at a better position to initiate a preventive action such that the island condition is not sustained. Current magnitude or direction is used as required to distinguish between down-stream faults on the feeder and upstream faults that are not on the feeder and avoid nuisance trips. From the DG protection vantage point, all faults on the Distribution System are in the same direction so they can not anticipate when an island is about to occur due to a fault. Also, depending upon the DGIT configuration the zero-sequence current contribution from DG facility could be minimal. Hydro One practices single-phase tripping to clear faults in F class feeders. Single-phase tripping results in additional unbalances seen by DG protections. Negative-sequence current protection can also be relied upon for detecting this condition. High security for the island protection can be achieved at the cost of some nuisance trips. Opening of the interrupting devices located upstream of DG PCC can create an island with no fault connected to the island. This condition is more stringent from DG protection perspective as there is no fault current to measure. The operation of the DG local anti-islanding protection 40

41 is then entirely dependent upon the miss-match between generation and the islanded load and/or subsequent unpredictable changes in load. In order to deploy a deterministic anti-island protection that is immune to nuisance trips, the Transfer Trip (TT) can be used to convey the protection intelligence from the Hydro One supply points to the DG connection that a DG islands is about to be created. A fast TT signal will guarantee a timely disconnection of the DG on the feeder. Hydro One requires Transfer Trip (TT) when the ratio of generation capacity to minimum feeder load is greater than 50%. When this ratio is exceeded it is considered that DG local antiislanding protections cannot be relied upon to disconnect the generator within normal automatic reclosing time-frames. When TT is used, Hydro One requires only the basic voltage and frequency based timed protection elements to be used by the DG Interconnection Protections. However, the cost of providing Transfer Trip is independent of the size of the project and can represent a formidable percentage of the total project cost for small biogas projects. Due to the cost implications on smaller projects, Hydro One does not require TT for the generation projects with a capacity of 500 KW or less. Transfer Trip from Hydro One was used for only one project (Fepro Farms) because the total installed capacity exceeded 500 KW. TT was added to Fepro Farms during the period of this monitoring project because the addition of 175 kw of Solar generation capacity increased the total capacity to greater than 500 KW DG Protections to detect Feeder faults Protection settings of Table 10 were based on minimum fault conditions as outlined in Section 4.1. The DG interconnection protections are required to detect faults at all locations of the feeder and open all supply connections. That includes faults at all locations from the PCC to the DS and the ends of the main feeder trunk and at the furthest locations of lateral branch connections. In most cases it is virtually impossible for local DG interconnection protections by themselves to be set sensitive enough to detect faults at all of these locations without detecting faults on other feeders as well. Nuisance tripping can be reduced by delaying operation of the local interconnection protections until Hydro One protections have a chance to clear faults at other feeder locations. The net clearance times of the fastest Hydro One protections may be as long as 100 ms, including the opening time of the reclosers. Delaying the Biogas interconnections too much increases the risk that prolonged DG in-feed may cause fuses to melt and cause unnecessary thermal damage for transient faults. Delays also increases the risk that DG fault in-feeds may naturally decay beneath practical setting levels and increases the risk that the DG s may still be connected when the Hydro One sources recloses. All of the DG protection instrument transformers for these projects sense voltages and currents on the generator LV side of the DGIT. Settings must distinguish between minimum fault and maximum load conditions as sensed by the DG protections. Typically over-current protections are set to about 50% of the measured minimum fault condition when there is sufficient margin from maximum load conditions to avoid nuisance operations. That margin accommodates some 41

42 variation of fault currents due to fault resistance, fault types and inaccuracies of the protection and system models. Table 10 Interconnection Protection Elements that Respond to Feeder faults Fault type Phase Elements 50N over-current 0.2 A 0.15 sec (9~) Not used 1.44 A 0.25 sec (15~) Sync-check and Breaker fail protections Table 11 outlines some other basic features that are required to be used by DG interconnection protections to avoid adverse impacts of DG connections. They include sync-check elements to block DG connections when there is significant mismatch in frequency, voltage or phase angle, and breaker failure to effectively disconnect or de-energize DG sources when the main devices fail to disconnect. Table 11 Other Interconnection Protection Features Breaker Fail IEEE Terryland Farms Function # G2 Fepro Farms Ledgecroft Farms 50 over-current 2400 A Instant A Instant. Not used 50 over-current 600 A 0.1sec (6~) 900 A 0.15 sec (9~) 1443 A 0.25 sec (15~) 51 inverse-time IEEE Ext. Inv IEC Ext. Inv. 300 A 560 A over-current TD 0.1 TD 0.05 Not used 67 directional Instant.(see Not used Not used 1509 A over-current Note 2) 27 undervoltage 83.3% Instant. Not used Not used 59G over-voltage 4% 0.3 sec (18~) 5% 0.4 sec (24~) 69.4 V 1 sec (60~) negativesequence Ground 46 Elements over-current 60 A 0.15 sec (9~) 150 A 0.4 sec (24~) 336A 0.25 sec (15~) negativesequence 47 over-voltage 4% 0.3 sec (18~) 4% 0.4 sec (24~) 69.4 V 1.0 sec (60~) Rated Current 271 A 644 A 480 A Note 1: All set point AC values in Table 10 below are on the 480 V bus for Terryland and on the 600 V bus for Fepro and Ledgecroft. Note 2: The 67 element at Ledgecroft uses protection logic to distinguish between LLL, LL and SLG faults. It only operates for LL or LLL faults on the distribution system Synchcheck Project Terryland Farms G2 Fepro Farms Ledgecroft Farms Time (sec) 0.25 sec 0.3 sec N/A Δ f 0.3 Hz 0.2Hz 0.1 Hz Δ V 10% 3% 0.5% Δ angle Generator Protections The main purpose of the generator protection is to protect the machine, the generator. The Generator protections use some protection elements that are similar to the feeder protections. Some of these elements may respond to some faults or other disturbances on the distribution system. This results in two problems. First if the fault is on the distribution system, it is not necessary to disconnect the generator. Second, operation of the generator protection is an 42

43 indication that there is a problem in the machine. If that is the case, the generator should not be reconnected to the grid as this could result in damage to the generator, the interconnecting equipment and possibly the grid. The generator needs to be inspected before it is re-energized. Another issue is what types of protection are contained within the generator protection and control system. A number of engine-generator suppliers have included anti-islanding protection, and even line protection, within their generator protection and control system package. This may result in a conflict in the desired response. Let us assume that the goal is to have the antiislanding scheme contained in the intertie protection perform all the anti-islanding functions. If for example, as part of an anti-islanding scheme contained within the generator protection and control system s set to trip the generator when the voltage goes below 95% of nominal, and the anti-islanding protection contained within the intertie protection is set to only operate when the voltage goes below 90% of nominal, then the anti-islanding protection contained within the generator protection will have tripped the generator prematurely, an undesirable result. It is good practice for the generator protection to act as backup for the intertie protection and vice versa. This means that these two protections must be designed and set to work in unison and not in conflict as described above. A similar situation exists with the co-existence of the intertie protection and the utility protection i.e., they must work in unison and not in conflict to prevent unnecessary disconnection of the generator from the grid. Throughout this report, where the response of a protection scheme is not ideal and results in an unnecessary disconnection of the generator from the grid, the event is referred to as a nuisance trip. Table 12 Generator Protection Design Project Terryland Farms G2 Fepro Farms Ledgecroft Farms Manufacturer Beckwith GE Jenbacher Model M3410A SEG MRG3, DEIF DIANE, DEIF CT location 52G2 (gen side) Generator breaker DEB-52,Generator breaker (gen side) CT ratio 300:5A 600:5 A 600:5 A VT location 52G2 (Utility side) Generator breaker Both utility and gen side of breaker VT ratio Direct connect to 277V phase-ground 347V/120V Device tripped 52G2 52G DEB-52 43

44 Table 13 Generator Protection Elements that may respond to Island conditions Project Terryland Farms G2 Fepro Farms Ledgecroft Farms under-voltage 1 88% 3 sec 90% 1 sec (MRG3) 90% 1 sec (DEIF) 27 under-voltage 2 50% sec 80% 0.2 sec (MRG3) 80% 0.2 sec (DEIF) 32 reverse power 13.5 kw 6% of 225 kva 0.5 sec 0.32 x P N 0.5 sec (DIANE) 0.32 x P N 0.5 sec (DIANE) over-voltage 1 110% 3.0 sec 110% 30 sec (MRG3) 110% 30 sec (DEIF) 59 over-voltage 2 120% 0.2 sec 115% 0.2 sec (MRG3) 115% 0.2 sec (DEIF) 59I peak over-voltage 120% 0.2 sec function not available function not available 81u under-frequency 57 Hz 59 Hz 0.5 sec (MRG3) 59 Hz 0.5 sec (DEIF) 1 sec 1 under-frequency 58.5 Hz 0.1 sec 58.5 Hz 0.1 sec (DEIF) 2 81o over-frequency 62 Hz 1 sec 61.5 Hz 0.1 sec 61.5 Hz 0.1 sec (DEIF) 78 vector-shift See interconnection 4 4 cycles 15 No delay (DEIF) protection Table 14 Generator Protection Elements that may respond to Fault conditions Project Terryland Farms G2 Fepro Farms Ledgecroft Farms 50 over-current 1 over-current 2 51 inverse-timed over-current Inverse timed over-current 51V (voltage restrained) 50N 51G 64 / 59N FL neutral current Inverse timed zero-sequence over-current unbalance voltage (3V 0 ) loss of field 1 loss of field 2 negativesequence overcurrent negativesequence overvoltage Fuse Loss x I 7 N = 819A x I N = 1950A 0.2 sec 0.3 sec 2.5 x I N = 3125 A 272 A x6 at 3s - 30% x I N = 375 A 406 A IEC Inverse TD = sec (DIANE) 1 sec (DIANE) 1 A 0.2 sec 30% x I N = 234 A 1 sec A IEC Inverse - - TD = % 3 sec (DIANE) D=1.0 pu, O=0.1pu D=3.0 pu, O=0.1pu 54.2 A 20% of 271.2A) sec 1 sec K =10 sec EN No delay 50V (DIANE) - - t= (I2/In)2 x tz tz = 20 sec EN t= (I2/In)2 x tz tz = 20 sec (DIANE) 4% 3 sec 4% 0.3 sec 4% 3 sec (DIANE) sec I N = 1250A for Ledgecroft 44

45 52G Generator Circuit Breaker overload 272 A X6 at 3 sec 51 short-time overcurrent 640 A 0.8 / 1.0 sec 400 A X8 at 0.1 sec 1600 A 2.0 / 0.3 sec 5960 A No delay 0.8 x I GS = 640 A 2 x 0.8 x I GS = 1280 A 10 x I GS = 8000 A 1 sec 0.3 sec No delay 45

46 5 Monitoring Methodology Each event was analyzed jointly by the project team members by correlating the oscillograph records from protection elements of interconnection protection relays that triggered the records with corresponding Hydro One PQ web data. 5.1 Monitoring At DG Sites The Oscillograph records related to events (pick up of protection elements of interconnection protection relays that triggered oscillograph records) at each site were collected from the interconnection protection relays. Records were also collected from the revenue meters equipped with power quality features (ION 8600) through Hydro One PQ web. Table 15 Interconnection Protection Monitoring Project Terryland Farms G2 Fepro Farms Ledgecroft Farms Data Log Oscillograph Event log Fault Report Va, Vb, Vc Ia, Ib, Ic P, Q V0, V2 Frequency Va, Vb, Vc Ia, Ib, Ic Vs, Ig, Isg Breaker status changes (52G, 52L, 52L on G1) Protection pickups and dropouts (except 51, 32 & ROCOF) Protection calls (all protections) Used oscillograph and event log Not used Ia, Ib, Ic, In, Ig Va, Vb, Vc, Vs, Vdc I0, I1, I2. V0, V1, V2 Frequency Boolean inputs and outputs, protection calls, timeouts, relay alarm and pushbuttons Used oscillograph and event log Va, Vb, Vc Ia, Ib, Ic P, Q V0, V2. I2 Va, Vb, Vc Ia, Ib, Ic, V&I Angles ROCOF Freq P and Q all active protection element operations all active virtual output operations breaker status alarm input operations Breaker status change alarm status change virtual output status change pickup and dropout of all active protection elements Alarms for UV, OV, V0, V2 Time and date of fault magnitude and angle of V &I pre-fault and fault, listing of protection elements that operated 46

47 5.2 Power Quality Monitoring At Hydro One DS and DG facilities Event records were collected through Hydro One PQ web from the revenue meters with power quality functionality (ION 8600/7650) connected at the biogas generation sites and at the Distribution Station supply point locations of the respective distribution. Following is the PQ web specifications. a) 10 minute samples (additional custom framework): THD i, THD v, THD even and THD odd V unbal, V s2/s1, V s0/s1, V pos seq mag I unbal, I s2 / s1, I s0 / s1, I pos seq mag V a, V b, V c, V avg, I a, I b, I c and I avg Frequency (Also being captured in the event log low set point is and high set point is 60.02) P a, P b, P c, P Total, Q a, Q b, Q c, Q Total, VA a, VA b, VA c, VA Total, pf a, pf b, pf c, and pf Total b) 15 minute samples (factory default framework): mean, high and low V LL and V avg mean, high and low I a, I b, I c and I avg mean, high and low P Total, Q Total and VA Total mean, high and low frequency c) Hourly samples (factory default framework): I a, I b, I c, V a, V b, and V c THD mean and THD high d) Also being recorded and downloaded: Time in EST (all timestamps are EST) Sag/swell events, threshold set at 92% and 106% of nominal voltage, waveform captured at 128 samples/cycle for 14 cycles, 4 cycle pre event and 10 cycle post event These provides Oscillograph record which are most useful for protection analysis e) Transient capture is not available in the ION

48 6 Events and Observations 6.1 Events at Terryland Farms Over the study period there were a total of 59 oscillograph records captured by the Terryland Interconnection Protection relay. Based on these records, 50 events occurred when the generator was on-line and resulted in the generator being disconnected (tripped). The on-line trip events that were captured were analyzed and classified as power swings (33) faults (10), unbalance conditions (5), an open phase condition (1 event) and a breaker open event (1). Figure 3 Terryland Trip Event Records Event Type Descriptions Total Terryland Trip Event Summary Power Swing 33 Supply Feeder Faults SLG 1 Supply Feeder Fault (to DS) 1 SLG 6 Other Feeder Faults Ø Ø 2 Unbalance (Zero Sequence) 5 Supply Feeder Open Phase 1 Breaker Opened 1 Grand Total 50 There were 33 oscillatory Power Swing events. There were no apparent faults on the feeder during these events. 3-phase currents decreased at the beginning of these power swings. The magnitude of the generator terminal voltages appear to be relatively stable, although there were changes in phase angle that were detected by the anti-islanding protections. The 3-phase current oscillations have a similar wave-shape and envelope frequency to oscillatory power swings observed for the Ledgecroft associated with Generator gas controls. However analysis of the Terryland current vectors showed that they remained in Active Power direction viz. the forward (generating) direction. There were 10 Feeder Fault events. 2 of these were on the kv F3 Supply Feeder from Stardale DS. The other 8 Faults were at other locations. The negative sequence overcurrent protection was designed with a 9 cycle time-out, but was required to be implemented with an immediate commitment to trip on pick-up. As all the events showed a feeder disturbance lasting for at most 7 cycles, the protection, as designed, would not therefore have caused a trip. 48

49 There were 5 events that appear to have been triggered by Interconnection Protection Zero- Sequence elements response to Feeder Unbalance. There was 1 event that appears to have been caused by an Open Phase on the Supply feeder. Finally there was 1 event that appears to have been caused by the Opening of the Generator breaker (cause unknown). These events will be discussed in further detail in the following sections. Figure 4 Terryland Hour-of-Day distribution for Event Types A check of the hourly distribution of events reveals a heavy weighting of the Power Swing events to evening hours. 49

50 6.1.1 Terryland 3-Phase Power Swing Events There were 33 Power Swing events, 32 of which caused a fast trip of the generator G2. This accounted for 66% of the trip events. In each of these cases, that protection element that responded (vector-shift, ROCOF and power export limit elements) was intended for the fast detection of anti-islanding conditions. None of the trips were related to actual islanding conditions however. Most of the power swings occurred after 6 pm, with the highest frequency occurring in the 23rd hour. According to the owner, there were no electrical events happening on the farm at this time. Figure 5 Terryland Power Swing Events - Hour-of- Day distribution Table 16 Terryland Protection Element Response to 3-Phase Active Power Swing Events Event Response Total Remarks Power Swing Vector Shift (1P) Fast Trip 27 These occurred before protection algorithm was changed from 1P to 3P Vector Shift (1P) No Trip 4 These occurred after protection algorithm was changed from 1P to 3P Vector Shift (3P) Fast Trip 1 This occurred after protection algorithm was changed from 1P to 3P Power Export Fast Trip 4 These occurred In August ROCOF Timed Trip 1 This occurred in August Grand Total 37 Analysis of these Power Swing events determined that there were no apparent faults on the feeder. For many of these events, the sensitive generator vector-shift protection responded so quickly that the power swing was interrupted at the beginning of its natural cycle. The magnitude of the generator terminal voltages appeared to be relatively stable throughout the swing, although there were detectable shifts in the voltage phase angles to which the generator vectorshift protection responded. In every case, the power swing began with a prominent decrease in all 3-phase currents. After the generator vector-shift protection was changed to reduce the occurrence of nuisance trips the nature of some full cycle power swings became apparent. 50

51 It is noted that all of the power swings at Terryland involved all 3-phase currents which is typical of generator mode oscillations. Generator mode oscillations can occur between the generator and the large power system (Plant Mode), or between generators (Inter-Machine Mode, Inter- Plant Mode or Inter-Area Mode). Terryland is the only facility where there is more than one generator; however these generators are not paralleled at the generator terminals, separate DGITs are used for each. The Terryland 3-phase current oscillations that persisted for at least one natural cycle appears to have a similar wave-shape and envelope frequency to oscillatory active 3-phase power swings observed for the Ledgecroft Generator fuel gas events. However analysis of the Terryland current vectors showed that they remained in Active direction viz. the Active Power remained in the forward (generating) direction. Vector-Shift Element Response to Power Swing Events The majority of the Power Swing events where tripped by operation of the vector-shift protection elements (86%). The vector-shift (78V) protection element is intended to detect sudden changes in period (voltage cycle length) when a generator becomes disconnected from the Utility Supply System (island condition). It operates when a cycle-length of the defined number of phase-voltages deviates from the average of the previous 10 cycles by the specified phaseangle amount. At Terryland these protection elements are Fast Trips (trips with no intentional time delay). Initially they were set to respond to a change of period by any single phase-ground voltage (1P). There were a total of 27 vector-shift (1P) Fast Trip events. In time it became apparent that these were nuisance trip operations, with these fast anti-islanding protection elements abruptly responding to the start of recoverable power swings. Figure 6 shows an example of a vectorshift Fast Trip that has a typical profile of these events. For these events there was no discernable change in voltage magnitude or phase angles, but all 3-phase currents showed a significant waveform changes. The current decreased quickly by about 50%, with an abrupt phase-angle change and harmonic content for about 2 cycles. The current then started to increase for about 1 cycle but was abruptly interrupted by the opening of the LV Tie breaker. There were no apparent faults on the Distribution System for these events. The fast clearances of the initial events did not allow the power swing to develop into a full cycle and it was not obvious until later that these transient events were the beginning of power swings. There were 19 Vector-shift (1P) Fast Trips between March 26 and July 19, after which the setting was changed from 4 to 6 degrees. The setting change was intended to reduce the number of trips that were clearly not responding to island conditions. Subsequently there were 8 fast trips vector-shift (1P) Fast Trips between July 19 and August 21. The setting change from 4 to 6 degrees did not appear to effectively reduce the number of nuisance trips. The vectorshift elements responded in a similar fashion to the brief power swings as they had previously. 51

52 Figure 6 Terryland Vector-Shift (1P) Fast Trip Aug 1, :11 OSC 073 Interrupted Power Swing Before algorithm changed The vector-shift protection algorithm was changed on August 21, from requiring only singlephase voltage vector-shift detection to requiring vector-shift detection on all 3-phase voltages. Between August 21 and September 4 there were 4 vector-shift (1P) No Trip responses and 1 vector-shift (3P) Fast Trip event. The changed algorithm reduced the number of vector-shift trips and allowed some power swing records to be captured. Figure 7 shows an example of a single-phase disturbance that would have caused a trip under the previous single-phase algorithm. Figure 7 Terryland 1P Vector-Shift Detection - No Trip Aug 30, :09 OSC 024 Complete Power Swing After algorithm changed The full period of the swing is about 12 cycles (5Hz). Records of phase currents displayed on the same axis clearly show that this is a balanced 3 phase Power Swing. 52

53 The algorithm change did not eliminate nuisance trips for power swings entirely. Figure 8 shows a vector-shift (3P) Fast Trip event on Aug 31, The 3P Fast Trip occurred only about one cycle after the vector-shift (1P) element responded. It appears that the algorithm change can reduce the number but not eliminate the nuisance trips to these types of power swings. Figure 8 Terryland 3P Vector-Shift (3P) Fast Trip Aug 31, :22 OSC 026 Current shows interrupted Power Swing 3P Fast Trip occurred after algorithm changed ROCOF Element Response to Power Swing Event ROCOF operated only once during the study period and that was a timed trip response to a power swing (see Figure 9 below). Figure 9 Terryland ROCOF Trip Aug 24, :55 OSC 007 Current shows interrupted Power Swing ROCOF Fast Trip occurred during the second Power Swing 53

54 Power Export Element Response to Power Swing Events Four Power Export trips were recorded. There was no perceptible change to the currents and voltage magnitudes or phase angles prior to these operations. Following a call to the generator supplier to service the governor, no further trips were recorded. These events may not be actual power swings but have been categorized as such because of the name of the element that operated. Figure 10 Terryland Power Export Trip Aug 1, :50 OSC 071 Waveforms show no perceptible changes to the currents and voltage magnitudes or phase angles 32 Fast Trip occurred during the second Power Swing Terryland Feeder Fault Events There were 10 Distribution System faults that resulted in trips from Terryland G2 Interconnection Protections. 2 of these trips were for faults on the Stardale DS F3 Supply Feeder that supply Terryland. 8 were nuisance trips for faults on the other two feeders supplied by Stardale DS (F1 and F2). In all cases the protection operated correctly as per design. The nuisance trips are a result of design limitation of protection intelligence at the DG location only. Localized protections inherently cannot use fault levels to distinguish precise fault location without the use of strategic intelligence conveyed from protections at other locations. Short time delays of the DG protection elements can be used to allow protections at other locations to clear faults on adjacent feeders or branches that do not require the DG to trip. Table 17 Terryland Feeder Fault Events Event Description 46 Timed Trip 78 (1P) Fast Trip Unknown Event record not available Grand Total Supply Feeder Fault SLG 1 1 Supply Feeder Fault 1 1 Ø Ø (to DS) SLG Other Feeder Fault Ø Ø 2 2 Grand Total

55 The original protection design contained a 9-cycle delay for unbalanced current protections (46 and 50N). The rationale was to trip within 200ms in response to a feeder fault, but to be able to survive a remote short-term unbalanced feeder fault. However, owing to concerns as to the signature of the current at the generator terminals following operation of feeder single-phase protection devices, it was agreed to implement this initially as an instantaneous commitment to trip, but to delay tripping for 9 cycles in order to provide data on current signatures. This led to a number of trips in response to short-duration feeder faults (see Figure 11 below). On 19-Jul-11, the protection was relaxed back to its original design and only one trip in response to a feeder condition was observed (see Figure T.7). Figure 11 Terryland Negative-Sequence elements response to Other Feeder Faults Apr 10, :55 OSC 005 Low level C phase SLG fault Negative Sequence current element (50Q) committed trip Apr 11, :19 OSC 006 Low level C phase SLG fault Negative Sequence current and voltage elements (50Q and 59Q) committed trip 55

56 Figure 12 Terryland Element responses to Stardale F3 SLG Feeder Fault Aug 2, :35 OSC 074 B phase SLG fault on Feeder F3 lateral (note A phase and C phase currents are equal and in phase with each other and 180 degrees from B phase) Vector Shift (1P) Fast Trip Negative Sequence current (50Q) committed trip Negative Sequence voltage,(59q) committed trip Zero Sequence current (50G) time trip Zero Sequence voltage (59N) timed trip Figure 13 Fault on Supply Feeder to Stardale DS Vector Shift (1P) Fast Trip Aug 10, :38 OSC 083 A phase and B phase currents are equal and opposite of each other. This is the expected current in feed to a SLG fault on the 44kV Supply feeder because of the Delta Star DS transformer connection. 56

57 6.1.3 Unbalance (Zero-Sequence) Over the period 23-Jul-11 to 5-Aug-11, there were 5 zero-sequence protection element responses to Feeder Unbalance conditions. During these times, data logs showed that the A- phase voltage was significantly lower than the other phases and the currents were unbalanced. 57

58 Figure 1 Voltage Unbalance at DG of Section shows that there was higher voltage unbalance during this period. No occurrences have been recorded since 5-Aug-11 and this was considered to be a feeder voltage issue that has now been resolved. Event Description 50N Timed Trip 59G Timed Trip Grand Total Zero Sequence Unbalance Figure 14 Typical Terryland Element Responses Feeder Unbalance Jul :24 OSC 003 large current unbalance (B&C phases opposite A phase) Zero Sequence current (50N) timed trip no apparent faults Terryland Breaker Open Event On one occasion the generator breaker appears to have been opened. Figure 15 Terryland Breaker Open Event Apr :00 OSC 003 Vector Shift operated after the current interrupted no apparent faults 58

59 6.2 Events at Fepro Farms Over the study period there were a total of 28 oscillograph records captured by the revenue/power quality meter for the Fepro Biogas generator and 3 oscillograph records captured by the Fepro Biogas Interconnection Protection relay. 19 events occurred when the generator was on-line and resulted in the generator being disconnected (tripped). The on-line trip events that were captured were analyzed and classified as faults (15), unknown current transients (2) and a power swing with the Distribution System (1). Figure 16 Fepro Trip Event Records (Generator On line) Fepro Trip Event Summary Event Type Descriptions SLG Supply Feeder Fault Ø Ø (Beachburg DS F2) 3Ø Total Supply Feeder Fault (to DS) 3 Supply Feeder current transient 2 SLG 1 Other Feeder Fault Ø Ø 2 Power Swing 1 Unknown 1 Grand Total out of the 19 were Fault events. 12 of these were on the Beachburg DS F2 Supply Feeder or on the single circuit supply to Beachburg DS. The other 3 Faults were on the other two feeders supplied by Beachburg DS (F1 and F3). There were 2 events that were caused by some kind of single-phase current transient, perhaps some equipment being energized on the F2 feeder. These current transients did not appear to be caused by faults because Beachburg PQ meter records showed them to be highly distorted and exhibiting exponentially decaying envelopes. There was 1 Power Swing event that resulted in a DG trip although there were numerous other power swings captured by the revenue/power quality meter that did not result in the Fepro Biogas generator being disconnected. There were no apparent faults on the feeder during any of these Power Swing events. The cause of these power swings was not been determined but appears to have persisted after the Fepro Biogas generator was disconnected indicating the power swings involved other customer-connections

60 There was 1 event that caused the Fepro Biogas generator to be disconnected by the generator protection but no useful oscillograph records were produced. These events will be discussed in further detail in the following sections. 60

61 Fepro Protection changes TT at Fepro Farms was installed in May 2011 (near the beginning of the study period) because the addition of the Fepro Solar increased the capacity to beyond 500 kw. The protection used for the F2 recloser at Beachburg DS sends TT to the Fepro DG whenever it operates for downstream faults on the F2 feeder. A vector-shift protection element is no longer required for the Interconnection Protection when TT is used to complement the basic frequency and voltage-based local anti-islanding protection. For this reason the vector-shift protection setting was relaxed from 4 degrees to its default setting of 10 degrees. After TT was incorporated there was a significant reduction in the frequency of trip events. There are numerous instances of tripping from generator supplied protections. Investigations of a sample of these showed that they were co-incident with protection operations of the Woodwood MFR relay. The two key protections contained in this relay are Vector-shift and Neutral over-current. Figure 17 Fepro Biogas Hour-of-Day distribution for Event Types A check of the hourly distribution of events reveals no significant weighing of event types to any particular hours. 61

62 6.2.1 Fepro Feeder Fault Events There were 15 Fault events that resulted in Fepro Biogas generator trips. 9 of these appeared to be on the Beachburg DS F2 Supply Feeder. 3 occurred when there were faults on the 44 kv supply circuit to Beachburg DS. The other 3 Faults appear to have been on the other two feeders supplied by Beachburg DS (F1 and F3). Table 18 Fepro Feeder Fault Events Event Description Fast Trip (50) Fast Trip (50, 27) Timed (59G, 47) Timed (47 T) Generator Protection No DG records Grand Total Supply SLG Feeder Ø Ø 1 1 Fault 3Ø 1 1 Supply Feeder Fault (to DS) Other SLG 1 1 Feeder Fault Ø Ø 2 2 Grand Total Faults on Beachburg DS F2 Supply Feeder to Fepro Farm (9 events) Figure 18 Typical Beachburg F2 Feeder Fault Jun 24, :38 Generator protection operated Interconnection protection did not operate (below 50 Overcurrent Fast Trip pick up) TT received 62

63 Faults on Beachburg DS F2 Supply Feeder beyond Downstream Recloser) (4 events) The protection for the Beachburg F2 recloser is only required to detect faults up to the second downstream recloser, in case the first downstream recloser fails or is by-passed. TT is not sent when fault current is flowing in the upstream direction because that means the fault is not on the feeder. TT may not be sent for faults that are beyond the second downstream recloser, although setting margins can not eliminate operation for faults slightly beyond that point (protection zone over-lap). There were 4 out of 9 occasions of SLG faults on the feeder whereby TT was not sent. These faults would have been beyond the recloser downstream of the Fepro connection. Technically the Fepro DG is not required to be disconnected because the downstream recloser clears the fault. The following table summarizes those occasions. These can be considered to be nuisance trips. Table 19 Beachburg Feeder Faults (beyond Downstream Recloser) Generator Status On line DG Trip Yes TT Received / No TT No TT Event Description Timed Trip (59G, 59Q) Generator Protection Not Listed Total Supply Feeder Fault (SLG) Figure 19 Typical Feeder Fault (beyond Downstream Recloser) Aug 1, :32 SLG fault on B phase 50 over current Fast Trip Generator protection operated Interconnection protection did not operate (below 50 Overcurrent Fast Trip pick up) TT not received 63

64 Faults on Supply Feeder to Beachburg DS There were 3 faults on the 44 kv supply circuit to Beachburg DS and the 3 faults on the other two feeders supplied by Beachburg DS (F1 and F3). Figure 20 Typical Fault on Supply Feeder to Beachburg DS Jun 23, :26 fault on all phases 50 over current Fast Trip No TT received 64

65 Faults on Other Beachburg DS Feeders There were 3 faults on the other two feeders supplied by Beachburg DS (F1 and F3). TT was not sent from Beachburg DS to Fepro Farms for these events. Table 20 Fault on Other Beachburg DS Feeders Event Description Fast Trip (50) Generator Protection, Fast Trip (47) Grand Total Other Feeder Fault (Ø Ø) Other Feeder Fault (SLG) 1 1 Grand Total Figure 21 Typical Fault on Other Beachburg DS Feeders Jun 28, :09 fault on Beachburg F1 feeder A phase 50 over current Fast Trip No TT received 65

66 6.2.2 Fepro Power Swing Event There was one event that appears to be a single-phase power swing on the A-phase. There was no evidence of a fault on any feeders in the immediate area. The Fepro Generator tripped. Figure 22 Fepro Power Swing Event Aug 10, :34 Power Swing on Beachburg F2 feeder A phase Generator protection operated No TT received Fepro Supply Feeder Current Transients There were two events involving current transients, the precise cause of which is not known. 66

67 Table 21 Fepro Supply Feeder Current Transients Event Description Gen protection Not listed Grand Total Supply Feeder Current transient Figure 23 Typical Supply Feeder Current Transients Aug 10, :19 Current Transients on Beachburg F2 feeder A phase (not a fault) Generator protection operated No TT received Current Transients 6.3 Events at Ledgecroft Farms Over the study period there were a total of 115 events captured by the Ledgecroft Interconnection Protection relay. For these 115 events, the relay captured at least one of an SER record, an Oscillograph record or a Fault Report record. These records were analyzed 67

68 and it was determined that only 71 out of the 115 captured events occurred when the generator was on-line and resulted in the generator being disconnected (tripped). The on-line trip events that were captured were analyzed and classified as faults (37), generator issues (24), power swings (4) and unidentified events (6). Figure 24 Ledgecroft Trip Event Records (Generator On line) Event Type Descriptions Total Supply Feeder Main SLG 16 Trunk Faults (Battersea DS F1) Ø Ø 2 Supply Feeder Lateral SLG 18 Faults (Battersea DS F1) Ø Ø 1 cause unknown 15 Generator Issue gas control 9 problem Power Swing (3 phase) 4 Unidentified 6 Grand Total 71 Ledgecroft Trip Event Summary There were 37 Feeder Fault events that resulted in disconnection of the Ledgecroft generator. All of these faults appear to have been on the Battersea DS F1 Supply Feeder to Ledgecroft. Based on the voltage records at Ledgecroft, it was determined that 18 of these faults were on the main trunk of the feeder connected between Battersea DS and Ledgecroft Farms, and 19 were on a lateral branch of that feeder. There were 24 events that appear to have been caused by generator problems. Oscillograph records show that all of these events involved similar oscillatory active power swings. The cause of the first 15 generator trips was not identified, but the subsequent 9 trips were determined to be caused by gas control problems. The oscillograph records show reversal of both active and reactive power during the course of the power swings. All of the current waveforms are similar which suggests the same cause for all of the events. There were 4 oscillatory Power Swing events. Unlike the Terryland Farms Power Swing events, all of the Ledgecroft power swings showed distinct oscillation of the 3 phase voltages as well as the currents. The exact cause of these Power Swing events was not been determined. In one case there is evidence of an initial single phase voltage and current transient that preceded the power swing. There were 6 events that could not be identified because of the lack of oscillograph record information. All of these events were trips initiated by the Generator protection. No further information was available for these events. These Ledgecroft events will be discussed in further detail in the following sections. 68

69 A check of the hourly distribution of events reveals no significant weighing of event types to any particular hours. Figure 25 Ledgecroft Farms Biogas Hour-of-Day distribution for Event Types Ledgecroft Feeder Fault Events There were 37 Fault events on the Battersea DS F1 feeder that resulted in Ledgecroft Biogas generator trips. 69

70 Table 22 Ledgecroft Feeder Fault Events Event Description Interconnection Protection Interconnection Protection + Generator Protection Generator Protection Unknown Main SLG Trunk Fault Ø Ø 2 2 Lateral branch or Customer Fault SLG Ø Ø Grand Total Grand Total Faults on the main trunk are cleared by reclosers. Because Ledgecroft Farms is near the end of the long feeder (approximately 23 km), there are no downstream reclosers beyond Ledgecroft Farms. Whenever a recloser pole opens to clear a fault on the main feeder trunk, the voltage of that phase will decay to zero after the Ledgecroft generation is isolated. These typically require more than 3 cycles to operate. Based on the interrupted post-voltages for the faulted phase at the recorded at the DG site, 18 of the feeder faults appear to have been on the main trunk. When a fuse opens on a single phase lateral or customer location to isolate a fault, then the fault is cleared and the feeder voltage recovers on the main trunk restoring a healthy 3-phase voltage supply to the remaining connected customers. Based on the recovery of the postvoltages for the faulted phase at the recorded at the DG sites, 19 of the feeder faults appear to have been on a lateral branch or at a customer connection of that feeder. Some lateral sections of the feeder and all load customer connections are protected by fuses. To avoid opening for transient faults, lateral fuses typically are slower than a line recloser first (fast trip) operation (i.e. considerably longer than 3 cycles). Customer transformer fuses can operate much more quickly to minimize transformer damage and avoid causing feeder outages. Many of the Lateral faults were cleared in less than 3 cycles so it is expected that these faults were on the load side of the customer fuses. The Ledgecroft Interconnection Protections did not operate for these faults, although some of the sensitive timed elements picked up momentarily, but reset as soon as the fault was cleared without initiating a protection trip. However there were many (19) occasions when fast, sensitive elements of the Generator protections operated and caused the generator to be disconnected. In most cases, the exact generator protection element that initiated the trip was not available for this report. However, several trips were examined in detail, including all the data from the generator protection, both during the study period and previous to the study period. In all those instances, the trip originated from the vector-shift protection. Where records were not available from the generator protection, the signatures from the intertie protection oscillograph, event log, and fault report was the same as for those caused by vector-shift. Therefore, it is reasonable to assume they were also due to the operation of the vector-shift protection. 70

71 Faults on Battersea DS F1 Main Trunk (18 events) Figure 26 Typical Battersea F1 Feeder Fault (Main Trunk) Mar 11, :00 C phase fault on Main Trunk Because the Ledgecroft facility is not effectively grounded, Ledgecroft contributes A phase B phase and C phase currents to SLG faults where Ia+Ib+Ic = 3I0 zero. Upstream recloser opened (Cphase pole) after 120 ms Ledgecroft current in feed increases after upstream recloser opens Generator and Interconnection protection operated interrupting generator current TOV on unfaulted phases recovers after generator trips 71

72 Faults on Battersea DS F1 Lateral Branch (19 events) Figure 27 Typical Battersea F1 Feeder Fault (Lateral Branch) Apr 28, :06 A phase fault on lateral branch cleared by fuse in one cycle Because Ledgecroft facility is not effectively grounded, Ledgecroft contributes A phase B phase and C phase currents to SLG faults where Ia+Ib+Ic = 3I0 zero. DG current on the unfaulted phases flows indirectly to the SLG fault via the DS transformer. Fast Generator and operated Interconnection protection elements reset after fault cleared Upstream recloser on Main trunk did not open 72

73 6.3.2 Ledgecroft Generator Events (Power Swings) There were 24 generator trips that appear to have been caused by large oscillatory power swings associated with generator problems. Careful examination of the oscillograph records show reversal of both active and reactive power during the course of the power swings. The cause of the first 15 generator trips was not identified. The subsequent 9 trips were determined to be caused by gas control problems. Generator Trips - cause unknown (15 events) All of these events occurred on 4 days - April 10 (4 events), April 11 (5 events), May 12 (5 events) and May 18 (1 event). There were 9 oscillograph records captured for these 15 events. The April events all show a generator trips on the 1 st power swing. The May events all show a generator trips on the 2nd power swing. All of the available current profiles for Generator Trips for which the cause was not known are similar to subsequent Generator Trips that were identified as having been caused by Gas Control problems. Figure 28 Typical Ledgecroft Generator Trip - Cause Unknown (Trip on 1 st Swing) Apr 11, :01 Generator trip Cause unknown Large oscillatory 3 phase Power Swing with envelope period of about 225ms (14 15 cycles) Current changed from approximately 445A rms forward power 0.99 leading power factor to 345A rms reverse power 0.94 lagging power factor There was no noticeable change in Generator terminal voltage The very similar current profiles to Gas Control problems 73

74 Figure 28 (continued) Typical Ledgecroft Generator Trip - Cause Unknown (Trip on 1 st Swing) Apr 11, :01 Generator trip Cause unknown Relay record shows reversal of active and reactive power Figure 29 Typical Ledgecroft Generator Trip - Cause Unknown (Trip on 2nd Swing) May 12, :43 Generator trip Cause unknown Large oscillatory 3 phase power swing with envelope period of about 225ms (14 15 cycles) Current changed from approximately 445A rms forward power 0.99 leading power factor to 345A rms reverse power 0.94 lagging power factor There was no noticeable change in Generator terminal voltage The very similar current profiles to Gas Control problems 74

75 Generator Trips caused by Gas Control problems (9 events) All of these events occurred after May 28, which was the last event for which a Generator trip occurred whose cause was not identified. They occurred on 5 days - May 30 (2 events), July 10 (2 events), July 12 (3 events), July 15 (1 events) and August 10 (1 event). There were 4 oscillograph records captured for these 9 events. All but one of these trips occurred on the 2nd power swing. Only the last event (August 10) tripped on the 1 st power swing. Figure 30 shows a typical record of a trip on the 2 nd power swing. All of the available current profiles for Generator Trips known to have been caused by Gas Control problems are similar to the previous Generator trips for which the cause was not known. Figure 30 Typical Ledgecroft Generator Trip Gas Control problem May 30, :35 Gas Control problem causing generator trip Large oscillatory 3 phase power swing with envelope period of about 275ms (16 17 cycles) Current changed from approximately 440A rms forward power 0.99 leading power factor to 370A rms reverse power 0.94 lagging power factor There was no noticeable change in Generator terminal voltage 75

76 There were 4 additional generator trips that appear to have been caused by relatively small power swings. Two of the trips were initiated by the Interconnection Protection change in reactive power element (32R). The other two trips were initiated by the Generator Protection. The exact cause of these power swings has not been determined. One of the records shows a half-cycle single-phase voltage and current transient preceding the power swing. Figure 31 Ledgecroft small Power Swing trip Aug 21, :14 The record shows the beginning of a small oscillatory 3 phase power swing For this event only the power swing is preceded by a half cycle decrease in B phase voltage with corresponding small increase in C phase current (from approximately 300A rms to 360A rms There is a noticeable change in Generator terminal voltage 76

77 Figure 31 (continued) Ledgecroft small Power Swing trip Aug 21, :14 The relay record shows a reversal of reactive power from 70 kvar absorbing (underexcited) to 442 kvar delivering (over excited) and decrease in forward active power from 307 kw to 270 kw Ledgecroft Unidentified Events There were 6 events that could not be identified because of the lack of oscillograph record information. All of these events were trips initiated by the Generator protection. No further information was available for these events. 7 Discussion of Events and Observations 7.1 Protection Settings The goal of protection design is to prevent or minimize equipment damage and customer supply interruptions for undesirable conditions such as faults or unacceptable power quality conditions. Protections must be dependable (operate when required) and should be reasonably secure (avoid nuisance trips). High frequency of nuisance trips based on operational experience may require some refinement to protection design to improve the balance of protection sensitivity, speed and selectivity. However dependability is paramount and that limits the amount of adjustments that can be made. The challenge increases for DG facilities that do not utilize communication intelligence (Transfer Trip) to selectively distinguish conditions that require the DG to disconnect. DG interconnection protection design and relay settings requires effective information exchange between the DG owner and the Utility. Accurate details of Generator equipment characteristics are required to be incorporated into the utility electrical model for the Distribution System. The model is then used to generate extreme fault conditions that the protections are required to respond to. The protection designer uses this information to determine settings for the protection. There were some issues encountered with the information that was exchanged, as identified below. a. All of the Biogas generators have generator neutral grounding resistors that result in very low neutral currents during ground faults. There was a fundamental flaw in the fault study 77