IEC/TR 61000-3-15 Edition 1.0 2011-09 TECHNICAL REPORT Electromagnetic compatibility EMC – Part 3-15: Limits – Assessment of low frequency electromagnetic immunity and emission requi
General
This article aims to compare the behavior of static power supplies connected to the electrical network with other types of generators, providing a concise overview of various generation systems.
There are three main types of generation systems that interface to the power system These include:
Different types of energy generation plants possess unique characteristics related to synchronization equipment, protective functions, starting practices, and electrical operating behavior These plants can utilize various primary energy sources, including internal or external combustion, wind, fuel cells, electrochemical accumulators, flywheel storage systems, small-scale hydro, and photovoltaic cells.
This Technical Report discusses both current and voltage source inverters While most distributed generation (DG) inverters are typically classified as voltage source inverters due to their topology, they actually operate under a current source control strategy when considered from the perspective of network integration.
It is typically assumed that the line voltage at the distributed generation (DG) connection point remains constant, allowing for the desired power injection to be accomplished by regulating the current supplied by the inverter.
Induction (asynchronous) generators
An induction generator, also known as an "asynchronous" generator, functions based on the principles of an AC induction motor but operates at a speed slightly exceeding the synchronous speed of the power system These generators are typically utilized in power plants that require operation in conjunction with another power source, such as the utility grid.
Induction generators draw their excitation current from their stators, leading to the consumption of reactive power from the system This results in voltage drops and heightened losses within the distribution network In cases where these losses and voltage drops are considerable, it may be necessary for the induction generator to implement measures to adjust its power factor close to unity.
Induction generators are unable to maintain significant fault current at their terminals for extended periods due to the drop in excitation source voltage during faults However, they can inject a substantial amount of current for a brief transient duration, which can affect the power system Consequently, the protection and interface mechanisms for induction generators differ from those of synchronous generators.
Synchronous generators
Synchronous generators are rotating energy conversion machines that function as voltage sources, capable of operating independently as stand-alone power sources Additionally, they can work in parallel with other sources, such as utility distribution systems, provided they are properly synchronized and equipped with the necessary protection and controls.
Synchronous generators feature integral exciters and control systems that enable them to function as stand-alone power sources This capability is especially beneficial for distributed generation (DG) installations, which can operate both as standby power units and in parallel with the grid However, it is essential to implement stringent anti-islanding protection measures for these systems.
Synchronous generators must be accurately synchronized with the utility system at the moment of connection and throughout their operation This synchronization involves aligning the frequency, phase angle, and voltage magnitude within strict tolerances at the customer's circuit breaker interface with the utility network Proper synchronization is essential to prevent damage to both the generator and the utility system equipment.
To ensure synchronicity, it is crucial to control the unit's load Failure to promptly disconnect the unit from the system when it loses synchronism can lead to potential damage and power quality issues.
Synchronous generators, equipped with exciters, are capable of sustaining fault currents for extended periods compared to induction generators, provided the exciter's energy source is independently sourced Consequently, the importance of fault protection is heightened for synchronous units in contrast to induction units.
Static power converters
The static power converter, commonly known as an inverter, serves as the crucial link between direct current (DC) energy sources or variable frequency sources and the power distribution system Inverter units are utilized in various generation systems, including photovoltaic arrays, fuel cells, battery storage systems, certain micro-turbines, and specific wind turbines.
In contrast to induction or synchronous generators that rely on rotating coils and magnetic fields to transform mechanical energy into electrical energy, inverters primarily convert one type of electricity to another, such as DC to AC, utilizing solid-state electronics These devices are managed and safeguarded by internal electronic circuits, which monitor voltage, current, and frequency conditions If any parameters exceed maximum tolerances, the internal controller promptly halts power injection into the utility system, while also overseeing synchronization and start-up processes.
Most small converter units for grid parallel operation depend solely on their internal protection functions However, larger inverters with special features may need additional external protection and control functions.
There are differences between inverters and rotating machines For example, as the inverter has no moving or rotating parts, it utilizes the on/off switching of semiconductor devices to
Solid-state switching devices enable the rapid synthesis of AC power frequency waveforms from energy sources Their fast switching response allows converters to halt energy production much more quickly than traditional rotating machines, especially when the controller's protection scheme detects the need to interrupt the energy flow.
5 Survey of EMC requirements for DG
The growing demand for testing and certification of distributed generation equipment is essential for ensuring reliable interconnection with the electric power grid and other load equipment This need has prompted research organizations like IEEE, EPRI, UL, CIGRE, and CIRED to intensify their investigations, aiming to establish widely accepted operating guidelines and standards.
The increasing integration of renewable energy sources and distributed energy generation into the electricity supply highlights the growing need for standardized electromagnetic compatibility (EMC) requirements on an international level.
The most frequently used specifications and emission requirements in different countries are summarized in Table 1
Table 1 evaluates the consideration of low frequency emission requirements across various countries, summarizing the applicable national and international standards, as well as common practice specifications for distributed generation (DG) that adhere to distribution system operators' (DSOs) restrictions.
Table 1 presents data on voltage fluctuations, harmonics, and DC injection, primarily sourced from CIGRE TF C6.04.01, a Task Force focused on establishing connection criteria for distributed generation within the distribution network.
The Table was subsequently updated on the basis of the contributions from National
Committees The last column in Table 1 lists the references to National Specifications
The proposed emission tests in this Technical Report are derived with these existing standards in mind
Data on EMC low frequency immunity requirements were insufficient for a dedicated table
Table 1 – DG specifications and emission requirements applied in different countries
Country Voltage fluctuations Harmonics DC injection National specifications
P lt = 0,46 Resulting from all the connected generators at the PCC mostly affected
Individual limits based on the available short- circuit power (half of the limits used for loads of the same power)
Systems which inject DC current by design (e.g half wave operation) are not permitted (Ref to
TOR D2:2006 Assessment of network interferences for any installation (MV and LV) ệVE/ệNORM E 8001-4-172:2009 (for
Belgium informative IEC 61000-3-3, IEC 61000-3-5 to IEC 61000-3-11 informative IEC 61000-3-2, IEC 61000-3-4 IEC 61000-3-12
< 1 % of rated current; if > 1 %, trip after 0,2 s
Synergrid – Specific technical requirements for connection of DG systems operating in parallel on the distribution network (C10/11 – revision 12 May 2009)
Canada IEEE 519 or IEC 61000 series
C22.3 NO 9.08 Interconnection of Distributed Resources and Electricity
Supply systems CAN/CSA-C22.2 NO 257-06 Interconnecting Inverter Based Micro- Distributed Resources to Distribution
1 Numbers in square brackets refer to the Bibliography
Country Voltage fluctuations Harmonics DC injection National specifications
IEC 61000-3-3, IEC 61000-3-11 Limited such that DSO can meet its commitments in terms of power quality
IEC 61000-3-2, IEC 61000-3-12 Limited such that DSO can meet its commitments in terms of power quality
Government decree 2003-229 and Ministerial orders (March and April
2003, November 2006) on the general technical requirements regarding design and operation which installations must fulfill for connection to the public distribution network Distribution Technical Guide (EDF)
1 A max (not normal operation) trip after 0,2 s
E VDE-AR-N 4105 Guideline for DG connection to the LV grid (draft July 2010) VDE 0126-1-1 Automatic disconnection device between a generator and the public low-voltage grid
Technical requirements for the connection of independent generation to the grid Guide for the connection of PV installations to the LV network
IEC 61000 series IEC 61000 series < 0,5 % rated current
CEI 0-21 (draft) Reference technical requirements for connecting active and passive electrical users to LV networks of electrical supply companies
Japan ∆V 10 shall be ≤ 0,45 in general
Current THD ≤ 5 % each harmonic current ≤ 3 %
1 % of rated current, trip after 0,5s
Interpretation of the Technical Standards for Electrical facilities;
Korea (Rep of) P lt ≤ 0.25, P st ≤ 0.35 IEEE 519:
Technical requirement for the connection of distributed generation to the distribution system
P st = 1; P lt = 0.8 IEC 61000 series None Malaysian standards adopted from
CFE-L0000-45 Permissible deviat ions on t he w ave f orms of volt age and current in t he pow er source
CFE-L0000-70 NMX-J-610/3-2-A NCE NMX-J-610/3-3-A NCE NMX-J-610/3-6-A NCE NMX-J-610/3-12-ANCE
Netherlands IEC 61000 series IEC 61000 series EN 50438 NTA 8494 Qualification measurements for grid-connected
Portugal IEC 61000 series IEC 61000 series EN 50438
Technical requirements needed for the connection of DG systems to the
LV EDP Electrical Network (Portuguese Grid)
P lt = 0,46 at the PCC mostly affected
IEC 61000-3-2, Class A or IEC 60034-1 or individually calculated when inverters are used
0,5 % of rated current and not exceeding 1A
"Guideline for connection and operation of power plants up to 10
MW in the distribution network"
(National System operator of distribution network – SODO)
Country Voltage fluctuations Harmonics DC injection National specifications
Spain IEC 61000 series IEC 61000 series
IEC 61000 series Galvanic isolation or any equivalent method is required
Royal decree 1955/200 ORDER 5/9/1985 Administrative and technical rules for the operation and interconnection to the grid of hydroelectric power plants up to 5 MVA and “autogeneration plants”
RD 1663/2000 Interconnection of PV installation for the low voltage grid
Switzerland P lt = 0,46 at the PCC mostly affected
Individually calculated when inverters are used
1 A max (not normal operation) trip after 0,2 s
VSE/AES 301/006 Technical Rules for the Assessment of Network Disturbances
< 0.5 % of rated inverter current Thailand’s standards adopted from
P st < 0,5 measured at PCC according to ENA ER P28;
P st < 1,0 measured at the supply terminals (not applicable to generating plant exporting power to other consumers)
IEC 61000-3-2 (Class A) IEC 61000-3-12 IEC/TR 61000-3-4
Limits implemented through references in ENA ER G59/1,
20 mA limit recommended in ENA ER G83
Zero limit recommended in ENA G5/4-1
Compliance with the Energy Networks Association (ENA) Engineering Recommendations (ERs) is essential for the connection of equipment This compliance is mandatory under the Distribution Code for all Distribution System Operators (DSOs) that hold Distribution Licenses issued by the Regulatory Authority.
Australia AS/NZS 61000 series AS/NZS 61000 series IEC 61000 series AS 4777 series: Grid connection of energy systems via inverters; Series
AS 4509: Stand alone power systems
USA IEEE 519 IEEE 519 Varies among utilities
IEEE Standard 1547 Energy Policy Act of 2005
6 Proposed EMC requirements and tests
General test requirements
The proposed general test setup for emission and immunity tests for DC supplied inverters is shown in Figure 1
Figure 1 – General test setup for combined emission/immunity tests
The impedance unit illustrated in Figure 1 can be configured either in-line or by-passed, simulating the public supply network impedance as outlined in IEC 61000-3-3 or IEC 61000-3-11, depending on the distributed generation (DG) power When the impedance is in-line, any non-linear current flowing to or from the inverter or load results in voltage distortion on the inverter side of the impedance This setup is crucial for the tests specified in this Technical Report, referencing the Z ref defined in IEC 61000-3-3.
Z test defined in IEC 61000-3-11, 6.3 are suggested
For current levels up to 16 A, the IEC 60725 Reference Impedance (“Z ref”) values are used
The combined resistance plus inductance values for European 230 V – 50 Hz public supply networks are defined as (0,4 Ω + j 0,25 Ω) consisting of (0,24 Ω + j 0,15 Ω) for the phase and
The neutral impedance is measured at (0.16 Ω + j 0.1 Ω) For current levels reaching up to 75 A, the recommended impedance values according to IEC 61000-3-11, section 6.3, yield a combined impedance of (0.25 Ω + j 0.25 Ω) In North American networks, lower impedance values may be utilized during system testing.
An appropriate power analyzer/data acquisition unit should be used to measure current emissions, voltage fluctuations and flicker, as well as voltage distortions caused by the inverter
The AC power source mimics the public supply, generating distorted voltages, dips, interruptions, and frequency variations It is essential for the AC power source or impedance unit to isolate the simulated power supply from the inverter, which can be achieved using a separate switch This switch, when opened, simulates a circuit breaker tripping, effectively disconnecting the distributed generation (DG) from the public supply locally Additionally, programming the voltage to zero replicates the scenario where the public supply voltage drops to zero.
If the power source used to simulate the public supply is regenerative, it can feed the
To effectively manage excess inverter power, it is essential to either return it to the public supply or ensure that the power source can absorb all generated power If the power source is not regenerative, a parallel load unit is required This load unit must be capable of handling both linear and non-linear current flows to accurately replicate the typical load patterns found in residential and commercial settings.
The DC supply depicted in Figure 1 powers the inverter and allows for adjustable power levels, enabling the inverter to function at different power generation capacities For the tests, a standard DC supply that is either computer-controlled or manually adjustable, featuring variable voltage, will be utilized.
Proposed tests
The result of the assessment process led to the compilation of the tests shown in Table 2
Successful completion of the tests outlined in Clauses 7 and 8 ensures the reliable operation of DG equipment at currents up to 75 A under typical network conditions.
It should be noted that these are proposed tests only
Table 2 – Proposed EMC requirements and tests for DG equipment
Refer to Figure 1 for general test setup and requirements of emission/immunity tests
DG proposed test Test set up configuration Proposed limits Test impedance Test specific notes
Modified Class C (≤ 600 W) - Modified Table 2 of IEC 61000-3-12,
If V-THD < 5 %, increase of V-THD
Z ref or Z test depending on DG power Product test
DC Injection See harmonic emissions 0,5 A or 1 % I rated whichever is less NO Product test
Short and long duration overvoltage emission caused when DG disconnects from the public supply
Voltage tolerance envelope YES Less then 2 cycle test
Voltage tolerance envelope YES Greater then 2 cycle test
Switching frequency emission Under consideration Under consideration
2 to 9 kHz, work is in progress in IEC 77A WG1
Immunity to voltage dips and short interruptions
< 100 ms Longer duration voltage dips
Immunity to harmonics and inter harmonics
Class 3 NO Immunity from 2 to
General
The integration of distributed generation (DG) units into the grid can elevate disturbance levels, influenced by the primary energy source and the conversion technology employed, thereby raising the likelihood of electromagnetic interference.
The degradation of power quality can significantly impact network user installations and hinder network operators from fulfilling their obligations The extent of disturbances caused by distributed generation (DG) is primarily influenced by the short-circuit power available at the connection point and the power level of the DG unit This issue is particularly pronounced in weak grids, where network impedance at the point of common coupling (PCC) may limit the number and size of DG units that can be connected Additionally, the parallel operation of these DG units must also be taken into account.
The effect on the public supply network is influenced by the technology employed, particularly in how it connects to the grid For example, coupling systems that utilize an electronic interface can help mitigate or prevent voltage fluctuations and flicker; however, they may also pose a risk of increased voltage distortion in certain situations.
This Technical Report focuses on limiting distributed generation (DG) emissions to acceptable levels, while also exploring the potential of DG to enhance power quality in the future As DG penetration increases, adopting alternative inverter strategies that emulate synchronous generators may help mitigate electromagnetic compatibility (EMC) impacts on the network Furthermore, implementing active infeed technology could provide compensating behavior that surpasses the performance of traditional synchronous generators, thereby improving overall power quality.
Enhanced power quality in public supply can be attained through the implementation of inverters utilizing a voltage source control strategy or by employing a combination of devices, such as inverters with a current source control strategy alongside an additional compensation system.
Operation of DG equipment, including switching at start up and stopping, power conversion and stochastic output may cause:
• harmonic and inter-harmonic emissions;
• disturbance of network signaling systems (PLC/ripple control)
The following clauses give information concerning possible test methods for the above phenomena as applicable to DG units, taking into account the data collected in Table 1.
Harmonics
Mechanisms of harmonic current emissions
Inverters connected to distributed generation (DG) often produce harmonic currents at the point of common coupling (PCC), which are significantly influenced by the harmonic voltage present in the AC system The effect of these harmonic currents on voltage distortion is also contingent upon the impedance of the supplying grid at the PCC, the internal filter properties of the DG equipment, and the characteristics of the DG's control system.
When a control system derives its reference waveform from the measured network voltage, the presence of harmonic components in the voltage generates harmonic currents, which can exacerbate voltage distortion.
In addition to harmonic currents caused by the supply voltage harmonics, DG equipment generates harmonics of its own due to the switching operation of its solid state devices
These harmonics are usually above 2 kHz but even then small components at lower frequencies exist due to the imperfections in the control and solid state device properties
Naturally the magnitude of the generated harmonics depends on the type of the DG equipment’s internal filter and its component values
Harmonic currents can vary significantly based on different generating conditions, particularly between high and low input power operations of inverters It is essential to consider these variations when assessing the grid connection of photovoltaic-based inverters For instance, a solar inverter utilizing DC/AC current control may exhibit higher harmonics during low-load conditions with open-loop control, while harmonics are reduced during peak generation with closed-loop control Consequently, multiple load levels are established for harmonic current emission testing.
Some more details and measurements results are given in Annex A.
Proposed limits and tests for harmonic current emissions
Specific recommendations on harmonic emissions associated with interconnecting distributed resources with electric power systems can be found in IEEE 1547 [5]
Even though the harmonic current emission limits in IEC 61000-3-2 (up to 16 A) and
IEC 61000-3-12, which applies to loads ranging from 16 A to 75 A, was developed without considering distributed generation (DG) However, it can be inferred that there is a significant similarity in emissions between specific loads and dispersed generation.
Lighting loads and dispersed generation (DG) below 600 W share similarities, as both are utilized for extended periods and can have comparable power levels The total power consumption of lighting in a home can be akin to that of small inverters, while small office buildings may exhibit lighting power usage similar to popular low kilowatt inverter types, particularly photovoltaic-based inverters Consequently, it can be inferred that both lighting and small inverters may have a similar impact on the network regarding current emissions, regardless of the current flow direction.
It is advisable to establish a set of limits derived from the modified IEC 61000-3-2 Class C (lighting) limit table to effectively regulate current emissions for distributed generation (DG) units with a capacity of less than 600 W.
IEC 61000-3-12 (Table 2, R sce = 33) are believed to be suitable for DG equipment in the power range above 600 W
To ensure that distributed generation (DG) does not significantly increase voltage distortion on the network while limiting current emissions, two testing methods are proposed The first method is a strongly suggested "product test" to assess the DG equipment, while the second, recommended as a supplementary measure, is a "system test" to further verify that both current and voltage distortion remain within acceptable levels.
The product test method follows the setup outlined in IEC 61000-3-2 for currents up to 16 A, which is comparable to the configuration used in IEC 61000-3-12 for currents up to 75 A This testing primarily evaluates the performance and compliance of the product.
DG current emissions in worst case conditions: if the DG meets the proposed limits, it is expected to function properly in all but the most exceptional cases
The emission limits set by IEC 61000-3-2 and IEC 61000-3-12 aim to control voltage distortion at the load connection point However, since the network can exhibit significant distortion, any additional current distortion from distributed generation (DG) can exacerbate the existing voltage distortion Therefore, it is crucial to restrict the potential increase in voltage distortion caused by DG to maintain acceptable levels.
For this reason, the system test method is proposed which utilizes the test circuits specified in
IEC 61000-3-3 (up to 16 A) and IEC 61000-3-11 (up to 75 A) establish guidelines for impedance, incorporating a defined load and specified predistortion levels to accurately simulate conditions in the public supply network.
The proposed test methods should enable the user and the manufacturer to assure that DG equipment can function acceptably in the EMC environment commonly found on the network
To ensure compliance with product test requirements, it is recommended that distributed generation (DG) systems maintain acceptable performance by limiting local voltage harmonic distortion to an increase of no more than 1% absolute, assuming that the local voltage distortion is below 5% before the DG connection.
Summary of harmonic current emission tests
Table 3 specifies the characteristics of the main instrumentation and lists different suggested product and system tests for harmonic current emissions
Table 3 – Different suggested product and system tests for harmonic emissions
Main instrumentation to perform DG tests
– Regenerative -> the power source feed back the DG power to the public supply
– NOT regenerative -> the power source or load shall absorb all the DG power plus an acceptable margin
DC SUPPLY – variable voltage for different DG power levels
Limits: as proposed in Table 6 Load Power source a Reference impedance Pre-distortion level
None Regenerative nominal voltage NO NO
Power source or linear load
DG harmonic emissions are assessed under worst-case conditions If the product test is successful, the DG operates effectively within the public supply network, except in rare instances It adheres to the maximum permitted voltage distortions as specified by IEC 61000-3-2 for devices under 16 A and IEC 61000-3-12 for those over 16 A.
SYSTEM TEST (voltage distortion on the network)
Load DG supply Network impedance b Pre-distortion level < 5 % Set up DG voltage distortion limit linear 100 % Z ref or Z test 4,0 ± 0,2 % set by source c IEC 61000-3-
50 % not linear 100 % Z ref or Z test 4,0 ± 0,2 % caused by load IEC 61000-3-
25 % not linear 100 % Z ref or Z test 2,5 ± 0,2 % caused by load IEC 61000-3-
25 % not linear 50 % Z ref or Z test 4,0 ± 0,2 % caused by load IEC 61000-3-
V-THD DG increase < 1 % b of the public supply network: Z ref in IEC 60725 = 0,4 Ω + j 0,25 Ω (impedance applied for power levels < 16 A per phase); Z test = 0,25 Ω + j0.25 Ω (impedance applied for power levels > 16 A per phase). c See Table 7.
Product test procedure for harmonic current emissions
Connect the DG as shown in Figure 1 (with impedance by passed) and set the simulated public supply to the nominal voltage
For DG below 16 A, verify that the simulated public supply has a voltage distortion that is less than the maximum values specified in IEC 61000-3-2, Clause A.2 and illustrated in Table 4
Table 4 – Voltage distortion of simulated public supply (IEC 61000-3-2)
For DG above16 A, verify that the simulated public supply has a voltage distortion that is less than the maximum values specified in IEC 61000-3-12, 7.1 and illustrated in Table 5
Table 5 – Voltage distortion of simulated public supply (IEC 61000-3-12)
Verify that the DG current emissions remain within the limits specified in Table 6
The limits reported in Table 6 are defined as a percentage of the average r.m.s current level
(I rms) that the DG unit can be operate on a continuous basis in full load condition
The method to determine the maximum continuous operating current is the method used in
IEC 61000-3-12 (basically the average of the current over the observation period with the inverter operating at maximum power)
The inverter is, at first, operated at the maximum (rated) power it can continuously handle
The current at that level is the basis for limits, even when the unit is tested at 25 % and 50 % power
The harmonic ratios of the output voltage (U) in no load condition shall not exceed the following values:
0,4 % for even harmonics of order from 2 to 10;
0,3 % for harmonics of order 12 and from 14 to 40
The harmonic ratios of the test voltage (U) shall not exceed the following values with the EUT connected as in normal operation:
0,2 % for even harmonics of order from 2 to 10;
0,1 % for harmonics of order from 11 to 40
Table 6 – Limits for DG up to 75 A/phase (in percent of I rms )
Harmonic order 2 3 5 7 9 11 13 Odd harmonics from H 15 to H 39
NOTE λ is the power factor of the DG, measured under 100 % power generation condition
System test procedure for harmonic current emissions
In Table 7 are reported the distortion values for a voltage distortion V-THD of 4,0 % based on flat top and peak curve of IEC 61000-4-13
Table 7 – Distortion values for a flat top and peaky voltage distortion V-THD of 4,0 %
Phase for flat-top wave form 0 º 10 º 210 º 300 º 220 º 20 º 0 º 120 º 180 º 0 º
Phase for peaky wave form 0 º 180 º 0 º 270 º 0 º 180 º 0 º 0 º 0 º 0 º
Unbalance
The type of distributed generation (DG) units and their connection to the grid can lead to an increased unbalance rate, potentially impacting supply quality While there is no direct test to measure unbalance from a single-phase DG, it can result in flicker and voltage fluctuations, necessitating careful consideration of these effects.
The system voltages at a generation site are generally highly symmetrical due to the construction and operation of synchronous generators used in large centralized power plants
Therefore, the central generation generally does not contribute to unbalance
When small-scale distributed generation, often integrated into energy management systems, is installed at customer sites and constitutes a significant portion of electricity production, the dynamics change These smaller units, like photovoltaic installations, typically connect to the grid at low voltage (LV) through single-phase power electronic inverters This connection point has a relatively high impedance, resulting in a lower short-circuit power and a greater potential for voltage imbalance compared to higher voltage level connections.
The impedance of electrical system components varies across different phases due to factors like the geometrical configuration of overhead lines, which may be asymmetric relative to the ground Although these differences in electrical parameters are typically minor and can often be disregarded with proper measures, such as line transposition, the primary cause of unbalance in most practical scenarios is the asymmetry of the loads.
IEC 61000-2-2 outlines compatibility levels for low-frequency conducted disturbances, emphasizing the importance of voltage unbalance in relation to long-term effects lasting 10 minutes or more It specifically focuses on the negative phase sequence component, which is crucial for assessing potential interference with equipment linked to public low voltage distribution systems Additionally, for systems with a neutral point directly connected to earth, the zero-sequence unbalance ratio may also be significant.
Voltage unbalance from a single-phase load connected line-to-line is effectively represented by the ratio of the load power to the three-phase short circuit power of the network.
Consequently, unbalance is generally only a concern in larger installations.
Voltage fluctuation and flicker
General
Distribution networks can experience heightened flicker, voltage fluctuations, and rapid voltage changes due to the integration of distributed generation (DG) units in consumer installations or the variable power output of these units This issue is particularly prevalent with wind power installations located in remote rural areas with weak supply networks, as well as photovoltaic systems affected by inconsistent irradiation patterns.
A weak supply network, indicated by a low short circuit current ratio or high supply impedance, can lead to significant voltage fluctuations from changes in distributed generation (DG) output, resulting in increased consumer complaints Such networks often operate at the limits of their legal supply voltage tolerances.
For DG equipment of limited power and exporting into the public supply at a high short circuit current connection, it is unlikely that the DG will introduce noticeable flicker
Large distributed generation (DG) units or multiple parallel photovoltaic systems in a localized area can lead to flicker issues This phenomenon is particularly prevalent during winter months when rapid fluctuations in temperature, cloud cover, and wind conditions can cause sudden voltage changes at the DG connection point.
For DG equipment with a maximum of 16 A per phase, the applicable standard is IEC 61000-3-3 Meanwhile, IEC 61000-3-11 pertains to connections for all equipment with input currents up to 75 A per phase, specifically designed for low impedance connections that possess a high short circuit current capability.
The flicker level, indicated by P st (short-term flicker indicator), must remain below 1.0 at the supply terminals of installations with diesel generator (DG) units that do not export power to the public supply network, under normal load conditions.
When distributed generation (DG) equipment exports power to a public supply network, the P st emissions at the installation's supply terminals must not exceed P st = 0.5 This measurement should be taken under normal load and steady-state conditions of the public supply, ensuring that there is no flicker contribution from the public supply.
The maximum relative voltage change is a crucial parameter when distributed generation (DG) equipment feeds power into a public supply network, as it reflects the level of disturbance experienced by the network.
IEC 61000-4-15 specifies how to assess for P st, P lt (long-term flicker indicator), d max and d c
(relative steady-state voltage change) and provides detailed specifications for the evaluation of these directly measured parameters
Voltage changes are generally associated with the energizing, switching and disconnection of
DG equipment voltage fluctuations are measured as a percentage of the steady-state supply voltage just before each voltage change event These variations in voltage are associated with the size of the equipment.
Voltage change limits, particularly the parameters d c, d(t) (relative voltage change characteristics) and d max as specified in IEC 61000-3-3 can be applied to DG equipment operation
IEC 61000-3-3 sets a maximum limit of 4% for rapid voltage changes, but allows a 6% limit for changes resulting from manual or delayed automatic switching, which is common in many distributed generation (DG) installations.
IEC 61000-3-3 permits voltage fluctuations of up to 7% for equipment that is attended during use or switched on and off no more than twice daily Consequently, this 7% threshold is applicable only in exceptional circumstances for distributed generation (DG) equipment.
For information, IEC 61000-2-2 specifies a compatibility level of 3 % for the individual voltage variations
Specific recommendations are not provided in IEEE standards or guides, but individual utilities in USA usually have their own rapid voltage change guidelines in the range 4 % to
Flicker test conditions for DG equipment exporting power to the
This test is made to assure that the flicker contribution, as caused by the DG equipment, is limited to acceptable levels
Configure the DG equipment as shown in Figure 1, with the IEC 60725 Reference Impedance
The Z test (Z ref) for higher power units should be conducted in-line, ensuring that the simulated public supply is set to the nominal voltage level It is essential to verify compliance with the requirements outlined in IEC 61000-3-3, section 6.3, specifically for a 50 Hz system.
Perform a 10 min test, as in 6.5 of IEC 61000-3-3 The general test conditions given in 6.6 of
IEC 61000-3-3 applies since Annex A of the standard does not specify particular DG test conditions Below are the test conditions for measuring voltage fluctuations and flicker.
For automatic DG operation, apply the d max limit of 4 %, and for manually controlled DG equipment, a d max limit of 6 % is acceptable
The P st reading with the DG active and exporting power to the public supply must not exceed an increase of 0.5 compared to the pre-connection level of the DG equipment Other parameters should adhere to the specified limits.
The test voltage shall be maintained within ± 2 % of the nominal value
The frequency shall be 50 Hz ± 0,5 %
The percentage total harmonic distortion of the supply voltage shall be less than 3 %
Fluctuations of the test supply voltage during a test may be neglected if the P st value is less than 0,4 This condition shall be verified before and after each test
For equipment not listed in Annex A, controls or automatic programs must be configured to generate the most adverse sequence of voltage changes, utilizing only the combinations of controls and programs specified by the manufacturer in the instruction manual or those that are reasonably expected to be used.
It is recommended to assess flicker during standard operation, both with and without the chopper or booster in operation, as well as during derating conditions, such as when the AC levels are excessively high.
DC injection
The growing significance of inverter-based generators has led to increased focus on the injection of DC current by distributed generators into distribution networks Consequently, it is essential to consider the potential presence of a DC component (offset) in voltage or current that may flow into the grid.
DC injection can occur due to circuit design issues, such as asymmetry from varying component characteristics, or it may stem from internal faults The injection of DC current into the AC network raises several concerns, which are outlined in detail.
DC injection can be measured using the test set up for harmonic emission assessment specified in 7.2.4 and 7.2.5
At the current time there are no worldwide or IEC limits defined for DC current injection (see
According to IEEE 1547, the maximum allowable distributed generation (DG) rated current in the USA is 0.5%, a standard that is also adopted by several countries outside North America Other nations may allow up to 1% of the rated current or set absolute limits ranging from 0 to 1 A, while the United Kingdom enforces a stricter limit of 0.25% of the rated current per phase.
The values mentioned, such as 0.5%, indicate a minor fraction of the overall load of the distribution transformer Additionally, various distributed generation (DG) units can offset any direct current (DC) injection from one another.
Laboratory tests indicate that inverters generally do not generate significant DC components, even when even harmonics are present in the voltage Most tested inverters recorded DC levels below 100 mA, and only a few instances showed that high levels of even voltage harmonics affected the DC component levels noticeably.
In European countries where EN 50438 is enforced, the injection of DC into the network is prohibited to minimize its impact Consequently, only symmetrical control is allowed for inverter-based systems, while designs that inherently inject DC current, such as half-wave operation, are not permitted.
Such requirement can be fulfilled with reasonable effort for a broad range of technologies
Another possible solution is the use of an isolation transformer, which guarantees a null emission of DC components to the distribution network.
Short duration over voltages
General
Short-duration overvoltages, ranging from 8 ms to several hundred milliseconds, occur when the network segment with distributed generation (DG) equipment is disconnected from the main grid These overvoltages can adversely affect equipment operating in parallel with the DG systems, making it essential to limit their maximum levels.
Two events typically occur when the DG equipment disconnects itself from the public supply
In particular it can happen that:
• DG equipment operates either supplying power to the public supply, or supplying only part of a heavier load In this case the DG generally disconnects fast, as illustrated in Figure 2
The output level of the DG matches the load level, which can result in a disconnect process that may take several hundred milliseconds, as illustrated in Figure 3.
Figure 2 – Over voltages produced during DG quick disconnection
Figure 3 – Over voltages produced during DG slow disconnection (greater than 10 ms)
In the IEC 61000-2-14 effects of over voltages on lamps and ITE equipment are considered
The CBEMA curve illustrates the acceptable AC input voltage envelope for most Information Technology Equipment (ITE), indicating the voltage levels that can be tolerated without causing interruptions in functionality.
P er cent age of no m inal v ol tac e (R M S )
Short duration over-voltages are defined as lasting less than 2 cycles of the fundamental
(40 ms at 50Hz) Longer duration over-voltages are those lasting in excess of 2 cycles
Most consumer electrical products are designed to endure short-duration overvoltages, typically lasting one or two cycles, up to 20% above their rated voltage Under normal operating conditions, the public power supply may experience a steady-state condition that is 10% over the nominal voltage.
To record the over voltages produced during DG disconnection, there are two maxima that should be measured One is the r.m.s value and the other one is a peak voltage measurement
At present no over voltage limits are defined for DG when it disconnects from the public supply and the following procedures just cover how to record such over voltages
When the connected load closely matches the distributed generation (DG) output power capability, the disconnection process may take several hundred milliseconds longer This extended disconnection time can lead to overvoltage persisting for a longer duration compared to scenarios where the DG quickly disconnects from the public supply when voltage exceeds tolerances.
Short duration over voltage test procedure
Connect the DG to the simulated public supply as in Figure 1 with a load as specified below, and follow the procedure for durations < 2 cycles and > 2 cycles
7.6.2.2 Over voltage test for durations less than 2 cycles
To conduct the test, apply a load ranging from 25% to 50% of the available distributed generation (DG) output power Once the DG operates stably, disconnect the public supply and record the voltage waveform using an oscilloscope with suitable voltage probes, as illustrated in Figures 2 and 3, or utilize alternative test equipment for this purpose.
IEC 61000-4-30 provided that the sampling rate is at least 100 x the fundamental frequency of the public supply
7.6.2.3 Over voltage test for durations exceeding 2 cycles
To assess the performance of the distributed generation (DG) system, apply a load that is 100% ± 2% of the available DG output power Once the DG operates stably, disconnect the public supply and record the voltage waveform using an oscilloscope with suitable voltage probes, as illustrated in Figures 2 and 3 Alternatively, this can be achieved with test equipment compliant with IEC 61000-4-30, ensuring a sampling rate of at least 100 times the fundamental frequency of the public supply.
Switching frequencies
Voltage distortion issues arise from switching frequencies, leading to overheating in filters, power supplies, and auxiliary transformers Additionally, these problems can cause failures in electronic control equipment and generate audible noise.
Higher frequency distortion from inverters has been noted, particularly in the voltage of a high-power photovoltaic plant, as illustrated in Figure 5 The current waveform reveals that the equipment utilizes a single three-phase inductor as its internal filter, which offers a 20 dB per decade attenuation In contrast, higher order filters like LCL filters deliver greater attenuation and substantially reduce distortion, as detailed in Annex A.
The distortion from inverter switching frequencies is typically independent of the fundamental frequency of the public supply and can exceed 2 kHz, particularly in premise-type solar inverters with a capacity of 10 kW or less Observations indicate that switching frequencies for these smaller distributed generation units can reach up to 9 kHz or even higher.
Switching frequencies often do not align as integer multiples of the fundamental frequency, such as 50 Hz or 60 Hz, making them undetectable by conventional harmonic analyzers that focus solely on integer harmonics As a result, these frequencies may not be visible in traditional harmonic measurements, as illustrated in the spectrum shown in Figure 5.
IEC 61000-4-7 outlines measurement techniques for frequencies between 2 kHz and 9 kHz, utilizing 5 Hz resolution to categorize spectral components into 200 Hz wide frequency bands, known as bins Frequencies above 9 kHz necessitate different assessment methods that are not covered in this Technical Report.
Currently, IEC 61000-3-10 is under preparation 2 , dealing with emission limits in the range from 2 kHz to 9 kHz, probably using the grouping methodology as defined in IEC 61000-4-7
IEC 61000-3-10 will soon address emissions from both loads and distributed generation (DG) equipment within the frequency range of 2 kHz to 9 kHz; however, currently, there are no defined emission limits for this frequency range.
2 This document (Emission limits in the frequency range of 2 kHz to 9 kHz) is being prepared by
Figure 5 – Distortion due to high power PV inverter
General
To ensure reliable and compatible operations of equipment in networks with high levels of distributed generators, it is crucial to establish appropriate immunity requirements and testing procedures.
Minimum requirements must focus on generator behavior during network disturbances, considering both generation technology and installation capacity In this regard, the low voltage ride-through capability and voltage support during disturbances are critical factors.
Voltage dips and short interruptions are widely considered to be the most serious and frequent power quality disturbances due to their effect on consumer equipment and sensitive processes
Existing standards for anti-islanding requirements may hinder the low voltage ride through capability of distributed generation (DG) equipment These requirements do not adequately address short duration dips or interruptions, which can last from a few milliseconds to longer periods.
40 ms – 50 ms The requirements in place in various states generally state that the inverter shall disconnect within times ranging from 200 ms to 2 s
To enhance power quality, it is essential to better coordinate anti-islanding specifications, allowing distributed generation (DG) equipment to remain connected to the public supply during very short voltage fluctuations lasting from 1 to 5 cycles This adjustment would prevent unnecessary disconnections during dips or interruptions that last less than 100 ms.
For the immunity tests covered by this Technical Report, the following general acceptance criteria are proposed:
Voltage dips and short interruptions
General
Existing standards for testing voltage dip immunity focus primarily on verifying minimum immunity requirements for equipment response to voltage dips
IEC 61000-4-11 applies to equipment below 16 A and IEC 61000-4-34 is for equipment with current levels above 16 A per phase
For semiconductor industry equipment, SEMI F47 [8] standard is applied Preferred test levels are as illustrated in Figure 6 [9], and test characteristics are defined by standards
• A: generator continues to operate as intended in the specified operating range
• B: generator stops generating (disconnection) but recovers without external intervention
• C: generator stops generating (disconnection); an external intervention is necessary, if specified
• D: generator is damaged, loss of function, not recoverable
Figure 6 – Voltage dips and short interruption test levels from different standards
Figure 6 illustrates the preferred test levels from IEC 61000-4-34, which apply to equipment with currents exceeding 16 A in a Class 3 environment, specifically for the industrial Power Control Center (PCC) of the unit under test, and these levels are based on IEC 61000-2-8 A similar trend is observed in IEC 61000-4-11.
For equipment linked to the public network, Class level 2 is applicable, which requires less severe test levels than those shown in Figure 6 The environmental classes are defined in IEC 61000-2-4.
For distributed generators, it is essential to align immunity requirements with protection standards to ensure maximum tripping time during under-voltage conditions The Distribution System Operator (DSO) defines protection requirements to prevent islanding and ensure effective short circuit protection Figure 7 [10] illustrates three voltage-tolerance curves: the grid interface protection requirements set by operators, the generator's immunity performance, and the immunity standards mandated by regulations.
R es idua l v olt age immunity requirement protection requirement
Figure 7 – Voltage tolerance curves for DG immunity requirements
Inverters must disconnect during voltage disturbances, a requirement that is mandatory for large systems with synchronous generators in low voltage (LV) grids The disconnection time of the inverter should be less than the grid's reclosure time following a fault.
Table 8 [11] illustrates the voltage window in which inverters are allowed to feed in the various countries The last column shows the time within which disconnection is required
Table 8 – Protection requirements for PV inverters under voltage disturbances
Country Max AC Voltage Min AC Voltage Disconnection time
Slovenia stage 1: 255 V stage 2: 265 V stage 1: 196 V stage 2: 161 V stage 1: 1,5 s stage 2: 0,2 s
Table 8 shows that protection requirements vary substantially from country to country
For example, in Austria, Germany and Denmark, voltages at the equipment terminal lower than 85 % or greater than 110 % of the nominal voltage shall cause a switch off within
Voltage tolerance characteristics for distributed generation (DG) vary significantly by country, with some nations allowing response times of up to 200 ms, while Greece and Spain permit even longer durations In contrast, other countries impose stricter requirements, demanding response times as short as 100 ms This variation highlights how the "forbidden domain" of voltage tolerance is heavily influenced by national regulations.
Generators must be protected from damage caused by auto-reclosure after disconnection, regardless of their tolerances Therefore, distributed generation (DG) units should trip prior to the auto-reclosure event and aim to reconnect promptly afterward.
It is also observed, that there is an undefined state, of at least 100 ms (France, The
In the Netherlands, there are no specific behavioral requirements for distributed generation (DG) equipment, leading to variability in operational responses Some DG systems may continue to operate for several cycles, while others may be programmed to shut down within a single cycle.
To comply with protection requirements, DG immunity tests for voltage dips and short interruptions are recommended A grid simulation, akin to the test setup shown in Figure 1, is proposed for conducting these tests The simulated public supply will be programmed to function as a voltage dip generator.
The inverter's immunity to grid impedance must be evaluated to ensure it operates effectively under varying grid conditions This can be achieved through dip/interrupt testing using the IEC 60725 Reference Impedance or the Z test for higher currents, initially in bypass mode and subsequently with the impedance in-line.
To ensure proper testing of distributed generation (DG) equipment, it is essential to vary the DC voltage alongside the AC voltage dips in the public supply For photovoltaic inverters, utilizing a photovoltaic array simulator or actual solar panels is advisable as the power source during testing The dip generator must be capable of producing voltage dips with specific parameters, including defined magnitude, duration, initiation point of the wave, and phase angle jump.
Testing must be conducted under various operational conditions and power levels, simulating scenarios like cloudy and sunny days for solar systems It is essential to accurately capture the equipment's behavior, including DC voltages and currents, while thoroughly documenting any malfunctions encountered.
Each test should be conducted three times at each level, allowing the unit to stabilize for 10 seconds between dip levels, referred to as the "gap." The "delay" indicates the waiting time between successive test steps This process not only helps the unit return to nominal operation but also aids in identifying any steps that may lead to the disconnection of the DG from the public supply.
Two different tests are suggested:
• a short dip/interrupt, shorter than 100 ms: for this test several of the test patterns derived from IEC 61000-4-11 (see Figure 8) may be applied;
For the longer dip/interrupt test, the AC voltage should be gradually decreased in increments of approximately 2% of the nominal voltage, while recording the tripping voltage and disconnection time A proposed test pattern involves reducing the public supply to a lower voltage level for 10 cycles (200 ms), followed by a return to nominal voltage for 5 seconds, and then repeating two additional dips to the same level After each test, the distributed generation (DG) system is allowed to stabilize for 5 seconds before proceeding to the next 2% lower voltage step Throughout the testing process, the DG output is closely monitored, with the point at which the output current drops to zero indicating the disconnection point By plotting the test results, a voltage dip tolerance curve can be established.
The voltage dip tolerance curve may be used as a specification for a DG minimum ride- through capability
Generally, mains monitoring for anti-islanding protection requires that DG equipment disconnects if the voltage falls below specified levels For example, one specification states:
Voltages at the equipment terminal that fall below 80% or exceed 115% of the nominal voltage must trigger a disconnection within 200 ms This requirement indicates that inverter manufacturers should either immediately disconnect the distributed generation (DG) or apply a delayed trip of 200 ms Additionally, many inverters offer programmable delays and trip levels, allowing for the selection of optimal operational characteristics tailored to the specific installation.
T s (cycles) Start phase Repeat Gap(s) Delay(s)
Figure 8 – DG immunity test for short dips/interruptions: an example
T s (cycles) Start phase Repeat Gap(s) Delay(s)
Figure 9 – Test pattern for a DG voltage dip tolerance curve
Short duration voltage dips test procedure
Connect the DG to the simulated public supply as illustrated in Figure 1 Apply a load of
50 % ± 10 % of the available DG output power
After the system is stable, execute the test as in Figure 8, and record the DG output current to the load and the DG output voltage (see 7.6)
Document the operating characteristics of the DG, identifying the “ride-through” capability, and the point at which the DG disconnects
If the DG rides through the longest dips, lasting 5 cycles, increase the interrupt time in 1 cycle increments to identify at which point the DG does disconnect
Test should be repeated at 50 % and 100 % DC power input level to solar inverters
Longer duration voltage dips test procedure
Connect the DG to the simulated public supply as illustrated in Figure 1 Apply a load of
50 % ± 10 % of the available DG output power
After the system is stable, execute the test as shown in Figure 9, and record the DG output current to the load
Document the operating characteristics of the DG, identifying the voltage value at which the
DG disconnects It may be required to increase the “dip” period to 20 cycles for DG equipment that is programmed to have at least 200 ms delay before disconnecting
Test should be repeated at 50 % and 100 % DC power input level to solar inverters.
Frequency variations
Public supply systems typically maintain a power reserve to ensure that frequency remains within a specified tolerance band, which generally varies by region but is commonly set at ± 1%.
In the case of significant transmission system incidents, it is crucial to maintain all generation to prevent network collapse when frequency decreases Conversely, if the frequency rises by more than 2%, automatic disconnection of generation is essential to ensure a balance between load and generation.
For operation of PV systems under frequency disturbances, the varying requirements are illustrated in Table 9 [12]
Changes in power frequency primarily affect the rotational speed of machines, leading to variations in the timekeeping of mains electrical clocks and fluctuations in motor power output The extent of these changes is influenced by the speed/torque relationship of the load.
Power frequency variation may have a de-tuning effect on harmonic filters
Any electronic equipment using the power supply frequency as a time reference will also be affected
Table 9 – Protection requirements for PV inverters under frequency disturbances
Country Maximum frequency Minimum frequency Disconnection time
Korea (Rep of) 60,3 Hz 59,7 Hz 0,5 s
Malaysia 52 Hz 47 Hz Continuous operation
USA 60,5 Hz 59,3 Hz 0,1 s power ≤ 30 kW (IEEE 1547)
To evaluate the immunity of distributed generation (DG) equipment connected to 50 Hz or 60 Hz networks with a rated line current of up to 75 A per phase, the IEC 61000-4-28 standard can be utilized.
Although the scope of IEC 61000-4-28 includes equipment up to 16 A per phase, the test principles can be used for higher power DG equipment up to 75 A per phase as well
The test should be performed at nominal mains voltage in representative operational modes of the equipment under test For each test, any degradation of the performance should be recorded
Figure 10 shows a test pattern with frequency increments of 0.1 Hz, beginning at 50.3 Hz Typically, DG equipment is designed to accommodate frequency variations of at least ±0.5 Hz, making 50.3 Hz a standard operational point.
The test must be performed in increments of 0.2% of the nominal frequency (or 0.1 Hz absolute), with a range that can differ by country, potentially reaching ±6% It is essential to document the tripping frequencies and the time delay for disconnection.
To identify the status of the inverter during immunity tests, the general acceptance criteria proposed in 8.1 are applicable
Frequency steps in 0,1 Hz steps starting at 50,3 Hz Type Time (s) Voltage Frequency Repeat Waveform
Figure 10 – DG frequency variation (increment) immunity test: an example
Harmonics and interharmonics
To ensure the proper functioning of generators and distributed generation (DG) equipment, it is essential to consider the rising levels of harmonics and interharmonics present in the grid voltage.
In case of photovoltaic based inverters, they can be particularly sensitive to harmonic and interharmonic disturbances that may affect the current control and output power conversion
The (inter) harmonic frequencies may also affect internal protection and monitoring circuits
IEC 61000-4-13 provides a detailed identification of common disturbances, which include mains signaling signals utilized for tariff and distribution equipment switching by utilities, as well as harmonics and inter-harmonics generated by controlled rectifiers and various user equipment.
Distributed generators must be resilient to common disturbances, ensuring that grid interface protection, over-current protection, and output power remain stable without experiencing false trips or other issues.
In order to test the immunity for harmonics and interharmonics on equipment connected to
50 Hz or 60 Hz network with rated line current up to 75 A per phase, the standard
IEC 61000-4-13 applies to equipment up to 16 A per phase, but its principles are also relevant for higher power distributed generation (DG) equipment, as they experience similar distortions in the public supply.
In general, the test set-up is similar to the one illustrated in Figure 1 The network simulator
(AC power source) is programmed to generate the harmonic and interharmonic voltage disturbances as specified in IEC 61000-4-13 and the following tests can be performed
• Combined harmonic waveforms (flat-curve and over-swing curve): see 8.2.1 of
• Individual harmonics/interharmonics with predefined sequence of test levels: see 5.1 and
• Sweep in frequencies: see 8.2.2 of IEC 61000-4-13
• Meister curve test: see 8.2.4 of IEC 61000-4-13
Table 10 illustrates the test levels for non-triplen and triplen odd harmonics (h)
The IEC 61000-4-13 standard includes tables for even harmonic and interharmonic frequencies, along with typical "flat-top" and "over-swing" curves that are commonly observed in daily public supply.
Table 10 – Harmonic voltage disturbance levels for odd harmonics (IEC 61000-4-13)
IEC 61000-4-13 Class 2 represents the most applicable test levels for DG equipment < 16 A per phase
In certain application areas and higher DG power levels, Class 3 levels may have to be considered for DG inverters that operate in industrial environments
According to IEC 61000-4-13, the test procedures and configurations for Class-2 equipment are generally applicable, except when the tested DG equipment exceeds a power level of 16 A per phase, in which case Class 3 test levels should be considered.
The acceptance criteria as proposed in 8.1 are applicable
Examples of harmonic measurements and analysis on
DG equipment connected to low voltage networks
This Annex presents examples of harmonic measurements and analyses conducted on distributed generation (DG) equipment, including active infeed converters (AIC) The measurements were carried out to validate various proposed tests outlined in this Technical Report.
A.2 Typical behaviour of a DG connected to the network
In DG equipment, the control system derives its current reference waveform from the measured network voltage, leading to harmonic currents due to the voltage's harmonic components, which can exacerbate voltage distortion.
This behaviour is illustrated in Figure A.1, where the simulated network distortion is increased from 3 % to 9 % in 1 % steps The set up adopted for these measurements is the same as in
Figure 1 of this Technical Report The horizontal scale represents 200 ms measurement windows in accordance with IEC 61000-4-7
The current distortion in the mains supply is roughly double the programmed voltage distortion value
Current distortion as a result of voltage distortion of the public supply
Figure A.1 – Total current distortion due the network and the connected inverter
In the proposed harmonic current tests reported in 7.2.2 and 7.2.3, several load levels are defined as harmonic currents could differ considerably under different generating condition
Measurements of distortions during high and low input power operations were conducted on a 5 kW inverter The findings, illustrated in Figure A.2, present the relative distortion percentage of the fundamental current for harmonics up to the 20th order under various inverter operating conditions.
As shown in Figure A.2, the distortion at 30 % (1 500 Watt inverter operating power) is about double than the distortion at 60 % power (3 000 Watt inverter operating power)
This is not uncommon for control loops that are optimized for full power operation
Harmonic order Current distortion (percentage of fundamental current)
Relative inverter current distortion at different input power conditions
C ur rent di st or tion (% of funda m ent al c ur rent )
Figure A.2 – Harmonic distortions at different input power of a 5 kW inverter
A.3 Behaviour of increasing number of active infeed converters (AIC) with LCL filters connected to the network
Recent measurement campaigns in Finland have examined the impact of increasing the number of parallel active infeed converters (AIC) with LCL filters on voltage distortion These measurements were conducted at currents below the converter's rated 93 A to effectively highlight the harmonics present in the current.
Figure A.3 shows an active infeed converter with LCL filter
Source of energy Source of energy
Figure A.3 – DG equipment with LCL filter
This article discusses the implementation of active converters with LCL filters, illustrated by a simulation study in Figure A.4 The study compares the impedance of distributed generation (DG) equipment with a model that substitutes the IGBT inverter and filter inductor with an ideal current source and resistor The rapid current control of the inverter allows it to behave like a current source, while the inverter is also responsible for stabilizing the resonance of the LCL filter, typically achieved through inverter control.
The artificial damping causes the phase angle of the impedance to remain close to zero within the filter's resonance range Notably, for the device examined, this damping can be effectively represented by a parallel resistor model.
Model for DG equipment with an LCL filter
In du cti ve Ca pa cit iv e
Model for DG equipment with an LCL filter
In du cti ve Ca pa cit iv e
Model for DG equipment with an LCL filter
Im pedanc e ( Ω ) I ndu ct iv e P has e ( °) C apac it i ve
Figure A.4 – Impedance model for DG equipment with LCL filter
During measurement campaigns performed in Finland, background phase-to-phase voltage harmonics (harmonic groups) were recorded and a value of THD, measured up to 2 kHz, equal to 2,4 % was obtained
Table A.1 presents the Total Harmonic Distortion (THD) values obtained from connecting one, two, and four inverters The THD data for various Active Inverter Controllers (AICs) equipped with LCL filters (each rated at 10 A) is associated with the background phase-to-phase voltage harmonics in the network.
Table A.1 – THD of increasing numbers of AICs with LCL filters connected to the network
Background phase-to-phase voltage harmonics (harmonic groups)
As an example, the voltage spectrum and current harmonics for four AIC inverters at
10 A r.m.s are reported in Figures A.5 and A.6
Four AICs (10 A each) versus background phase-to-phase voltage harmonics (harmonic groups)
CH1 BGrms CH3 BGrms CH1 rms CH3 rms
Figure A.5 – Voltage spectrum: four AICs connected
% o f t he t ot al ra ted cur rent 4 × 93 A = 372 A
Four AICs (10 A) current harmonics (harmonic groups)
Switching frequency related components go down when the number of conveters increases (square root law)
Figure A.6 – Current harmonics: four AICs at 10 A r.m.s (0,11 / N )
• Active infeed converters with LCL filters do not increase voltage distortion, but tend to decrease it
• Due to the filtering effect, erroneous results are likely when compliance with harmonic current limits is verified in a distorted grid
The harmonics associated with the switching frequency increase in proportion to the square root of the number of parallel-connected AICs, even when these converters are in close proximity and functioning at the same operational point.
• If limits for harmonics above 2 kHz are set the influence of the wider 200 Hz grouping band to the harmonic values has to be taken in the account
[1] Connection Criteria at the Distribution Network for Distributed Generation – CIGRE publication N 313 – February 2007
[2] Distributed Generation: current source behaviour vs voltage source behaviour,
[3] Harmonic Current Emission of PV-Generation under Controlled Voltage Conditions, J
Schlabbach, A Groβ – Proceedings of the IEEE Mediterranean Electrotechnical
Conference MELECON 2006, May16-19, 2006, Malaga, Spain, pp 1056-1059
[4] Prediction of harmonic currents of PV-inverters using measured solar radiation data, J
Schlabbach, L Kammer – Proceedings of the IEEE Mediterranean Electrotechnical
Conference MELECON 2006, May 16-19, 2006, Malaga, Spain, pp 857-860
[5] IEEE 1547 – Standard for interconnecting distributed resources with electric power systems, 2003
[6] DISPOWER Deliverable 2.3 – Identification of general safety problems, definition of tests procedures and design measures for protection, 2006
[7] EN 50438 – Requirements for the connection of micro-generators in parallel with public
[8] SEMI F-47-0200 – Specification for semiconductor processing equipment voltage sag immunity
[9] Evaluating voltage dip immunity of industrial equipment, M Stephens, M
McGranaghan, M Bollen, Proceedings of the 18th Int Conf on Electricity Distribution
[10] Power quality: interactions between distributed energy resources, the grid and other customers, M Bollen, M Họger, Electric Power Quality Utilization Magazine, Vol.1,
[11] ENIRDGnet – WG7: Voltage Disturbance, ESBI, 2004
[12] ENIRDGnet – WG8: Frequency Disturbance, PSYMETRIX, 2004
[13] Parallel active infeed converters: harmonic measurements, Jouko Niiranen, 2011-01-11
[14] IEEE 519 – IEEE Recommended Practices and Requirements for Harmonic Control in
IEC 60034-1, Rotating electrical machines – Part 1: Rating and perfomance
IEC 60050(161):1990, International Electrotechnical Vocabulary – Chapter 161:
IEC 60050-601:1985, International Electrotechnical Vocabulary – Chapter 601: Generation, transmission and distribution of electricity – General
IEC 60050-617:2009, International Electrotechnical Vocabulary – Part 617: Organization/
IEC 60725, Consideration of reference impedances and public supply network impedances for use in determining disturbance characteristics of electrical equipment having a rated current ≤ 75 A per phase 3
IEC 61000 (all parts), Electromagnetic compatibility (EMC)
IEC 61000-2-2, Electromagnetic compatibility (EMC) – Part 2-2: Environment – Compatibility levels for low-frequency conducted disturbances and signalling in public low-voltage power supply systems
IEC 61000-2-4, Electromagnetic compatibility (EMC) – Part 2-4: Environment – Compatibility levels in industrial plants for low-frequency conducted disturbances
IEC 61000-2-8, Electromagnetic compatibility (EMC) – Part 2-8: Environment – Voltage dips and short interruptions on public electric power supply systems with statistical measurement results
IEC 61000-2-14, Electromagnetic compatibility (EMC) – Part 2-14: Environment –
Overvoltages on public electricity distribution networks
IEC 61000-3-2, Electromagnetic compatibility (EMC) – Part 3-2: Limits – Limits for harmonic current emissions (equipment input current ≤ 16 A per phase)
IEC 61000-3-3: 2008, Electromagnetic compatibility (EMC) – Part 3-3: Limits – Limitation of voltage fluctuations and flicker in low-voltage supply systems for equipment with rated current
≤ 16 A per phase and not subject to conditional connection
IEC/TS 61000-3-4, Electromagnetic compatibility (EMC) – Part 3-4: Limits – Limitation of emission of harmonic currents in low-voltage power supply systems for equipment with rated current greater than 16 A
IEC/TS 61000-3-5, Electromagnetic compatibility (EMC) – Part 3-5: Limits – Limitation of voltage fluctuations and flicker in low-voltage power supply systems for equipment with rated current greater than 16 A
IEC/TR 61000-3-6, Electromagnetic compatibility (EMC) – Part 3-6: Limits – Assessment of emission limits for the connection of distorting installations to MV, HV and EHV power systems
IEC/TR 61000-3-7, Electromagnetic compatibility (EMC) – Part 3-7: Limits – Assessment of emission limits for the connection of fluctuating installations to MV, HV and EHV power systems
IEC 61000-3-8, Electromagnetic compatibility (EMC) – Part 3-8: Limits – Signalling on low- voltage electrical installations – Emission levels, frequency bands and electromagnetic disturbance levels
IEC/TR 61000-3-9, Electromagnetic compatibility (EMC) – Part 3-6: Limits – Assessment of emission limits for the connection of distorting installations to MV, HV and EHV power systems
IEC/TR 61000-3-10, Electromagnetic compatibility (EMC) – Part 3-10: Limits – Emission limits in the frequency range 2 kHz to 9 kHz 4
IEC 61000-3-11:2000, 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
IEC 61000-3-12, 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
IEC 61000-3-14, Electromagnetic compatibility (EMC) – Part 3-14: Limits – Assessment of emission limits for harmonics, interharmonics, voltage fluctuations and unbalance for the connection of disturbing installations to LV power systems 5
IEC 61000-4-7, Electromagnetic compatibility (EMC) – Part 4-7: Testing and measurement techniques – General guide on harmonics and interharmonics measurements and instrumentation, for power supply systems and equipment connected thereto
IEC 61000-4-11, Electromagnetic compatibility (EMC) – Part 4-11: Testing and measurement techniques – Voltage dips, short interruptions and voltage variations immunity tests
IEC 61000-4-13, Electromagnetic compatibility (EMC) – Part 4-13: Testing and measurement techniques – Harmonics and interharmonics including mains signalling at a.c power port, low frequency immunity tests
IEC 61000-4-15, Electromagnetic compatibility (EMC) – Part 4-15: Testing and measurement techniques – Flickermeter – Functional and design specifications
IEC 61000-4-28, Electromagnetic compatibility (EMC) – Part 4-28: Testing and measurement techniques – Variation of power frequency, immunity test
IEC 61000-4-30, Electromagnetic compatibility (EMC) – Part 4-30: Testing and measurement techniques – Power quality measurement methods
IEC 61000-4-34, Electromagnetic compatibility (EMC) – Part 4-34: Testing and measurement techniques – Voltage dips, short interruptions and voltage variations immunity tests for equipment with mains current more than 16 A per phase
IEC 61727, Photovoltaic (PV) systems – Characteristics of the utility interface
IEC/TS 62578, – Power electronics systems and equipment – Operation conditions and characteristics of active infeed converter applications 6