Grid requirements to connect DPGS based on RES

1. Grid requirements to connect DPGS based on RES Marco Liserre liserre@ieee.org

2. Introduction • Grid requirements for DPGS are stringent and subject to changes • They are different for different renewable energy sources • IEEE made an attempt, with IEEE 1547 series, to have a common approach for all DPGS below 10 MW • In fact power level is maybe more important than source type • Grid operators consider low power DPGS as a kind of “disturbance” or “negative” load • Higher power DPGS are starting to be consider a resource for grid stability

3. Introduction • Safety issues are also important due to the higher penetration of DPGS at low voltage level • Power quality and EMC are stringent too • In the following the grid requirements are reviewed with focus on: • Photovoltaic systems • Wind systems • However considerations on the influence of the power level will be made

4. Photovoltaic systems

5. Outline • International Regulations • Public Voltage Quality • Response to abnormal grid conditions • Power Quality • Anti-islanding requirements • References • Conclusion

6. Grid connectionrequirements • IEEE 1547-2003 Standard for Interconnecting Distributed Resources with Electric Power Systems • IEEE 1547.1- 2005 Standard for Conformance Tests Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems • IEEE 929-2000, Recommended Practice for Utility Interface of Photovoltaic (PV) Systems – incorporated in IEEE 1547 • UL 1741, Standard for Inverters, Converters, and Controllers for Use in Independent Power Systems - elaborated by Underwriters Laboratories Inc. – compatibilzed with IEEE 1547 • IEC61727 [6] Photovoltaic (PV) systems - Characteristics of the utility interface - December 2004 • IEC 62116 Ed.1 2005: Testing procedure of islanding prevention measures for utility interactive photovoltaic inverter (describes the tests for IEC 61727) – approved in 2007 • VDE0126-1-1 2006 Automatic disconnection device between a generator and the public low-voltage grid”– Safety issues- applied on German Market • EMC • IEC 61000-3-2, Ed. 3.0 – “Electromagnetic compatibility (EMC) –Part 3-2: Limits –Limits for harmonic current emissions (equipment input current ≤16 A per phase)”, ISBN 2-8318-8353-9, November 2005 • EN 61000-3-3, Ed. 1.2 —“Electromagnetic compatibility (EMC) –Part 3-3: Limits – Limitation of voltage changes, voltage fluctuations and flicker in public low-voltage supply systems, for equipment with rated current ≤16 A per phase and not subject to conditional connection”, ISBN 2-8318-8209-5, November 2005 • IEC 61000-3-12, Ed. 1 – “Electromagnetic compatibility (EMC) –Part 3-12:Limits – Limits for harmonic currents produced by equipment connected to public low-voltage systems with input current >16 A and ≤75 A per phase” , November 2004 • IEC 61000-3-11, Ed. 1 —“ Electromagnetic compatibility (EMC) – Part 3-11: Limits – Limitation of voltage changes, voltage fluctuations and flicker in public low-voltage supply systems – Equipment with rated current ≤75 A and subject to conditional connection” , August 2000Standard EN 50160 – “Voltage Characteristics of Public Distribution System”, CENELEC: European Committee for Electrotechnical Standardization, Brussels, Belgium, November 1999 • Utility Voltage Quality • Standard EN 50160 – “Voltage Characteristics of Public Distribution System”, CENELEC: European Committee for Electrotechnical Standardization, Brussels, Belgium, November 1999 . International Regulations

7. voltage unbalance for three phase inverters. Max unbalance is 3% • voltage amplitude variations: max +/-10% • frequency variations: max +/-1% • voltage dips: duration < 1 sec, deep < 60% • voltage harmonic levels. Max voltage THD is 8% Public Voltage Quality – EN 50160

8. Voltage deviations Response to abnormal grid conditions Obs. The purpose of the allowed time delay is to ride through short-term disturbances to avoid excessive nuisance tripping • Frequency deviations Obs. The VDE0126-1-1 allow much lower frequency limit and thus frequency adaptive synchronization is required. • Reconnection after trip Obs. The time delay in IEC61727 is an extra measure to ensure resynchronization before reconnection in order to avoid possible damage

9. DC Current Injection Obs. For IEEE 1574 and IEC61727 the dc component of the current should be measured by using harmonic analysis (FFT) and there is no maximum trip time condition Power Quality • Current harmonics Obs. The test voltage for IEEE1574/IEC61727 should be produced by an electronic power source with a voltage THD < 2.5% (typically ideal sources) if IEC 61727 is not considered, the practice is that the harmonic limits are set by the IEC 61000-3-2 for class A equipments Obs. The current limits in IEC61000-3-2 are given in amperes and are in general higher than the ones in IEC61727. For equipments with a higher current than 16 A but lower than 75A another similar standard IEEE 61000 3-12 applies

10. Average Power Factor • Only in IEC61727 it is stated that the PV inverter shall have an average lagging power factor greater than 0,9 when the output is greater than 50%. Most PV inverters designed for utility-interconnected service operate close to unity power factor. • In IEEE1574 as this a general standard that should allow also distributed generation of reactive power there is no requirement for the power factor • No power factor requirements are mentioned in VDE0126-1-1 • Obs. Usually the power factor requirement for PV inverters should be interpreted now as a requirement to operate at quasi-unity power factor without the possibility of regulating the voltage by exchanging reactive power with the grid. For high power PV installations connected directly to the distribution level local grid requirements apply as they may participate in the grid control. For low power installations it is also expected that in the near future the utilities will allow them to exchange reactive power but new regulations are still expected. Power Quality

11. What is Islanding? • Islanding for grid connected PV systems takes place when the PV inverter does not disconnect very short time after the grid is tripped, i.e. it is continuing to operate with local load. In the typical case of residential electrical system co-supplied by a roof-top PV system, the grid disconnection can occur as a result of a local equipment failure detected by the ground fault protection, or of an intentional disconnection of the line for servicing. In both situations if the PV inverter does not disconnect the following consequences can occur: • Retripping the line or connected equipment damaging due to of out-of-phase closure • Safety hazard for utility line workers that assume de-energized lines during islanding • In order to avoid these serious consequences safety measures called anti-islanding (AI) requirements have been issued and embodied in standards Anti-islanding Requirements

12. In IEEE 1574 the requirement is that after an unintentional islanding where the distributed resources (DR) continues to energize a portion of the power system (island) through the PCC, the DR shall detect the islanding and cease to energize the area within 2 seconds. Anti-islanding Requirements – IEEE 1574 Adjustable RLC load should be connected in parallel between the PV inverter and the grid. The resonant LC circuit should be adjusted to resonate at the rated grid frequency and to have a quality factor of 1 or in other words the reactive power generated by [VAR] should equal the reactive power absorbed by [VAR] and should equal the power dissipated in [W] The parameters of the RLC load should be fine tuned until the grid current through S3 should be lower than 2% of the rated value on a steady-state base. In this balanced condition, the S3 should be open and the time before disconnection should be measured and should be lower than 2 seconds. The UL 1741 standard in US has been harmonized with the anti-islanding requirements stated in IEEE 1547

13. In IEC 62116-2006 similar AI requirements as the IEEE1547 is proposed. The test can also be utilized by other inverter interconnected DER. In the normative reference IEC 61727-2004 the ratings of the system valid in this standard has a rating of 10 kVA or less, the standard is though subject to revision. The test circuit is the same as in the IEEE1547.1 test power balance is required before the island detection test. The requirement for passing the test contains more test cases but the conditions for confirming island detection do not have a significant deviation compared to the IEEE1547.1 test. The inverter is tested at three levels of output power (A 100-105%, B 50-66% and C 25-33% of inverters output power). Case A is tested under maximum allowable inverter input power, case C at minimum allowable inverter output power if > 33 %. The voltage at the input of the inverter also has specific conditions. All conditions are to be tested at no deviation in real and reactive load power consumption then for condition A in a step of 5% both real and reactive power iterated deviation from -10% to 10% from operating output power of inverter. Condition B and C are evaluated by deviate the reactive load in an interval of ±5 % in a step of 1 % of inverter output power. The maximum trip time is the same as in IEEE 1547.1 standards 2 s. In IEC61727, there is no specific description of the anti-islanding requirements. Instead reference to IEC62116 is done. Anti-islanding Requirements – IEC62116

14. The VDE0126-1-1 allows the compliance with one of the following anti-islanding methods: A. Impedance measurement Anti-islanding Requirements – VDE-0126-1-1 B. Disconnection detection with RLC resonant load The test circuit is the same of the one reported in IEEE1547.1 and the test conditions are that the RLC resonant circuit parameters should be calculated for a quality factor bigger than 2 With balanced power the inverter should disconnect after the disconnection of S2 in maximum 5 seconds for the following power levels: 25%, 50% and 100%. For three-phase PV inverters a passive anti-islanding method is accepted by monitoring all three phases voltage with respect to the neutral. This method is conditioned by having individual current control in each of the three phases. Finding a software based anti-islanding method has been a very challenging task resulting in a large number of research work and publications.

15. An overview of the most relevant standards related to the grid connection requirements of PV inverters is given. High efforts are done by the international standard bodies in order to “harmonize” the grid requirements for PV inverters worldwide. The IEEE1574 standard has done a big step in the direction of issuing a standard that includes grid requirements not only for PV inverters but for all distributed resources under 10 MVA. Underwriters Laboratories in US has revised this year the UL 1471 by accepting the grid requirements of IEEE1574 and also IEC62116 was revised to harmonize with the requirements of IEEE1574 in the anti-islanding requirements. Even the very specific German standard VDE0126-1-1 was revised in 2006 where the grid impedance measurement has become optional and an alternative requirement very similar to IEEE1574 was included. All these positive actions needs to be followed by adoption in different countries that still use their own local regulations. Conclusions

16. References [1] Dugan, R.C.; Key, T.S.; Ball, G.J., "Distributed resources standards," Industry Applications Magazine, IEEE , vol.12, no.1, pp. 27-34, Jan.-Feb. 2006 [2] IEEE Std 929-2000 – “IEEE Recommended Practice for Utility Interface of Photovoltaic (PV) Systems,", ISBN 0-7381-1934-2 SH94811, April 2000. [3] UL standard 1741, “Inverters, Converters, and controllers for Use in Independent Power Systems”, Underwriters Laboratories Inc. US, 2001 [4] IEEE Std 1547-2003 – “Standard for Interconnecting Distributed Resources with Electric Power Systems," ISBN 0-7381-3720-0 SH95144, IEEE, June 2003 [5] IEEE Std 1547.1-2005 – “Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems” ISBN 0-7381-4736-2 SH95346, IEEE, July 2005 [6] IEC 61727 Ed.2 – “Photovoltaic (PV) Systems - Characteristics of the Utility Interface”, December, 2004 [7] IEC 62116 CDV Ed. 1 – “Test procedure of islanding prevention measures for utility-interconnected photovoltaic inverters”, IEC 82/402/CD:2005 [8] VDE V 0126-1-1 “Automatic disconnection device between a generator and the public low-voltage grid”,VDE Verlag, Doc nr. 0126003, 2006 [9] IEC 61000-3-2, Ed. 3.0 – “Electromagnetic compatibility (EMC) –Part 3-2: Limits –Limits for harmonic current emissions (equipment input current ≤16 A per phase)”, ISBN 2-8318-8353-9, November 2005 [10] EN 61000-3-3, Ed. 1.2 —“Electromagnetic compatibility (EMC) –Part 3-3: Limits – Limitation of voltage changes, voltage fluctuations and flicker in public low-voltage supply systems, for equipment with rated current ≤16 A per phase and not subject to conditional connection”, ISBN 2-8318-8209-5, November 2005 [11] Standard EN 50160 – “Voltage Characteristics of Public Distribution System”, CENELEC: European Committee for Electrotechnical Standardization, Brussels, Belgium, November 1999 . [12] IEC 61000-3-12, Ed. 1 – “Electromagnetic compatibility (EMC) –Part 3-12:Limits – Limits for harmonic currents produced by equipment connected to public low-voltage systems with input current >16 A and ≤75 A per phase” , November 2004 [13] IEC 61000-3-11, Ed. 1 —“ Electromagnetic compatibility (EMC) – Part 3-11: Limits – Limitation of voltage changes, voltage fluctuations and flicker in public low-voltage supply systems – Equipment with rated current ≤75 A and subject to conditional connection” , August 2000

17. Wind systems

18. Outline • Grid codes, description and purpose • Transmission system operator demands • Active power control, frequency control • Reactive power control, voltage control • Ride-Through Capabilities • Conclusion

19. Grid Codes description and purpose Operate a wind farm/wind turbine like a power station/plant Grid Code: Technical document containing the rules governing the operation, maintenance, & development of the system defined at the Point of Common Coupling – PCC (not turbine specific) Steady state Frequency /Power control Low/high frequency support Voltage support/reactive power compensation Power Quality, flicker, harmonics Transient /dynamic state Fault ride through, to stay connected during low voltage on the grid Ramp rate Communication /power dispatch Reliable communication Wind forecasting Participate power market

20. Recent Grid Codes Europe: The grid codes of Europe are affected by the fact that the grid has traditionally been strong and stable – but the fact that the wind power penetration has been increasing - LVRT (Low Voltage Ride Through) has entered the scene and most grid codes at least specifies LVRT requirements as defined by the German E.ON. In Spain, Scotland and Ireland the grid codes exceeds the “standard” requirements. Australia & New Zealand: Are characterised by a weak and unstable grid with frequency variations from -10 % to +6 % (in extreme) and -6 % to +4 % (more common). Voltage control and site dependent requirements are standard North America: Characterised by a large number of “smaller” power systems requiring local control capabilities such as voltage control. The PF range is more standardised as 0.9c to 0.9i.

21. Grid Codes Trends Voltage control: Future demands is going towards operation in a voltage set point control mode; with a continuously-variable, continuously-acting, closed loop control voltage regulation system, acting like a synchronous generator, where reactive power changes are based on measured voltage. Power control: The trend in power control is fast ramp rates – both up and down, in order to support the frequency of the grid. The latest comments for GB grid codes for power recovery after grid faults states power restoration of 90 % within 1 s. Further frequency control is required in some countries, both under frequency and over frequency support. Plant control: Having wind power plants tending the capabilities of primary control units, traditional power system control features are indisputable. As the need for more dynamical response will increase, the needs for fast and reliable control-infrastructure between the turbines in a park facility are increasing.

22. Grid Codes Trends Low voltage ride-through: Is becoming standard for all grid codes! In addition to symmetrical faults, which are three-phased, new trend setting grid requirements will be covering single and two-phase faults ride-through capability. Voltage support during grid disturbances is becoming a common requirement. An increase in the low voltage duration is foreseen – today GB codes mention 3 min. at 85 % voltage. Simulation models: Validated park control models with full disclosure are already defined for various grid code drafts. Park simulation models are an integrated part of the tender phase in more and more projects. Most connection agreements are decided on background of simulation studies. Also non-confidential block diagrams are required, mainly Australia and New Zeeland, but US are also requiring open-source models. PSCAD, DigSilent and PSS/E are preferred tools.

23. Different National Grid Codes

24. Voltage and Frequency limits Eltra – Denmark. Voltages and frequencies used for design of a wind turbine with voltages below 100 kV

25. Voltage and Frequency limits E-On – Germany. Voltage and frequency range for generating units in the E-On grid.

26. Voltage and Frequency limits Great BritainVoltages and frequencies in GB grid

27. Transmission System Operator demands Primary control: Maintain the balance between generation and demand in the network using turbine speed regulators Automatic control to stabilize the grid frequency in seconds Secondary control: Secure import/export balancing with neighbouring areas with reserve generating capacities. Control within minutes In case of a steady major deviation in the control area, to restore the frequency and to free capacity for the primary control Can be manual or automatic Tertiary control: As automatic or manual change in the working points of generators in order to restore adequate secondary control reserve at the right time

28. Transmission System Operator demands NORDEL UCTE

29. Transmission System Operator demands UCTE: Primary control Insensitive dead band 10 mHz Frequency deviation of 200 mHz it must be possible to activate the total primary control power range required by the power plant in 30 sec and to supply it for at least 15 min. Primary control must be again available after 15 min of activation. Dispatch 2-8% of rated capacity for primary frequency control. Secondary control It restores the frequency to its rated value and releases engaged primary reserves Start within 30 sec. Fully activated within 15 min. N-1 network security Ability to re-establish supply after black out

30. Decoupling of power plants Lowering generation Emergency power by HVDC connections Frequency control/primary control The reserve is activated Emergency power by HVDC connections Disconnection of large combined power plants Load shedding, diconnection of connection lines Transmission System Operator demands NORDEL: • Primary control • 0 MW in frequency control reserve (50,1-49,9 Hz) • 192 MW in momentarily disturbance reserve (49,9-49,5 Hz) 50% (5sek),100 % (30 sek), HVDC emergency power, • Re-established within 15 min. • Secondary control • Fast reserve 600 MW within 15 min

31. Transmission System Operator demands Power control • Production limit control both on transmission and distribution • Reduction below 20% of maximum power in less than 2s on transmission level • Automatic power control after faults up to full power reduction or increase within 30s on transmission level • Distribution level decrease and increase in power from 10-100% of rated power per minute

32. Regulation functions for active power System protection Protection function that shall be able to perform automatic down-regulation of the power production to an acceptable level for electrical network. In order to avoid system collapse it should act fast. Frequency control All production units shall contribute to the frequency control. Automatic control of power production based on frequency measurement to re-establish the rated frequency. Stop control Wind farm shall keep the production on the actual level even if it is an increase in the wind speed

33. Regulation functions for active power Balance control The power production shall be adjusted downwards or upwards in steps at constant levels. Production rate Sets how fast the power production can be adjusted upwards or downwards Absolute production limit Limit the maximum production level in the PCC in order to avoid the overloading of the system.

34. Regulation functions for active power Delta control The wind farm shall operate with a certain constant reserve capacity in relation to its momentary possible power production capacity. Horns Reef offshore windfarm 10*8*2MW=160MW: Operates with 10% Delta Control

35. Regulation functions for active power Horns Reef

36. Frequency control Eltra – Denmark Requirements for wind turbines connected to grids with voltages below 100 kV

37. Frequency control E-On: power reduction at over frequencies

38. Frequency control Ireland: Frequency control characteristic

39. Reactive power control Eltra – Denmark The reactive power flow between the wind turbine including the transformer and the electrical network must be calculated as an average value over 5 min within the control band

40. Reactive power control E-On – Germany Every generating units shall provide in the connection point the range of reactive power provision shown in the figure without limiting delivered active power Type of regulation • Power factor • Mvar regulation • Voltage regulation

41. Reactive power control Great Britain Every generating unit other than synchronous one with a completion date after 1 January 2006 should be able to support an active reactive power flow shown in the figure.

42. Voltage quality Eltra – Denmark. Requirements for wind turbines to grids with voltages below 100 kV

43. Ride-through capability Eltra – Denmark.Requirements for wind turbines to grids with voltages below 100 kV The wind turbine shall be disconnected from the electrical grid according to the figure. Under some special situations a WT shall not be disconnected from the electrical network

44. Ride-through capability Eltra – DenmarkRequirements for wind turbines to grids with voltages below 100 kV • The wind turbine shall stay connected in the following cases. • 3-phase short-circuit for 100 msec; • 2-phase short-circuit with or without ground for 100 msec followed after 300-500 msec by a new short-circuit of 100 msec duration. • Sequences in which WT should keep connected: • At least two 2-phases short-circuits within 2 min interval; • At least two 3-phases short-circuit within 2 min interval. • Energy reserve to remain connected when: • At least six 2-phases short-circuits with 5 min interval; • At least six 3-phases short-circuit with 5 min interval.

45. Ride-through capability E-On - Germany • Three-phase short-circuits or fault related symmetrical voltage dips must not lead to instability above the red line • Between lines red and blue: • All generating plants should experience the fault without disconnection from the grid. If, due to the grid connection concept, a generating plant cannot fulfill this requirement, it is permitted with agreement from E-On to shift the limit line while at the same time reducing the resynchronisation time and ensuring a minimum reactive power injection during the fault • If, when experiencing the fault, the individual generators becomes unstable or the generator protection responds, a brief disconnection of the generating plant from the grid is allowed by agreement with E-On. At the start of a brief disconnection resynchronisation of the generating plant shall take place within 2 seconds at the latest. The active power infeed must be increased to the original value with a gradient of at least 10% of the rated generator power per second. The highest value of the 3-phase line-to-line grid voltage is considered in this figure

46. Ride-through capability E-On - Germany • The generating plants shall support the grid voltage with additional reactive current during a voltage dip. • The voltage control shall act within 20 msec after fault recognition. • The generator unit shall provide a reactive current on the low voltage side of the transformer equal to at least 2% from the rated current for each percent of the voltage dip. • If necessary the generating unit shall be able to provide full rated reactive current.

47. Ride-through capability REE – Spain • The wind turbines shall remain connected during three-phase, two-phase or single-phase to ground faults with a voltage profile as shown in this figure. • In the case of isolated two-phase faults the valley of the voltage profile is set to 60%.

48. Ride-through capability REE – Spain. • No active/reactive power will be consumed at the PCC neither during the fault period nor during the grid voltage recovery period after the fault clearance. • The wind turbine should inject maximum reactive current both during the fault and after the fault is cleared and the grid voltage is in the recovering process with maximum delay of 150ms.

49. Ride-through capability Comparison of different national voltage profiles for fault ride-through capability

50. Resume of several national grid codes