Distributed Solar Integration Experiences

Transcription

1 Distributed Solar Integration Experiences Prepared by: Philip Barker Founder and Principal Engineer Nova Energy Specialists, LLC Schenectady, NY Phone (518) Website: novaenergyspecialists.com E Mail: pbarker@novaenergyspecialists.com Presented at: Utility Wind Integration Group (UWIG) 2013 Distributed Wind/Solar Interconnection Workshop May 21 22, 2013 Golden, CO Prepared by Nova Energy Specialists, LLC 1

2 Topics Discussion of Distribution and Subtransmission Factors Considered in Basic DG integration Studies Useful Ratios for Screening Analysis of DG Impacts Review of Some System Impacts: Voltage Issues Fault Current Issues Islanding Issues Ground Fault and Load Rejection Overvoltage Issues Summary and Conclusions of PV Experiences Prepared by Nova Energy Specialists, LLC 2

3 Discussion of Some Factors to Consider in DG Integration Alt. Feed Other Substations with Load and DG LTC kv Subtransmission Line Substation Transformer Reclosing and Relay Settings Subtransmission Source Bulk System Regulator and LTC Settings Adjacent Feeders Other load and DG scattered on feeder Distribution Feeder Voltage Regulator Step Up Transformer DG Type of Grounding Rotating Machine or Inverter based DG Primary Feeder Point of Connection (POC) Alt. Feed Capacitor Customer Site Load Prime mover or energy source characteristics Prepared by Nova Energy Specialists, LLC 3

4 Some Useful Penetration Ratios for Screening Analysis Minimum Load to Generation Ratio (this is the annual minimum load on the relevant power system section divided by the aggregate DG capacity on the power system section) Stiffness Factor (the available utility fault current divided by DG rated output current in the affected area) Fault Ratio Factor (also called SCCR) (available utility fault current divided by DG fault contribution in the affected area) (Note: also called Short Circuit Contribution Ratio: SCCR) Ground Source Impedance Ratio (ratio of zero sequence impedance of DG ground source relative to utility ground source impedance at point of connection) Note: all ratios above are based on the aggregate DG sources on the system area of interest where appropriate Prepared by Nova Energy Specialists, LLC 4 NREL Workshop on High Penetration PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

5 Minimum Load to Generation Ratio (MLGR) Peak Load Weekdays Minimum Load Weekend Annual Minimum Load Time (up to 1 year is ideal) False Minimum Try to use the annual minimum load (don t just assume 1 week of measurements gives the minimum) Prepared by Nova Energy Specialists, LLC 5

6 Some Helpful Screening Thresholds the Author Uses in His Studies Name of Ratio Minimum Load to Generation Ratio [MLGR] (2) What is Ratio useful for? (Note: these ratios are intended for distribution and subtransmission system impacts of DG for the types of impacts described below.) MLGR used for Ground Fault Overvoltage Suppression Analysis (use ratios shown when DG is not effectively grounded) MLGR used for Islanding Analysis (use ratios 50% larger than shown when minimum load characteristics are not well defined) MLGR used for Load Rejection Overvoltage (use ratios 50% larger than shown when minimum load characteristics are not well defined) Suggested Penetration Level Ratios (1) Very Low Penetration (Very low probability of any issues) >10 Synchronous Gen. Moderate Penetration (Low to minor probability of issues) 10 to 5 Synchronous Gen. Higher Penetration (4) (Increased probability of serious issues. Less than 5 Synchronous Gen. >6 6 to 3 Less than 3 Inverters (3) Inverters (3) Inverters (3) >4 4 to 2 Less than 2 >2 2 to 1 Less than 1 Notes: 1. Ratios are meant as guides for radial 4-wire multigrounded neutral distribution system DG applications and are calculated based on aggregate DG on relevant power system sections 2. Minimum load is the lowest annual load on the line section of interest (up to the nearest applicable protective device). Presence of power factor correction banks that result in a surplus of VARs on the islanded line section of interest may require slightly higher ratios than shown to be sure overvoltage is sufficiently suppressed. 3. Inverters are inherently weaker sources than rotating machines therefore this is why a smaller ratio is shown for them than rotating machines 4. If DG application falls in this higher penetration category it means some system upgrades/adjustments are likely needed to avoid power system issues. Prepared by Nova Energy Specialists, LLC 6 NREL Workshop on High Penetration PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

7 Screening Ratios (Continued) Type of Ratio Fault Ratio Factor (I SCUtility /I SCDG ) Ground Source Impedance Ratio (2) Stiffness Factor (I SCUtililty /I RatedDG ) What is it useful for? (Note: these ratios are intended for distribution and subtransmission system impacts of DG for the types of impacts described below.) Suggested Penetration Level Ratios (1) Very Low Penetration (Very low probability of any issues) Moderate Penetration (Low to minor probability of issues) Overcurrent device coordination Overcurrent device ratings > to 20 Ground fault desensitization Overcurrent device coordination and ratings Voltage Regulation (this ratio is a good indicator of voltage influence. Wind/PV have higher ratios due to their fluctuations. Besides this ratio, may need to check for current reversal at upstream regulator devices.) > to 20 >100 PV/Wind > 50 Steady Source 100 to 50 PV/Wind 50 to 25 Steady Source Higher Penetration (3) (Increased probability of serious issues. Less than 20 Less than 20 Less than 50 PV/Wind Less than 25 Steady Source Notes: 1. Ratios are meant as guides for radial 4-wire multigrounded neutral distribution system DG applications and are calculated based on aggregate DG on relevant power system sections 2. Useful when DG or it s interface transformer provides a ground source contribution. Must include effect of grounding step-up transformer and/or accessory ground banks if present. 3. If DG application falls in this higher penetration category it means some system upgrades/adjustments are likely needed to avoid power system issues. Prepared by Nova Energy Specialists, LLC 7 NREL Workshop on High Penetration PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

8 What Does it Mean if it Falls Into the Higher Penetration Category? If the DG application falls into these higher penetration categories, then a detailed study is generally recommended and may lead to the need for mitigation Prepared by Nova Energy Specialists, LLC 8 NREL Workshop on High Penetration PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

9 In addition to the ratios discussed in the prior slides, also check for: Reverse power flow at any voltage regulator or transformer LTC bank: if present, check compatibility of the controls and settings of regulator controls. Check line drop compensation interaction: if employed by any upstream regulator, do a screening calculation of the voltage change seen at the regulator controller with the R and X impedance settings employed at the regulator. Generally, if ΔV < 1% seen by the regulator controller calculated for the full rated power change of DG, then line drop compensation effects and LTC cycling is not usually an issue. Capacitor Banks: if significant VAR surplus on a possible islanded area study for potential impact overvoltages, resonances, etc. Fast Reclosing Dead Times: if less than 5 seconds (especially those less than 2 seconds) consider the danger of reclosing into live island. Prepared by Nova Energy Specialists, LLC 9

10 Caveats for Use of the Ratios & Checks Ratios we have discussed on preceding slides are only guides for establishing when distribution and subtransmission system effects of DG become significant to the point of requiring more detailed studies and/or potential mitigation options. They must be applied by knowledgeable engineers that understand the context of the situation and the exceptions where the ratios don t work It requires a lot more than just these slides here to do this topic justice. We have omitted a lot of details due to the short presentation format so this is just meant as a brief illustration of these issues. Prepared by Nova Energy Specialists, LLC 10 NREL Workshop on High Penetration PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

11 Voltage Regulation & Variation Issues Steady State Voltage (ANSI C84.1 voltage limits) Voltage Excursions and LTC Cycling Voltage Flicker Line Drop Compensator Interactions Reverse Power Interactions Regulation Mode Compatibility Interactions Prepared by Nova Energy Specialists, LLC 11

12 High Voltage Caused by Too Much DG at End of Regulation Zone LTC SUBSTATION Feeder (with R and X) ( X Sin( θ ) R Cos ( θ )) ΔV I DG + Large DG exports large amounts of power up feeder I DG DG current at angle θ IEEE 1547 trip Limit (132 Volts) Voltage ANSI C84.1 Upper Limit (126 volts) Light Load (DG at High Output) ANSI C84.1 Lower Limit (114 volts) Heavy Load No DG Heavy Load (DG High Output) Distance Prepared by Nova Energy Specialists, LLC 12 End

13 Impact of Distributed Generation on Line Drop Compensation Exporting DG DG shields the the substation LTC LTC controller from from seeing seeing the the feeder feeder current. current. The The LTC LTC sees sees less less current current than than there there is is and and does does not not boost boost voltage voltage adequately. SUBSTATION LTC Line drop compensator LTC Controller CT Heavy Load No DG DG Supports most of feeder load Large DG (many MW) ANSI C84.1 Upper Limit (126 volts) Voltage Heavy Load with DG Light Load No DG ANSI C84.1 Lower Limit (114 volts) Distance End Prepared by Nova Energy Specialists, LLC 13

14 Voltage Regulator Reverse Mode Confused by DG Reverse Power SUBSTATION LTC Normally Closed Recloser Supplementary Regulator with Bi Directional controls Normally Open Recloser R R Supplementary regulator senses reverse power and erroneously assumes that auto loop has operated it attempts to regulate voltage on the substation side of the supplementary regulator Reverse Power Flow Due to DG DG What What happens? happens? Since Since the the feeder feeder is is still still connected connected to to the the substation, substation, the the line line regulator regulator once once it it is is forced forced into into the the reverse reverse mode mode will will be be attempting attempting to to regulate regulate the the front front section section of of the the feeder. feeder. To To do do this this can can cause cause the the supplementary supplementary regulator regulator to to runaway runaway to to either either its its maximum maximum or or minimum minimum tap tap setting setting to to attempt attempt to to achieve achieve the the desired desired set set voltage. voltage. This This in in turn turn could could cause cause dangerously dangerously high high or or low low voltage voltage on on the the DG DG side side of of the the regulator. regulator. This This occurs occurs because becausethe the source source on on DG DG side side of of regulator regulator is is voltage voltage following following (not (not aiming aiming to to a a particular particular voltage voltage set set point) point) and and is is weak weak compared compared to to the the substation substation source. source. Prepared by Nova Energy Specialists, LLC 14

15 Fluctuating Output of a Photovoltaic Power Plant Days Prepared by Nova Energy Specialists, LLC 15

16 Flicker The GE Flicker Curve (IEEE Standard and ) Screening: Using the voltage drop screening formula to estimate the ΔV for a given DG current change (ΔI DG ). Then plot ΔV on the flicker curve using expected time period between fluctuations System Impedance ΔI DG Infinite Source R X DG Starting Current and DG Running current fluctuations ( X Sin( θ ) RCos( θ )) ΔV ΔI + DG DG ΔV Flicker Voltage Example Realize that this is a basic screening concept. For situations Realize that this is a basic screening concept. For situations where there might be more significant dynamic interactions with where there might be more significant dynamic interactions with other loads, or utility system equipment, a dynamic simulation other loads, or utility system equipment, a dynamic simulation with a program such as EMTP or PSS/E may be required to verify with a program such as EMTP or PSS/E may be required to verify if flicker will be visible. if flicker will be visible. Prepared by Nova Energy Specialists, LLC 16

17 A Conservative Quick Screen for PV Flicker (Not as accurate as IEEE 1453 method but easy and quick for PV) This is the IEEE flicker curve, but with two new adjusted curves added by NES to conservatively approximate PV flicker thresholds. Adjusted Borderline of Irritation Curve for PV: This curve used/developed by NES represents a conservative modification to the regular IEEE flicker irritation curve. This curve for PV is meant to capture the fact that PV is not square modulation, and is based on cloud ramping rates, and possible LTC interactions causing flicker. IEEE Borderline of Irritation Curve While the IEEE 1453 method based on Pst, Plt is still the most technically robust approach and should allow best results in tight situations, it is the author s view that this adjusted IEEE curve approach shown here can serve as a cruder but easier alternative method to facilitate quick screens. Note that for PV, the regular IEEE curves are generally too conservative from a flicker visibility perspective due to the fact that PV fluctuations are more rounded rather than square. Percent Voltage Change (ΔV%) 519 Visibility Curve x Irritation Curve x 1.25X Adjusted Borderline of Visibility Curves for PV: This curve used/developed by NES represents a conservative modification to the regular IEEE flicker visibility curve. This curve for PV is meant to capture the fact that PV is not square modulation, and is based on cloud ramping rates, and possible LTC interactions causing flicker. IEEE Borderline of Visibility Curve (Square modulation) (Square modulation) Prepared by Nova Energy Specialists, LLC 17

18 PV Flicker Experiences Use of IEEE 1453 method is a technically very robust screening methodology for flicker when very accurate threshold levels need to be determined However, a suggested modified GE flicker curve can work well for PV as a conservative tool for simple screening when less accuracy is required It is the author s experience that other voltage problems (LTC cycling, ANSI limits, etc.) related to PV become problematic at lower capacity thresholds than flicker flicker is one of the last concerns to arise Prepared by Nova Energy Specialists, LLC 18

19 Estimate of Additional Tap Changes Due to PV Variations [Case with LDC Off, Bandwidth at 2 Volts, Time Delay = 30 seconds, PV at one site only] Rough Estimate of Total Additional LTC Tap Changes Occurring Each Month (for the conditions of this slide only) Percent Voltage Change (ΔV) at the LTC Measuring PT Note 1: Percent voltage change of left column is calculated using ΔP=100% of aggregate nameplate rating. This is the calculated voltage change at the PT with no line drop compensation. The right column shows the extra tap changes based on a statistical distribution of typical PV power variations that occur due to typical weather patterns. The values shown assume the PV source is lumped at a single site (the worst case) rather than distributed across the feeder. Note 2: In this example total bandwidth = 2 Volts, time delay =30 seconds, line drop compensation = 0 volts. Different regulator settings would yield different values of extra monthly tap changes. Line drop compensation, if turned on, will usually increase the sensitivity to tap changer cycling. Decreased bandwidth will increase the sensitivity. A shorter time delay increases the sensitivity to PV cycling. Prepared by Nova Energy Specialists, LLC 19

20 Some DG Fault Current Issues Impact of current on breaker, fuse, recloser, coordination. Affect on directional devices and impedance sensing devices. Increase in fault levels (interrupting capacity of breakers on the utility system) Nuisance trips due to backfeed fault current Distribution transformer rupture issues Impact on temporary fault clearing/deionization Prepared by Nova Energy Specialists, LLC 20

21 Fault Currents of Rotating Machines Separately-Excited Synchronous Generator 4-10 times rated current Subtransient Period Envelope Transient Period Envelope Steady State Period Envelope Fault Current 2 to 4 times rated current Induction Machine Fault Current 100% 37% Time Transient Time Constant 4-10 times rated current Current Decay Envelope Current decays to essentially zero Time Prepared by Nova Energy Specialists, LLC 21

22 Fault Current Contributions of Inverters i Pre-fault Inverter Fault Current t I rated Best Case: May last only a few milliseconds (less than ½ cycle) for many typical PV, MT and fuel cell inverters Worst Case: may last for up to the IEEE 1547 limits and be up to 200% of rated current (but usually it is % for most brands) Note: Note: The The nature nature of of the the fault fault contribution from from an an inverter is is a function of of the the inverter controller design/settings, the the thermal protection functions for for the the IGBT IGBT and and the the depth depth of of voltage voltage sag sag at at the the inverter terminals. For For screening it it is is safe safe to to assume that that fault fault currents never never exceed exceed 2 times times the the inverter steady steady state state current current rating rating for for any any duration exceeding ½ cycle. cycle. In In fact, fact, test test results results show show that that nearly nearly all all products have have only only to to per per unit unit current fault fault current. Prepared by Nova Energy Specialists, LLC 22

23 Fault Current Impacts: Nuisance trips, fuse coordination issues, transformer rupture issues, etc. 115 kv 13.2 kv Fault Contribution from DG Might Trip The Feeder Breaker and Recloser (Nuisance trip) Adjacent Feeder Fault Case 1 I utility I DG Recloser A The good news is that PV is much less likely than conventional rotating DG to cause issues since inverter fault contributions are smaller! Transformer Rupture Limits (fault magnitude) Utility DG Fault Case 3 Fault Case 2 Utility DG DG Fault Contribution from DG Might Interfere with Fuse Saving or Exceed Limits of a Device Recloser B Prepared by Nova Energy Specialists, LLC 23

24 The Author s Experiences Related to PV Fault Levels In doing many projects, I have observed that fault current problems associated with PV in most cases are not an issue due to the low currents injected by the inverter (about 1 2 per unit of rating). In general, only the largest PV (or large PV aggregations) can cause enough fault current to even begin to worry current impacts (there are some special exceptions). As PV capacity grows on a circuit, voltage problems usually arise well before fault currents become an issue. A circuit without voltage problems is not likely to have fault current problems due to PV. Prepared by Nova Energy Specialists, LLC 24

25 Unintentional DG Islanding Issues Incidents of energized downed conductors can increase (safety) Utility system reclosing into live island may damage switchgear and loads Service restoration can be delayed and will become more dangerous for crews Islands may not maintain suitable power quality Damaging overvoltages can occur during some conditions Adjacent Feeder Islanded Area 115 kv 13.2 kv Recloser A Recloser B (Normally Open) The recloser has tripped on its first instantaneous shot, now the DG must trip before a fast reclose is attempted by the utility Prepared by Nova Energy Specialists, LLC 25 DG

26 Islanding Protection Methods of DG Protective relay functions can sense the development of an island by sensing when electrical conditions drift outside an acceptable window or acceptable limits. Methods Include: Passive approaches: Simply measure the conditions and trip DG if the limit is exceeded. Could use 81o/u, 27/59, ROCOF, phase jump detection, impedance shift, etc. Active Approaches: DG forces a change and measures it so that island detection can occur much faster: still uses functions like 81o/u, 27/59, ROCOF, phase jump detection, impedance shift, etc. (Non islanding inverters per UL1741 listed as use active detection) Communication Approaches: (use of direct transfer trip (DTT) via fiber optic, telephone lease line, radio, TWACS, etc. Prepared by Nova Energy Specialists, LLC 26

27 Islanding and PV Inverters Inverters typically have very effective active antiislanding protection. Unfortunately, the IEEE 1547 and UL 1741 islanding protection requirements (2 second response time) are not compatible with high speed utility reclosing practices used at many utilities If minimum load is nearly matched to generation then provisions such as DTT and/or live line reclose blocking may be needed, especially with high speed reclosing situations. Prepared by Nova Energy Specialists, LLC 27

28 Screening for Islanding Issues No No No Start Is the DG equipped with at least passive relayingbased islanding protection? Yes Is the reclosing dead time on the Islandable section 5 seconds? Yes Is the annual minimum load on any Islandable section at least twice the rated DG capacity? No Is the DG an Inverter Based Technology Certified Per UL1741 Non-IslandingTest? Yes Yes No Is the mix of (number of and capacity) inverters and other converters and capacitors on the Islandable section within comfortable limits of the UL1741 algorithms? [see: Sandia Labs Report SAND ] Islanding Protection May Need Careful Examination and Possible Enhancement Yes Islanding Protection is Adequate Prepared by Nova Energy Specialists, LLC 28

29 Ground Fault Overvoltage V(t) Voltage swell during ground fault Phase A Phase B X 1, X 2 R 1, R 2 X 1, X 2 R 1, R 2 (t) Source Transformer (output side) Phase C X 1, X 2 R 1, R 2 Fault V cn V bn V an X 0 R 0 Ground Fault Overvoltage can result in serious damaging overvoltage on the unfaulted phases. It can be up to roughly 1.73 per unit of the pre fault voltage level. V cn Before the Fault Neutral Neutral and earth return path V an V bn Neutral V cn During the Fault V an Voltage Increases on V an, V bn V bn Prepared by Nova Energy Specialists, LLC 29

30 IEEE Effective Grounding IEEE Standard C62.92 Parts I through V. Effective grounding achieved if COG=80% or less. This is roughly when the source impedance has the following ratios: R o /X 1 < 1 X o /X 1 3 In general, effective grounding limits the L G voltage on the unfaulted phases to roughly about per unit of nominal during the fault With an ungrounded neutral source, the voltage could be as high as 1.82 per unit. V cn Effectively grounded system N N Ungrounded neutral system N 1.82 V LN V an ideally grounded system 1.05 V LN 1.25 to 1.35 V LN Voltage includes 5% regulation factor V bn Prepared by Nova Energy Specialists, LLC 30

31 Generator Step Up Transformer Grounding Issues High Voltage Side (to Utility Distribution System Primary) Distribution Transformer Low Voltage Side (DG facility) Acts as grounded source feeding out to system Neutral wye delta C C Gen. A B N Neutral grounding of generator on low side of transformer does not impact grounding condition on high side Acts as grounded source feeding out to system only if generator neutral is tied to the transformer grounded neutral Neutral wye wye C C Gen. A B N *IMPORTANT: Generator neutral must be connected to the neutral/ground of the transformer to establish zero sequence path to high side Acts as ungrounded source feeding out to system only if generator neutral is not connected to transformer grounded neutral* Neutral wye wye C C Gen. A B N *neutral is not connected then the source acts as an ungrounded source even though transformer is grounded-wye to grounded-wye Prepared by Nova Energy Specialists, LLC 31

32 Generator Step Up Transformer Grounding Issues Continued High Voltage Side (to Utility Distribution System Primary) Distribution Transformer Low Voltage Side (DG facility) Acts as ungrounded source feeding out to system delta delta C C Gen. A B N Neutral grounding of generator on low side of transformer does not impact grounding condition on high side No connection to Transformer Neutral Acts as ungrounded source feeding out to system Neutral Floating Neutral wye delta C C Gen. A B N Neutral grounding of generator on low side of transformer does not impact grounding condition on high side Acts as ungrounded source feeding out to system Gen. A delta wye C N Neutral grounding at generator C on low side of transformer does B not impact grounding condition on high side Prepared by Nova Energy Specialists, LLC 32

33 PV Inverter Neutral Is Typically Not Effectively Grounded Three Phase Inverter with Internal Isolation Transformer all inside an enclosure a typical arrangement C PV Inverter Switching Bridge Delta Wye A B Neutral Terminal Wye has high resistance neutral grounding or is essentially ungrounded Enclosure bond to safety ground 12,470V Utility Distribution Transformer A 480V Neutral B C Building Neutral Safety Ground 277V Usually bonded to earth ground at main service panel per NEC but this does not make it effectively grounded if inverter transformer is not so Prepared by Nova Energy Specialists, LLC 33

34 Ground Fault Overvoltage Issues Utility System Bulk Source Subtransmission source transformer acts as grounded source suppressing ground fault overvoltage on subtransmission until subtransmission breaker opens. Substation transformer acts as grounded source with respect to feeder suppressing ground fault overvoltage on distribution until feeder breaker opens. But it acts as an ungrounded source when feeding backwards into subtransmission! DG Subtransmission Breaker Subtransmission (46kV) Ground Fault Distribution Substation Distribution Substation Feeder Breaker DG Site 1 Ground Fault Transformer Acts as ungrounded source (not effectively grounded) kv Line DG Site 2 Transformer acts as ungrounded source or acts as high Z grounded source (if generator neutral is not grounded or high z grounded) Load DG Distribution Substation Load Load Load Neutral is Ungrounded or High Z Grounded Load Need enough load on this island with respect aggregate DG at distribution level to suppress overvoltage otherwise effective grounding or other solutions are needed! Need enough load on this island with respect aggregate DG at all connected distribution substations to suppress overvoltage otherwise special solutions are needed! Prepared by Nova Energy Specialists, LLC 34

35 Solutions to Ground Fault Overvoltage (any one of these alone will work) Effectively ground the DG if possible (But be careful since too much effectively grounded DG can desensitize relaying and cause other issues. Also, see note 1 with regard to subtransmission impacts of distribution effective grounding of DG.) If DG is not effectively grounded make sure to maintain a minimum load to aggregate generation ratio >5 for rotating DG and >3 for inverter generation (lower ratios are possible in specific cases based on inverter currents limits) Don t separate the feeder from the substation grounding source transformer until sufficient non effectively grounded DG is cleared from the feeder (e.g. use a time coordinated DTT method.) Use grounding transformer banks at strategic point(s) on feeder. Note 1: On subtransmission since the distribution substations usually feed in through delta (high-side) windings, effective grounding of DG at the distribution level does not make it effectively grounded with respect to subtransmission level. Prepared by Nova Energy Specialists, LLC 35

36 How Load Reduces Ground Fault Overvoltage V cg Neutral V ag Before the Fault V bg Neutral V cg =0 V ag Voltage Increases on V ag, V bg During Ground Fault (light load) V bg X R For inverters the excessive load will also trigger fast shutdown to protect transistors Impedance of DG Source, its transformer and connecting leads V ag During Ground Fault (heavy load) kv Feeder V cg =0 Neutral V bg Utility Source Open Breaker Load Ground Fault (phase C) Voltage does not rise much on V ag, V bg because the overall size of the triangle has been reduced (phase to phase voltage has dropped) Prepared by Nova Energy Specialists, LLC 36

37 Grounding Transformer Impedance Sizing Utility Source Open X t =5% X 1PV = 30% IEEE Effective Grounding Definition Utility Primary Feeder Grounding Transformer Bank X 0groundbank, R 0groundbank Inverter Assume the inverter X 1 is 30% for the generic worst case Note: 30% is not the actual inverter impedance since the inverter impedance varies due to controller dynamics and operating state. But 30% is a very conservative value that can be used generically if no other data is available. A higher number can be used, but care should be exercised if using a higher value (especially if it exceeds 50%). If the specific inverter impedance (R and X) is known in detail, you can also use the IEEE C overvoltage equations/graphs to calculate the needed grounding transformer impedance. X R X R 0 groundbank X 1 pv 0 groundbank X 1 pv 0 groundbank X 1 pv 0 groundbank X 1 pv < 3 < 1 Engineering Targets to Provide Effective Grounding with Reasonable Margin Prepared by Nova Energy Specialists, LLC 37

38 Ground Transformer Sizing/Rating Must be sized such that: X0/X1 and R0/X1 ratios are satisfied with some margin (see the targets prior slide or use IEEE C equations/graphs) Bank must be able to handle fault currents and steady state zero sequence currents without exceeding damage limits Bank must not desensitize the utility ground fault relaying or impact ground flow currents too much Bank may need alarming or interlock trip of DG if bank trips off. Utility Source Path I 0 utility I 0 TotalI 0 Ground transformer Grounding Transformer Path Zero Sequence Current Divider Prepared by Nova Energy Specialists, LLC 38

39 Inverter Load Rejection Overvoltage Subtransmission Load (250A) Breaker Opens PV Inverter Current Source (I inverter = 50A) Adjacent Feeder Load (50A) Feeder Load (10A) Square root voltage Rise Model V = Overvoltag e in Per Unit S S inverter load on island Linear Voltage Rise V = Overvoltag e in Per Unit S S inverter load on island Note: The actual maximum value will depend on many factors specific to each application. For very large load rejections it will be significantly less than calculated by the above equations but still can be as high as 2 per unit in some cases. Prepared by Nova Energy Specialists, LLC 39

40 Inverter Load Rejection Overvoltage Load on Island (In Per Unit of the Inverter Power Output the Instant Before Island Formed) Per Unit Overvoltage* Square Root Model (inverter calculates P and Q from measured I x V) Per Unit Overvoltage* Linear I Model (inverter measures I assumes power is linearly related) > > >2.00 > >2.00 >2.00 *Voltage shown is in per unit of the pre-island operating voltage. Values shown are likely worst case for illustration purposes and will vary considerably based on product design consult inverter manufacturers for specific values for products. Non-linear effects of the loads during the island as well physical voltage output limits of the inverter (over modulation, DC input limit, etc.) can reduce the value compared to what is shown on the table. Prepared by Nova Energy Specialists, LLC 40

41 Recommendations for Inverter Load Rejection Inverter load rejection overvoltage onset can be severe and rapid, happening almost instantly. Inverter design and protection settings affect response check with manufacturer for case specifics. Inverter overvoltage with full load rejection can be up to and over 2.0 per unit in the worst cases. See >> pazos.pdf Conditions to Avoid or that Might Warrant Mitigation: Avoid situations where the load on island is less than 1 per unit of inverter output at the time of island formation. Below this level, the conditions and inverter product responses need to be studied more closely to determine if overvoltage are outside bonds. Lightly loaded islands where capacitors (cables, capacitor banks) provide surplus reactive power on island can be more sensitive to overvoltage issues. Voltage Withstand Guidance: arrester TOV curves, ITIC curve for loads, and IEEE guidelines (similar to those for effective grounding) Prepared by Nova Energy Specialists, LLC 41

42 Ferroresonance and Load Rejection Overvoltage with Rotating DG Conditions to Avoid: Islanded State (Feeder Breaker open) Generator Rating > minimum load on island Excessive Capacitance on island Reliable and fast anti islanding protection that clears DG from line before island forms is a good defense against this type of ferroresonant condition! Reasonably high MLGR avoids it too. EMTP Simulation of Ferroresonant Overvoltage Unfaulted Phase Voltage Normal Voltage Waveform shown is Rotating Machine Type Overvoltage Load rejection, ground fault and resonance related overvoltage Breaker Opens (island forms) Prepared by Nova Energy Specialists, LLC 42

43 Outcomes of PV Projects (0.1 MW to about 10 MW) the Author Has Been Involved With in Various Locations Type of Issue Voltage Regulation Interactions Fault Current Interactions Islanding Interactions Experiences (over 40 projects studied) Most have not required changes to the regulator or regulation settings. A few projects have required regulator setting changes to reduce the chance of LTC cycling or ANSI C84.1 voltage violations. The largest sites studied have required reactive compensation (fixed power factor mode) to mitigate voltage changes. No sites except one have caused enough additional fault current to impact coordination or overcurrent device ratings in a significant manner. For islanding protection, roughly 1/3 rd of the sites have required something special beyond the standard UL 1741 inverter with default settings. Some require more sensitive inverter settings or adjustments to utility reclosing dead time. A few have needed radio or hardwired DTT and/or live line reclose blocking added. Ground Fault Overvoltage Load Rejection Overvoltage Harmonics Other About 1/3 rd of the sites need some form of mitigation usually a grounding transformer bank, a grounded inverter interface, or a time coordinated DTT A few sites have had enough generation relative to load (exporting beyond the feeder breaker) to pose an issue. Time coordinated DTT is a solution. No sites have required any major provisions for harmonics yet Some sites are considering operating in fixed power factor mode producing VARs to provide reactive power support. One site had a capacitor concern. Prepared by Nova Energy Specialists, LLC 43

44 Conclusions PV and other types of DG today are being successfully interconnected on distribution feeders all over the country. In many cases the impacts of smaller projects and/or low aggregations are not enough to cause worrisome effects. However, the size of projects is growing, especially the large commercial and FIT type projects interconnecting at the distribution level. Also, the aggregation of PV as it becomes more widely adopted is leading to more substantial impacts. Inverter features such as fixed power factor mode, high speed overvoltage limiting and robust active islanding detection can help in many situations, but impact mitigation can still be required depending on case specific conditions. Prepared by Nova Energy Specialists, LLC 44

45 Conclusions (continued) The relative size of the PV (or DG) compared to the power system to which it is connected plays the key role in system impact effects. Key factors that gauge the relative size include: The MLGR, FRF (SCCR), Stiffness Factor, and GSIR The ratios will usually need to be gauged based on aggregate DG in a zone or region of concern The settings of utility voltage regulation equipment and feeder overcurrent devices and system designs also play a key role. The absolute size and project class (e.g. FIT, net metered) play a role only in that this impacts the scope and criticality of the project and may trigger certain regulatory requirements. Prepared by Nova Energy Specialists, LLC 45