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Wind Integration: International Experience

WP2: Review of Grid Codes

2ndOctober 2011

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Contents

1. Introduction and Background .................................................................................................... 1

2. Scope of Work Package 2 ........................................................................................................... 1

3. Approach to Work Package 2 ..................................................................................................... 2

4. Grid Codes in General ................................................................................................................ 3

4.1. Background to Grid Codes .................................................................................................. 3

4.2. Grid Codes and Wind Generation ....................................................................................... 4

5. Contingency Performance and Fault Ride Through ..................................................................... 6

5.1. Introduction ....................................................................................................................... 6

5.2. Wind Turbine Generators ................................................................................................... 6

5.3. Specification of Voltage Ride through in Grid Codes ........................................................... 6

5.3.1. Conditions for which Wind Turbine Generators Must Remain Connected ....................... 6

5.3.2. Voltage Support during the Fault .................................................................................... 8

5.3.3. Active Power Provision during the Fault ......................................................................... 9

5.3.4. Active Power Recovery after Fault Clearance .................................................................. 9

5.3.5. Additional Requirements Related to Voltage Ride Through........................................... 10

5.4. NER Specification ............................................................................................................. 10

5.4.1. Conditions for which Wind Turbine Generators Must Remain Connected ..................... 10

5.4.2. Voltage Support during the Fault .................................................................................. 11

5.4.3. Active Power Recovery after Fault Clearance ................................................................ 11

6. Active Power Control Requirements ........................................................................................ 11

6.1. Introduction ..................................................................................................................... 11

6.2. Wind Turbine Generators ................................................................................................. 11

6.3. Specification of Active Power Control Requirements in Grid Codes................................... 126.4. NER Specification ............................................................................................................. 14

7. Frequency Control ................................................................................................................... 14

7.1. Introduction ..................................................................................................................... 14

7.2. Wind Turbine Generators ................................................................................................. 14

7.3. Specification of Frequency Control Capability in Grid Codes ............................................. 14

7.3.1. Limited Frequency Sensitivity mode and Frequency Control Mode ............................... 14

7.3.2. Limited Frequency Sensitivity Mode ............................................................................. 15

7.3.3. Frequency Regulation using Configurable Droop Characteristic with Deadband Control 15

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7.3.4. Frequency Regulation with Multi-Stage Response ........................................................ 16

7.3.5. Frequency Remain Connected Range............................................................................ 17

7.3.6. Additional Frequency Control Requirements ................................................................ 19

7.4. NER Specification ............................................................................................................. 20

7.4.1. Disturbed Operation..................................................................................................... 20

7.4.2. Rate of Change of Frequency ........................................................................................ 20

7.4.3. Frequency Control ........................................................................................................ 20

8. Reactive Power and Voltage Control ........................................................................................ 21

8.1. Reactive Power Capability Requirements ......................................................................... 21

8.1.1. Introduction ................................................................................................................. 21

8.1.2. Wind Turbine Generators ............................................................................................. 21

8.1.3. Specification of Reactive Requirements in Grid Codes .................................................. 22

8.1.4. NER Specification ......................................................................................................... 25

8.2. Voltage Control Capability ................................................................................................ 25

8.2.1. Introduction ................................................................................................................. 25

8.2.2. Voltage control requirements in grid codes .................................................................. 26

8.2.3. NER Requirements ....................................................................................................... 28

9. Requirement to provide a dynamic model ............................................................................... 29

9.1. Introduction ..................................................................................................................... 29

9.2. Issues relating to modelling of WTGs ................................................................................ 29

9.2.1. Initial development of models for transient stability studies ......................................... 29

9.2.2. System Operator and Manufacturer Perspectives ......................................................... 30

9.2.3. Standard Models or Manufacturer-Specific Models ...................................................... 30

9.2.4. Wind Farm Modelling and Aggregation ........................................................................ 31

9.3. Modelling Requirements in Grid Codes ............................................................................ 31

9.3.1. Summary of requirements ............................................................................................ 319.3.2. Form of Model (Block Diagram or Specific Software Compatibility)............................... 33

9.3.3. Scope of Models ........................................................................................................... 33

9.3.4. Aggregation .................................................................................................................. 34

9.3.5. Documentation ............................................................................................................ 35

9.4. Model Validation .............................................................................................................. 35

9.4.1. Introduction ................................................................................................................. 35

9.4.2. Validation Requirements in Grid Codes ........................................................................ 35

9.4.3. Modelling Data and Validation Requirements in Australia ............................................ 38

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9.5. Conclusions ...................................................................................................................... 38

10. Emergency Conditions and Black Start ................................................................................. 39

11. Summary and Conclusions ................................................................................................... 40

11.1. Framework for Negotiation .......................................................................................... 40

11.2. Contingency Performance and Fault Ride Through ....................................................... 41

11.3. Active Power and Frequency Control ............................................................................ 41

11.4. Reactive Power and Voltage Control ............................................................................. 42

11.5. Requirement to provide a validated dynamic model ..................................................... 42

11.6. Emergency Conditions and Black Start .......................................................................... 42

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1. Introduction and BackgroundThe 2010 National Transmission Network Development Plan (NTNDP) for Australia shows that in

some scenarios between 7,000 and 8,000 MW of new wind generation could be added to the

existing 2,000 MW of wind generation over the next 20 years. The Australian Energy Market

Operator (AEMO) is seeking to understand the technical performance issues that might arise should

this level of wind generation penetration occur, and the means by which they have been addressed

in other parts of the world.

In this context, ECAR Ltd. is undertaking two work packages for AEMO:

WP1: International practice, a general review of technical issues observed or discussed

internationally

WP2: Review of Grid Codes:

o a review of international grid codes and how they deal with the matters described inWP1

o a review of the current Australian National Electricity Market (NEM) NationalElectricity Rules (NER), in terms of:

how adequately they deal with the issues described in WP1 how they align with international grid codes for those issues

This report deals with WP2, the Review of Grid Codes.

2. Scope of Work Package 2This work package includes a review of international Grid Codes, including recent changes to, anddevelopments of, international codes that specify technical requirements for new wind generation.

The work will review and summarise:

Grid connection codes relating to the technical performance of wind farms

Requirements for validation of wind farm or wind turbine performance

Modelling requirements for simulating the performance of a wind farm in the power system

The work should identify particularly any grid code issues that may be relevant to the National

Electricity Market (NEM).

This work package will identify how international Grid Codes deal with the issues identified in WP1

and review the NER on similar terms.

In terms of a review of the NER, it is proposed that the Work be limited to a review of the technical

performance standards for generation plant and generating systems (including power stations and

wind farms), described in Schedule 5.2 of the NER. In carrying out this review, it is important to note

that the NER performance requirements for generating plant:

Attempt to be technology neutral, where possible i.e. the requirements for wind farms are the

same as those for conventional power plant, with some explicit exceptions (i.e. requirementsrelating to synchronous versus asynchronous generating units)

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Allow for a negotiation framework with automatic and minimum access standards, where

the requirements might be location specific, such that:

o plant that meets the automatic access standard would not be denied access becauseof that technical requirement

o plant that does not meet the minimum access standard will be denied connection. In reviewing the NER, the Work should address:

Whether the automatic access standard sufficiently addresses the technical issue

If the automatic access standard does not adequately address the issue, how the automatic

access standard might be changed (with reference to other Grid Codes) and

Whether the minimum access standard is unnecessarily onerous in relation to wind

technologies, and the reasons why those wind technologies would not need to meet that

requirement

3.Approach to Work Package 2ECARs approach to Work Package is as follows:

Grid codes or equivalent documents as shown in Table 3.1 were obtained and relevant

provisions reviewed

Some recent comparative literature dealing with grid code requirements for wind generation

was reviewed

System and plant performance issues that may be addressed by codes (including issues

identified in Work Package 1) were identified. Each issue was assessed on the basis of:

o How its addressed in various codes, with commentary as appropriateo How its addressed in NER; is Automatic standard adequate? is minimum standard

excessive? Are guidelines for negotiated standard adequate?

The issues addressed in this WP2 report are:

o Contingency performance and fault ride through (Section 5)o Active power control requirements (Section 6)o Frequency control (Section 7)o Reactive power and voltage control (Section 8)o Requirement to provide a dynamic model, and model validation requirements (Section

9)

o Black start (Section 10)

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Table 3.1 Grid Codes and Equivalent Documents Reviewed

Country /Region

Issuer Document

Ireland: EirGrid Grid Code version 3.5, 15th March 2011

UK National Grid Electricity Transmission The Grid Code, Issue 4, Revision 5, 31st December 2010Germany VDN Transmission Code 2007

50 Hz Transmission Netzanschluss- und Netzzugangsregeln, May 2008

Transpower (Tennet)Grid Code for high and extra high voltage, 1st April2009.

FGW

Technical Guidelines for Power Generating Units, Part 4,Demands on modelling and validating simulationmodels of the electrical characteristics of powergenerating units and systems, revision 5, 23.03.2010

Denmark Energinet.dkTechnical regulation 3.2.5 for wind power plants with apower output greater than 11 kW, 30.9.2010

SpainMinistry of Industry, Commerce andTourism

P. O. 12.2, Installations connected t the transmissionsystem, minimum requirements for design, operationand safety and commissioning, Nov 2009, unofficialtranslation.Link to Spanish version.

Texas ERCOTSummary incorporating extracts from ERCOTdocuments.

Canada Alberta Electric System OperatorWind power facility technical requirements, November15 2004

Hydro Qubec Trans nergieTransmission Provider Technical Requirements for theConnection of Power Plants to the Hydro QubecTransmission System, February 2009

Ontario IESOMarket Rules, Chapter 4, Grid ConnectionRequirementsAppendices, March 6, 2010

Europe ENTSO-EDraft Requirements for Grid Connection Applicable toall Generators, 22 March 2011

4. Grid Codes in General4.1. Background to Grid CodesWith the unbundling of the electricity industry and the opening of generation to competition, it was

necessary to introduce transparent technical rules for the connection of generators to the grid, so as

to ensure the continued reliable and economical operation of power systems, while facilitating a

level playing field for all market entrants. These technical rules form part of what have becomegenerically known as grid codes, or Interconnection Standards in North America. Grid code technical

requirements, including requirements relating to the provision of technical information, were first

developed based on the characteristics and capabilities of large synchronous generators. The

process for drafting and approval of grid codes varies from one jurisdiction to another, but typically a

grid code is drafted by the transmission system operator through a consultative process and

approved by the regulator.

The grid code is not the only source of technical requirements for connections to a power system.

Technical requirements may be included in legislation, in licences issued to various parties, in

standard connection and use-of-system agreements or in the specific terms of individual connectionand use-of-system agreements.

http://www.eirgrid.com/media/2011%20Mar%2008%20EirGrid%20Grid%20Code%20Clean%20Version%203.5.pdfhttp://www.eirgrid.com/media/2011%20Mar%2008%20EirGrid%20Grid%20Code%20Clean%20Version%203.5.pdfhttp://www.eirgrid.com/media/2011%20Mar%2008%20EirGrid%20Grid%20Code%20Clean%20Version%203.5.pdfhttp://www.eirgrid.com/media/2011%20Mar%2008%20EirGrid%20Grid%20Code%20Clean%20Version%203.5.pdfhttp://www.nationalgrid.com/NR/rdonlyres/67374C36-1635-42E8-A2B8-B7B8B9AF2408/44739/Z_CompleteGridCode_I4R5.pdfhttp://www.nationalgrid.com/NR/rdonlyres/67374C36-1635-42E8-A2B8-B7B8B9AF2408/44739/Z_CompleteGridCode_I4R5.pdfhttp://www.nationalgrid.com/NR/rdonlyres/67374C36-1635-42E8-A2B8-B7B8B9AF2408/44739/Z_CompleteGridCode_I4R5.pdfhttp://www.nationalgrid.com/NR/rdonlyres/67374C36-1635-42E8-A2B8-B7B8B9AF2408/44739/Z_CompleteGridCode_I4R5.pdfhttp://www.bdew.de/bdew.nsf/id/DE_7B6ERD_NetzCodes_und_Richtlinienhttp://www.bdew.de/bdew.nsf/id/DE_7B6ERD_NetzCodes_und_Richtlinienhttp://www.50hertz-transmission.net/de/file/NANZR_50HzT_Stand_05_2008_(2).pdfhttp://www.50hertz-transmission.net/de/file/NANZR_50HzT_Stand_05_2008_(2).pdfhttp://www.tennettso.de/pages/tso_de/Transparenz/Veroeffentlichungen/Netzanschluss/Netzanschlussregeln/transpower-NAR2009eng.pdfhttp://www.tennettso.de/pages/tso_de/Transparenz/Veroeffentlichungen/Netzanschluss/Netzanschlussregeln/transpower-NAR2009eng.pdfhttp://www.tennettso.de/pages/tso_de/Transparenz/Veroeffentlichungen/Netzanschluss/Netzanschlussregeln/transpower-NAR2009eng.pdfhttp://www.energinet.dk/SiteCollectionDocuments/Engelske%20dokumenter/El/55986-10_v1_Grid%20Code%203%202%205_v%204%201-30%20%20September%202010.pdfhttp://www.energinet.dk/SiteCollectionDocuments/Engelske%20dokumenter/El/55986-10_v1_Grid%20Code%203%202%205_v%204%201-30%20%20September%202010.pdfhttp://www.energinet.dk/SiteCollectionDocuments/Engelske%20dokumenter/El/55986-10_v1_Grid%20Code%203%202%205_v%204%201-30%20%20September%202010.pdfhttp://www.ree.es/operacion/pdf/po/PO_resol_11feb2005.pdfhttp://www.ree.es/operacion/pdf/po/PO_resol_11feb2005.pdfhttp://www.ree.es/operacion/pdf/po/PO_resol_11feb2005.pdfhttp://www.aeso.ca/rulesprocedures/9139.htmlhttp://www.aeso.ca/rulesprocedures/9139.htmlhttp://www.aeso.ca/rulesprocedures/9139.htmlhttp://www.hydroquebec.com/transenergie/fr/commerce/pdf/exigence_raccordement_fev_09_en.pdfhttp://www.hydroquebec.com/transenergie/fr/commerce/pdf/exigence_raccordement_fev_09_en.pdfhttp://www.hydroquebec.com/transenergie/fr/commerce/pdf/exigence_raccordement_fev_09_en.pdfhttp://www.hydroquebec.com/transenergie/fr/commerce/pdf/exigence_raccordement_fev_09_en.pdfhttp://www.ieso.ca/imoweb/pubs/marketRules/mr_chapter4appx.pdfhttp://www.ieso.ca/imoweb/pubs/marketRules/mr_chapter4appx.pdfhttp://www.ieso.ca/imoweb/pubs/marketRules/mr_chapter4appx.pdfhttp://www.ieso.ca/imoweb/pubs/marketRules/mr_chapter4appx.pdfhttp://www.ieso.ca/imoweb/pubs/marketRules/mr_chapter4appx.pdfhttps://www.entsoe.eu/fileadmin/user_upload/_library/news/110322_Pilot_Network_Code_Connections.pdfhttps://www.entsoe.eu/fileadmin/user_upload/_library/news/110322_Pilot_Network_Code_Connections.pdfhttps://www.entsoe.eu/fileadmin/user_upload/_library/news/110322_Pilot_Network_Code_Connections.pdfhttps://www.entsoe.eu/fileadmin/user_upload/_library/news/110322_Pilot_Network_Code_Connections.pdfhttps://www.entsoe.eu/fileadmin/user_upload/_library/news/110322_Pilot_Network_Code_Connections.pdfhttp://www.ieso.ca/imoweb/pubs/marketRules/mr_chapter4appx.pdfhttp://www.ieso.ca/imoweb/pubs/marketRules/mr_chapter4appx.pdfhttp://www.hydroquebec.com/transenergie/fr/commerce/pdf/exigence_raccordement_fev_09_en.pdfhttp://www.hydroquebec.com/transenergie/fr/commerce/pdf/exigence_raccordement_fev_09_en.pdfhttp://www.hydroquebec.com/transenergie/fr/commerce/pdf/exigence_raccordement_fev_09_en.pdfhttp://www.aeso.ca/rulesprocedures/9139.htmlhttp://www.aeso.ca/rulesprocedures/9139.htmlhttp://www.ree.es/operacion/pdf/po/PO_resol_11feb2005.pdfhttp://www.energinet.dk/SiteCollectionDocuments/Engelske%20dokumenter/El/55986-10_v1_Grid%20Code%203%202%205_v%204%201-30%20%20September%202010.pdfhttp://www.energinet.dk/SiteCollectionDocuments/Engelske%20dokumenter/El/55986-10_v1_Grid%20Code%203%202%205_v%204%201-30%20%20September%202010.pdfhttp://www.tennettso.de/pages/tso_de/Transparenz/Veroeffentlichungen/Netzanschluss/Netzanschlussregeln/transpower-NAR2009eng.pdfhttp://www.tennettso.de/pages/tso_de/Transparenz/Veroeffentlichungen/Netzanschluss/Netzanschlussregeln/transpower-NAR2009eng.pdfhttp://www.50hertz-transmission.net/de/file/NANZR_50HzT_Stand_05_2008_(2).pdfhttp://www.bdew.de/bdew.nsf/id/DE_7B6ERD_NetzCodes_und_Richtlinienhttp://www.nationalgrid.com/NR/rdonlyres/67374C36-1635-42E8-A2B8-B7B8B9AF2408/44739/Z_CompleteGridCode_I4R5.pdfhttp://www.eirgrid.com/media/2011%20Mar%2008%20EirGrid%20Grid%20Code%20Clean%20Version%203.5.pdf

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While the intention of grid codes and other documents is to set out what is required for connection

to a particular system, these codes are not the only vehicle by which system operators and

regulators obtain desired performance standards. Grid codes reflect the concept of mandating

certain desirable technical capabilities, but delivery of the associated services is a separate, often

commercial, issue that may be managed through market mechanisms. There is a school of thought

that there should be minimal mandatory requirements and that the provision of necessary system

services should be incentivised through appropriate commercial mechanisms. The contrary view is

that the provision of necessary capabilities can only be ensured through mandatory provisions in

grid codes, licences, connection agreements or other documents. The standing which grid codes /

rules have and the degree of enforceability which results varies from one jurisdiction to another, so

any review of these rules should be complemented by looking at the penalty and incentive

mechanisms which also exist internationally. There are derogation procedures associated with grid

codes to handle temporary non-compliance which may arise due to plant breakdowns, and

permanent non-compliance where it may be infeasible or unreasonable to require full compliance.

4.2. Grid Codes and Wind GenerationThe modern development of wind power plants began with small units that were connected to

distribution systems. Standards or codes were applied to such generators with a view to

ensuring that they would not degrade system performance. It was expected that they would

disconnect in the event of any disturbance (both for distribution network safety and to protect

the wind power plant). The potential technical issues arising from large scale integration of such

machines was not recognized from the outset and so the needs of power systems were not

considered in their design. As wind generation developed to the point where it would form a

significant part of the total generation in a system or region, it became clear that a higher

standard of performance would be required.

Once wind generation reaches a level where it may displace other generators, the need to

provide services such as frequency regulation and control, operating reserves, reactive power

and voltage control etc. that would otherwise be provided by the displaced generators must be

considered. However, many grid code requirements then in force were not applicable to wind

turbine generators, or even if they were, the developers sought derogations from the codes on

the basis that it would be unreasonable or uneconomical for them to comply. Therefore special

grid code requirements for wind generators were developed and introduced in a number of

countries/regions.

1

Since then there has been conflict between wind plant developers and manufacturers on one hand,

and system operators on the other with regard to the reasonableness of grid code requirements. It

may be argued that services that can be provided economically by a synchronous generator cannot

be provided by a wind turbine generator without significant cost penalties, or that location-specific

services such as reactive power and voltage control are not required at the locations of many wind

farms. There is a considerable amount of literature on the topic, some academic, and some driven by

1

See for example: Fagan, E., Grimes, S., McArdle, J., Smith, P. and Stronge, M., Grid code provisions for windgenerators in Ireland, IEEE Power Engineering Society General Meeting, San Francisco, vol. 2, pp. 1241-1247,2005.

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the interests of the parties concerned.2 Furthermore, the scope of grid codes and the form in which

requirements are expressed varies from jurisdiction to jurisdiction. Manufacturers find it impractical

to develop a standard product to comply with all the different requirements, and have in some cases

indicated that they may not supply certain markets because of the difficulties of grid code

compliance. These issues have led, in Europe, to an initiative to harmonise grid codes. The European

Network of System Operators for Electricity (ENTSO-E) has produced a common set of draft

requirements for grid connection3 where specific values to be assigned to various parameters can

vary for different synchronous areas. The objective is eventual complete harmonisation which gives

rise to the risk of failing to take account of the genuinely different requirements of different power

systems depending on such issues as their size and the characteristics of other generation plant. In

the same way that the needs and issues of small synchronous system like Ireland and Northern

Ireland differ from those of mainland Europe, different requirements are likely to be appropriate for

Tasmania than for eastern and south eastern Australia. So a balance needs to be struck between, on

one hand, the benefits that arise from standardised requirements and the impact this may have on

future turbine development and on the other hand, the unique needs of each power system.

The integration of high levels of wind and other variable generation requires specific performance

not just from the variable generators, but also from the other conventional plant in the generation

portfolio. This may require review of technical requirements for conventional plant, or increased

emphasis on compliance with existing requirements.

Experience has shown that it is important to consider carefully the manner in which new

requirements are introduced and whether these requirements should apply to pre-existing wind

farms or not. Ill thought through or rushed implementation of new requirements, particularly if

onerous or expensive to comply with can cause long running issues in the industry which can be

difficult to resolve.

As well as technical performance requirements, grid codes also deal with the provision of technical

data on the plant to be connected to the grid, including all data necessary to carry out the full range

of system studies. In the case of wind turbine generators, particular issues have arisen in relation to

models for use in time domain dynamic simulation (transient stability studies). Ireland was at the

forefront in including a requirement for such models in the Grid Code. Subsequently in North

America the Western Electricity Co-ordinating Council distinguished between standard models that

could be used in system-wide studies, and specific models for use in interconnection studies. This is

discussed further in Section 9 below.

In comparing grid codes for wind generation it must be borne in mind that these codes were not

developed independently. The drafters of a grid code may be expected to have taken into account

provisions include in codes previously developed for other countries and systems.

2 See for example Van Hulle, Christensen, Seman, Schulz, European Grid Code Development the Roadtowards Structural Harmonization, Workshop on Large Scale Integration of Wind into Power Systems, QubecCity, October 2010, or Christensen, Grid codes, The Manufacturers Nightmare EWEC 2010, Warsaw - April

22. 20103 ENTSO-E Draft Requirements for Grid Connection Applicable to all Generators, March 2011,https://www.entsoe.eu/fileadmin/user_upload/_library/news/110322_Pilot_Network_Code_Connections.pdf

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5. Contingency Performance and Fault Ride Through5.1. IntroductionThe capability to withstand disturbances on the network which result in temporarily depressed

voltages is critical in maintaining power system stability and in preventing exacerbation of

disturbances leading to the risk of cascading outages. It is generally desirable that generators remain

connected for durations sufficient for the clearance of faults by the automatic actions of power

system protection, contribute to restoration of the voltage within normal limits and restore active

power contributions as soon as possible. Network faults and the corresponding voltage dips can

lead to significant imbalances between instantaneous mechanical power input and electrical power

output. This typically results in oscillations in active power output which must be adequately

damped following a disturbance.

5.2. Wind Turbine GeneratorsIn the initial phase of wind power integration, no specific performance standards were required ofwind turbines which were typically required to disconnect in the event of a disturbance to prevent

exacerbation of the fault and to protect the turbines themselves. As the potential for large scale

integration of wind power became apparent, the need for a contribution to system stability was

recognised leading to requirements for low voltage ride through in most of todays grid codes.

5.3. Specification of Voltage Ride through in Grid CodesGrid codes generally specify four main characteristic in relation to wind farm performance in the

event of a voltage disturbance:

Conditions for which the turbines must remain connected

Active power provision during fault

Voltage support requirements during the disturbance

Restoration of active power after the fault has been cleared

5.3.1. Conditions for which Wind Turbine Generators Must RemainConnected

The requirements in grid code specifying the conditions under which wind turbines must remain

connected generally take the form of a voltage vs. time profile which dictates the level of voltage

drop a turbine must be capable of withstanding along with the time for which the voltage drop

should be endured. Figure 5.1 below, illustrates this profile for all the grid codes examined in thisstudy. For each particular profile, during a fault, if the voltage at the grid connection point remains

above the corresponding line, the turbine must remain connected to the system.

While this voltage vs. time profile is a feature common to many grid codes, the type of fault to which

it applies is not consistent. For Ireland, UK, Denmark, Alberta and the draft ENTSO-E requirements,

the profile applies to faults on any or all phases, symmetrical or unbalanced faults. In the grid codes

of Spain and Quebec, there are reduced requirements for some types of fault, for example, in the

Spanish grid code, a three-phase symmetrical fault resulting in a voltage of 20% pu at the grid

connection point must be withstood for 500ms. However, for two-phase to ground faults, a voltage

drop to 60% must only be withstood.

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Figure 5.1: Voltage ride through Remain connected conditions in the grid codes examined.

The draft ENTSO-E requirements define two such voltage/time profiles, one representing the most

severe profile the TSO can require at its discretion, depending on system needs and the other

defining the minimum requirement. This envelope of allowed profiles is illustrated in Figure 5.2,

below.

Figure 5.2: Allowed voltage ride through requirements envelope for transmission connected wind farms, from the draft

ENTSO-E requirements.

The German transmission code also defines two profiles, denoted borderline 1 and borderline 2. If a

generator cannot meet the requirement defined by borderline 2, it may be possible to negotiate a

requirement between the two curves if a minimum reactive current feed-in during the fault can be

guaranteed and if resynchronisation time is decreased.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

-0.5 0 0.5 1 1.5 2 2.5 3

V (pu)

Time (s)

Ireland, Alberta

UK

Germany Borderline 2

Germany Borderline 1

Spain

Quebec

ENTSO-E - Type D Upper Bound

ENTSO-E - Type D Lower Bound

Denmark0.15

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Figure 5.3: Voltage ride through requirement from German Transmission Code 2007, showing borderline 1 and

borderline 2. A capability between these two curves can be negotiated with the TSO subject to the ability to deliver

reactive current during a fault.

5.3.2. Voltage Support during the FaultIn addition to remaining connected for the duration of a fault and the recovery period, many grid

codes also specify requirements for voltage support during the fault by means of a reactive current

injection. While all grid codes, with the exception of Alberta, Quebec and the UK, require some formof reactive support during the fault, there is no consistent formulation of the requirement.

The Irish grid code contains the requirement that reactive current should be maximised for

600ms or until the voltage has recovered to normal limits.

The ENTSO-E draft requirements allow TSOs to require reactive current to be prioritised. It

is presumed that the intention of this provision is to allow individual TSOs to require reactive

current maximisation during a fault.

The German, Spanish and Danish grid codes require a specific amount of reactive current as

a percentage of rated current, depending on the extent of the voltage drop.

The German Transmission Code 2007 requires that reactive current of 2% of rated current isprovided per percent voltage drop up to 100% rated current and that this is provided within

20ms. Similarly, the Spanish grid code requires that for voltage dips below 0.85pu, the

facility must provide reactive current at a rate of approximately 2.7% of rated current per

percent voltage below 0.85pu.

The Danish grid code contains the requirement that reactive power should be prioritised

over active power during a fault. For voltage dips below 0.9pu voltage at the point of

connection, the ratio of reactive to rated current should be as in Figure 5.4, below.

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Figure 5.4: Required ratio of reactive current to rated current for voltage dips in the Danish grid code.

5.3.3. Active Power Provision during the FaultAll grid codes examined either implicitly or explicitly permit some reduction in active power for theduration of a fault on the network. The Irish and UK grid codes contain the statement that active

power should be provided in proportion to the retained voltage. The Danish grid code states that if

possible, active power should be maintained and reduction in active power is allowed (within

plants design specifications). The Spanish grid code has detailed requirements on consumption of

active and reactive power during a disturbance, depending on the nature of the fault. These

generally prohibit active and reactive power consumption except in the first 150ms immediately

after the fault occurs and in the first 150ms after the fault has been cleared.

5.3.4. Active Power Recovery after Fault ClearanceThe Irish grid code requires that active power is restored to 90% of maximum available active poweras fast as the technology allows and faster than 1 second in any case. The UK grid code requires that

90% of active power is provided within 1 second of recovery of the voltage at the point of grid

connection. The grid code in Quebec contains the general requirement that Power producer

facilities must also help restore the power system to normal operating conditions after a

disturbance while the Spanish grid code requires that a facility must provide maximum current

possible (post fault and post clearance). The German Transmission Code 2007 requires that if a

facility is not disconnected, it must restore active power at a rate of 20% nominal capacity per

second, immediately after fault clearance. It also states that if a facility is disconnected, it must

reconnect with 2 seconds and increase active power output at a rate of 10% of the pre-fault active

power level per second. The draft ENTSO-E requirements require a TSO to specify the time within

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which a facility must restore its active power output to 85% of its pre-fault value and that this time

must be between 0.5 and 10 seconds (inclusive).

5.3.5. Additional Requirements Related to Voltage Ride ThroughThe UK and the draft ENTSO-E code require that active power oscillations are adequately damped.

5.4. NER Specification5.4.1. Conditions for which Wind Turbine Generators Must Remain

Connected

The requirements for low voltage ride through in the NER are expressed differently to the

corresponding requirements found in other grid codes making a direct comparison difficult.

However, with a number of assumptions, an equivalent voltage vs. time profile for specific cases in

the automatic access standard in NER can be derived for the purpose of comparison. From Table

S5.1a.2 of the National Electricity Rules, a three-phase fault must be cleared in 220ms at 100kV and

120ms at 250kV at worst,, with actual values depending on the clearing times of relevant primary

protection. Assuming a nearby generator sees a voltage of zero in each case, the voltage vs. time

profiles illustrated in Figure 5.6 result when assuming voltage recovery to 0.9pu in three seconds.

The actual recovery time is linked to the generating system performance for voltage disturbance,

and is worded such that the generating system must remain in continuous uninterrupted operation.

For comparison purposes, Figure 5.6 also shows the envelope of permitted voltage ride through

requirements for transmission connected wind farms in the ENTSO-E draft connection code. In NER,

a three phase fault at 220kV requires that a nearby generator must be capable of withstanding zero-

voltage for 120ms, whereas the ENTSO-E draft requirements require that zero voltage must be

withstood for 150ms meaning that this cannot be considered excessive. However, the voltage ridethrough requirement for a fault at 100kV would require a nearby generator to withstand zero

voltage for 220ms meaning that this is more onerous than any of the grid codes considered in this

study.

Figure 5.6: NER voltage ride through requirement for a 100kV and a 250kV connected wind farm seeing zero-voltage

following a three phase fault and assuming voltage recovery to 0.9pu within 3 seconds. Figure also shows ENTSO-Eenvelope of permitted requirements.

0%

10%

20%

30%

40%50%

60%

70%

80%

90%

100%

-0.5 0 0.5 1 1.5 2 2.5 3

V (pu)

Time (s)

ENTSO-E - Type D Upper Bound

ENTSO-E - Type D Lower Bound

NER 250KV

NER 100KV

0.15

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The minimum access standard in NER is similar to the Automatic standard with notable exception

being that there is no requirement to remain connected in the event of a three-phase fault. All the

grid codes examined in this study require wind turbine generators to withstand a three phase fault

on the transmission system.

5.4.2. Voltage Support during the FaultThe automatic access standard in NER is that a generator provide reactive current equal to 4% of

rated current for each 1% reduction in system voltage. This is higher than the Spanish requirement

for 2.7% reactive current for each 1% voltage drop which is the highest equivalent requirement in

the grid codes studied here. No reactive current injection is required in the minimum access

standard. This may not be consistent with a do no harm approach if generators are permitted to

consume reactive power in the event of depressed system voltage.

5.4.3. Active Power Recovery after Fault ClearanceThe automatic access standard in NER is that active power most be restored to 95% of the pre-fault

level within 100ms of fault clearance. This requirement is higher than that seen in any of the grid

codes studied here. In particular, the draft ENTSO-E requirements mention a range of 0.5 seconds to

10 seconds within which TSOs can require restoration of active power to 85% of the pre-fault level.

The minimum access standard is that after fault clearance, a generator must deliver sufficient active

power and supply or absorb reactive power necessary to restore the connection point voltage to the

normal operating range. This is consistent with a do no harm approach.

6.Active Power Control Requirements6.1. IntroductionControl of the active power output of generators in the electricity network is of fundamental

importance to system operators in order to maintain the supply/demand balance, thus maintaining

system frequency within acceptable limits and in order to control network flows and manage

congestion. In the early days of wind power integration where wind was simply treated as negative

demand, little was required by way of controllability of active power. As the percentage of wind

power became significant in many regions, the need for controllability was recognised and specific

requirements akin to requirements from conventional generators have become common place in

grid codes.

6.2. Wind Turbine GeneratorsWhile the output of a wind turbine will always be subject to primary energy source availability, some

control of active power output has generally been possible in wind turbine generators. With the first

fixed speed induction generator machines, crude control of active power was possible by

disconnection of individual turbines within the wind farm network. Fixed speed machines with blade

pitch control then emerged where continuous control of an individual turbines output was possible.

Since the advent of fixed speed, doubly fed induction generators and full convertor based machines,

power electronics permit arbitrary control of a turbines output subject to availability of the primary

energy source.

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6.3. Specification of Active Power Control Requirements in Grid CodesThe requirements in grid codes for controllability of active power differ in the amount of control

required, methods by which instructions should be accepted, the capability to limit the rate of

change of output and the time by which instructions should be acted upon and achieved. Standards

range from the requirement to disconnect in the event of a system constraint to the requirement to

accept a range of instructions containing active power and gradient set points automatically (as in

the Danish Grid Code, illustrated in Figure 6.1, below). The following section lists the various

requirements along with the grid codes in which they are required and this information is

summarised in Table 6.1, below.

Active Power Cap: This is where a wind farm is required to constrain its active power output

below a certain value. Of the codes examined, this is required in the vast majority of cases.

Gradient Constraint: This is where the rate of change of active power is limited to a certain

value, either on a standing basis as a static constraint agreed at the time of connection (as in

Ireland), or issued dynamically by the system operator as a setpoint (as in Denmark).Delta Control: This is where a wind farm is required to operate at a certain amount below its

maximum output to provide upward regulation and/or reserve capability. This is required

explicitly in Ireland and Denmark and implicitly (by virtue of the frequency control capability

required) in Spain and in the ENTSO-E draft requirements. In the Irish grid code, the

percentage amount by which a unit must operate below its maximum in order to provide

frequency regulation capability is a static value which does not change frequently. In the

case of the Danish grid code, this amount is variable and can be issued as a set point

instruction.

Requirement to Accept Electronic Dispatch Instructions: This capability is explicitly required

in Demark and Ireland and in the ENTSO-E requirements. It may be implied in other codes,depending on the interpretation of terms such as accept instructions in real time.

Accuracy of Compliance: The Danish grid code specifies minimum accuracies within which

active power output and the instructed level must agree. This is 2% of the instructed level or

5% of rated power, whichever yields the higher tolerance.

Time of Compliance: The codes of Ireland, Denmark and Alberta specify maximum times for

compliance with dispatch instructions. Demark requires implementation of instructions to

commence within 2 seconds of receipt of the instruction and to be fully implemented within

30 seconds. Ireland requires implementation of instructions to commence within 10 seconds

and the instruction to be implemented as soon as possible thereafter. Alberta requires that

the facility in question disconnect if the instruction to reduce output is not implemented

within 30 minutes.

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Figure 6.1: Instruction types illustration from the Danish Grid code.

Table 6.1

Summary of active power control requirements in the grid codes examined

Grid Code Output Cap Delta

Control

Gradient

Limit

Commence

Implementation

Time

Implementation

Time

Ireland Yes Yes As set by TSObetween 1and30MW/min

10 seconds ASAP

UK No requirements specified

Denmark Yes Yes As instructedby TSO

2 seconds 30 seconds

Spain Yes Yes

Germany Yes 10%/min

Alberta Mustdisconnect ifnot capable

10%/min 10 minutes

Quebec No requirements specified

ERCOT Yes

ENTSO-E Draft

Requirements

Yes Yes (Types

C,D)

20%/min

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6.4. NER SpecificationThe automatic access standard in the NER requires that output be increased or decreased within 5

minutes to a level at or below that instructed by AEMO and that output does not change by more

than instructed raise/lower amounts for 5 minutes. Furthermore, the facility must ramp linearly

from one dispatch level to another. This standard is consistent with some of the most advanced

requirements examined here with the possible exception of the capability to operate in delta control

mode and specific requirements around time to and accuracy of compliance. A limit on the rate of

change of output is implicit in the requirement to ramp linearly within 5 minutes.

The minimum NER standard is the capability to maintain and change active power output in

accordance with dispatch instructions. The negotiated standard also allows for requiring a generator

to upgrade its systems to implement electronic instructions if the frequency of instructions becomes

difficult to manage. The minimum standard together with the right to require upgraded systems in

the event that they are required is consistent with the do no harm philosophy.

7. Frequency Control7.1. IntroductionThe rotating masses of conventional synchronous machines contribute fundamentally to frequency

stability and control in the system. Regulation of rotational speed through governor action controls

frequency while inertia of the rotational masses of synchronous machines acts to limit the rate of

change of frequency in the event of a disturbance.

7.2. Wind Turbine GeneratorsIn the most common types of wind turbines being deployed today, namely doubly fed induction

generators and full converter based machines, the rotational masses are decoupled from system

frequency through the use of power electronics. Even so-called fixed-speed machines using

induction generators are only loosely coupled to system frequency. Significant deployment of these

technologies can decrease total inertia on the system thus increasing the need for frequency

regulation but reducing the total regulation capability available. If system stability is not to be

degraded by deployment of these technologies, the inertia and frequency control capability of the

conventional machines which are displaced must be replaced.

7.3. Specification of Frequency Control Capability in Grid CodesThe grid codes of the countries examined in this study almost universally require a degree of

frequency control capability from wind turbine generators. This can vary from a requirement to

proportionally reduce output in the event of over frequency (as in Germany), to providing multi-

stage frequency response with a controller capable of implementing multiple configurable droop

characteristics with configurable dead-band (as in Denmark).

7.3.1. Limited Frequency Sensitivity mode and Frequency Control ModeThe grid codes of Ireland, the UK and the draft ENTSO-E requirements provide for two types of

frequency response and require that wind farms are capable of both and can be switched from one

to the other as the need arises. The first of these is referred to as Limited Frequency Sensitivity

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mode in the UK and ENTSO-E requirements and as Frequency Control Curve 1 in the Irish Grid

code. The second type of response provides for frequency regulation capability from wind farms.

7.3.2. Limited Frequency Sensitivity ModeThis frequency control capability is required in Germany, Ireland, the UK, in the draft ENTSO-E and in

ERCOT requirements. This response requires that wind turbines reduce power output at a rate of

40% of the generators instantaneous available capacity per Hertz when the system frequency rises

above 50.2Hz. Figure 7.1, below, is taken from the German Transmission Code 2007 and illustrates

this capability requirement. The UK grid code provides for a similar type response on the low

frequency side also.

Figure 7.1: Frequency control capability required in German Transmission Code 2007

7.3.3. Frequency Regulation using Configurable Droop Characteristicwith Deadband Control

This type of control requires a wind farm to operate at a level below its instantaneous available

capacity to provide upward and downward frequency regulation capability. Typically, there is a

control dead-band which is configured according to TSO requirements within which generator

output is independent of frequency. Above this, on the high frequency side, the generator output

will decrease linearly with frequency at a rate specified by the TSO until the high frequency limit isreached where it is permissible to disconnect. Similarly, on the low frequency side, the generator

output will increase linearly with frequency at a rate specified by the TSO until the low frequency

limit is reached or output is limited by primary energy source availability. This type of control

capability is required in Ireland, the UK and Spain. The implementation of this requirement is slightly

different in the Irish grid code in that the amount of downward regulation required to provide

under-frequency response in essentially fixed (i.e. is parameter specified by the TSO at the time of

connection). Most other grid codes (UK, Spain and Denmark for example) formulate the frequency

control requirement with reference to an arbitrary operating point below the instantaneous

capability which allows for frequency regulation at any dispatch level below this point.

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Figure 7.2: Frequency Response Curve Required in Irish grid code.

7.3.4. Frequency Regulation with Multi-Stage ResponseThis type of control is similar to the configurable droop characteristic mentioned above, but features

additional configurable points which provide for a two-stage response with different droop

characteristics and frequency insensitivity ranges. Figure 7.3, below, is taken from the draft ENTSO-E

requirement and illustrates this frequency response requirement. This requirement applies to wind

farms of 400MW or those connected to the transmission system in the draft ENTSO-E requirements.

The Danish grid code has a similar, but more generally configurable response which is illustrated in

Figure 7.4, below. The Danish code allows for 7 TSO-specified frequency points providing for 4

distinct droop values in total.

Figure 7.3: Frequency control capability from the ENTSO-E Draft connection code.

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Figure 7.4 Frequency Response Curve from the Danish Grid Code

7.3.5. Frequency Remain Connected RangeMost grid codes specify the range of frequencies within which a wind turbine must remain

connected and also the length of time for which they must remain connected for. Some countries

also specify what rates of change of frequencies must be withstood. Figure 7.5 and Table 7.1, below,

summarise these for the grid codes studied.

Table 7.1

Frequency and Rate of Change of Frequency (ROCOF) Limits

Grid Code FrequencyMinimum

Frequency

MaximumROCOF

Ireland 47 Hz 52 Hz 0.5Hz/s

UK 47 Hz 52 Hz

Denmark 47 Hz 52 Hz 2.5Hz/s

Spain 47.5 Hz 51.5 Hz 2Hz/s

Germany 47.5 Hz 51.5 Hz

Alberta 57 Hz 61.7 Hz

Quebec 55.5 Hz 61.7 Hz

ENTSO-E Draft

Requirements

2Hz/s

Remain connected for1.25s over 2Hz/s

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Figure 7.5 Graph showing the length of time a wind power plant must remain connected to the transmission for

different frequency ranges for different 50Hz systems.

Figure 7.6 Graph showing the Automatic and Minimum Access Standards governing the length of time a wind power

plant must remain connected to the Australian Mainland transmission system.

47

47.5

4848.5

49

49.5

5050.5

51

51.552

0 10 20 30 40 50 60 70 80

Frequency

(Hz)

Time (Minutes)

Frequency Remain Connected Ranges

Germany

Denmark

Ireland

UK

4747.5

48

48.549

49.5

5050.5

51

51.552

0 10 20 30

Frequency

(Hz)

Time (Minutes)

Australian Remain Connected Ranges

Mainland AutomaticStandard

Mainland Minimum9 seconds9 seconds

Continuous

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Figure 7.7 Graph showing the Automatic and Minimum Access Standards governing the length of time a wind power

plant must remain connected to the Tasmanian transmission system.

7.3.6. Additional Frequency Control RequirementsAccuracy of frequency measurement: The Danish grid code requires that the controller

frequency measurements are accurate within 10mHz.Controller Cut-out on under-voltage: The Spanish grid code requires the frequency

controller to cut-out momentarily when the voltage falls below 0.85pu in order to avoid

conflicting actions interfering with local voltage control.

Inertia Emulation: The Grid code of Quebec requires wind farms over 10MW to have a

frequency control capability which can reduce short term frequency deviations by an

amount equal to that of a conventional generator with an inertial constant (H) of 3.5s. The

Spanish grid code does not require inertia emulation capability, but does impose specific

requirements on the operation and design of the control where a wind turbine generator

has this capability. Requirements are specified regarding the gain adjustability, speed of

response, magnitude of response available and the requirement to have energy storageavailable which allows injection of 10% rated power within two seconds.

Turbine vs. aggregate control: The UK grid code explicitly states that the frequency

controller may act on individual turbine outputs or on the output of the wind farm in

aggregate or on a combination of both.

46

47

48

49

50

51

5253

54

55

0 10 20 30

Frequency

(Hz)

Time (Minutes)

Tasmanian Remain Connected Ranges

Tasmania Automatic

StandardTasmania Minimum

9 seconds9 seconds

Continuous

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7.4. NER Specification7.4.1. Disturbed OperationThe NER specifies requirements for remaining connected to the transmission system during

frequency deviations following a system disturbance and these cover rate of change of frequency as

well as remaining in operation for particular frequency ranges for certain times. The rules are

defined in terms of frequency ranges and times defined in the relevant frequency standard for that

area as determined by the Reliability Panel. This allows for different frequency standards in

different regions (for example, Tasmania has wider frequency bands, as it is an island, with a HVDC

connection to the main system, whereas in the mainland the frequency bands are tighter). Figure

7.5, above, shows the length of time for which a unit must remain connected for given system

frequencies.

7.4.2. Rate of Change of FrequencyThe preceding requirements in NER for remaining connected during a frequency disturbance apply

when the rate of change of frequency is within certain limits. Outside these limits, the unit is not

obliged to remain connected. The automatic standard is that generators are not bound by the

conditions in Section 7.3.1 when the magnitude of the rate of change of frequency exceeds 4Hz/s.

The next most onerous condition observed in the grid codes examined is that of Denmark where the

equivalent rate of change of frequency limit is 2.5Hz/s. The minimum access standard in the NER is

that units must remain connected for the durations specified unless the magnitude of the rate of

change of frequency exceeds 1Hz/s. The least onerous equivalent condition observed in the grid

codes examined (where rate of change of frequency is mentioned) is that of Ireland where the

equivalent limit is 0.5Hz/s. However, the recent TSO Facilitation of Renewables studies

commissioned by EirGrid found that if generation actually disconnects during voltage or frequencydisturbances which result in a rate of change of frequency in excess of 0.5Hz/s, this would pose a

serious risk to system stability to the extent that instantaneous wind penetration has been limited to

50% until this issue is resolved. It is concluded that 1Hz/s would appear to be broadly consistent with

the do-no-harm principle. However, appropriate studies of the Australian system would be required

to confirm this.

7.4.3. Frequency ControlThe automatic access standard for frequency control in NER is that a generator must be capable of

automatically adjusting output when system frequency is outside of the normal operating frequency

range. This is similar to the droop characteristic described above, except that the maximum droop isspecified in the rules rather than being specified by the network operator.

The minimum access standard is that generator output does not increase in response to a rise in

system frequency and that output does not decrease by more than 2% per Hz in response to a fall in

system frequency.

The negotiated access standard requires that the frequency response from the generation system is

as close to the automatic access standard as the technology allows.

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The minimum standard in the grid codes examined in this study is that a generator is capable of

automatically reducing output proportionally in response to a rise in system frequency above a

certain threshold level.

8. Reactive Power and Voltage Control8.1. Reactive Power Capability Requirements8.1.1. IntroductionSynchronous machines have an inherent reactive power capability, controlled by excitation control.

Over-excitation, delivering capacitive reactive power to the system is normally limited by either

exciter current limits or stator current limits. Under-excitation, delivering inductive reactive power,

is normally limited by stability considerations. In integrated utilities, the reactive capabilities of

individual machines were normally a matter for negotiation internally. Greater capacitive capability

could normally be achieved at some cost increase due to the greater alternator and exciter ratingsrequired. On the other hand turbine improvements leading to increased output could lead to

reduced reactive capability if the alternator rating was not also increased.

With the opening of electricity generation to competition, grid codes specified minimum reactive

capabilities, as measured at the generator terminals, as these were the parameters generally known

to generator owners.

8.1.2. Wind Turbine GeneratorsWhen wind generation began to be developed on a significant scale, the generators were fixed

speed induction machines which draw inductive reactive power from the system. The reactivepower requirements of an individual machine at any particular level of output and terminal voltage

are fixed in the steady state, but will vary under transient conditions. It will also vary as output varies

and as terminal voltage varies. For most installations some or all of this reactive requirement is

compensated by the installation of shunt capacitors. Compensation is sometimes limited by

concerns about self-excitation if the generator becomes isolated from the system. The level of

compensation is normally agreed between the wind generation owner/developer and the (usually

distribution) network operator. The level might vary depending on network conditions, or a network

operator might adopt a standard range of acceptable power factors. This might have been expressed

as an acceptable power factor at full output, enabling a fixed capacitor installation, or an acceptable

range of power factors throughout the operating range, which would be likely to lead to a

requirement for switched capacitor stages.

When larger wind generation installations requiring connection at higher voltages and thus

compliance with grid codes began to be developed, the difficulty of designing a wind installation to

match a performance that was specified with synchronous machines in mind emerged. Wind

developers began to look for derogations from grid codes, and TSOs began to develop grid code

requirements more suited to wind generation technology. At the same time wind turbine generator

technology evolved with the development of variable speed technologies using power electronic

converters, which enabled variable power factor operation.

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A number of issues arise when considering the specification of generally-applicable reactive ranges

for wind generation installations:

In many codes, requirements for synchronous machines are specified at the machine terminals

as these are well understood and this is traditionally the point at which the output is metered,

although it is conceptually more appropriate to specify requirements at the interface betweenthe network and generation installation. However, a wind installation is typically widely

dispersed with multiple generators and an extensive collector network. Therefore the

relationship between machine capability and capability at the interface point will vary from one

installation to another.

The design implications of different reactive capability requirements are not certain, and will

vary between installations, technologies, manufacturers etc. Therefore the cost implications are

not necessarily well understood.

For synchronous machines, the dependence of the reactive capability on terminal voltage is

understood, as the limits are virtually all current limits, and the machine terminal voltage can

normally be controlled within tight limits. The variation of wind farm reactive capability as

interface point voltage varies is more complex.

System reactive power requirements are location dependent and wind generation is often

located in weak parts of the network. Therefore a general reactive requirement based on

synchronous machine capability could result in investment in reactive power capability which is

never needed at its location. Furthermore, utilisation of the full reactive power capability of a

generator located in a weak part of the network may result in unacceptably high voltages near

the generator site without impacting significantly on the grid voltage, therefore resulting in

unusable reactive capability due to the characteristics of the local network

Synchronous machines are dynamic reactive power sources, and thus contribute to voltageregulation and voltage stability. Wind farms may depend on static devices (such as capacitors

which in addition have voltage squared output dependence) and thus may not deliver the same

performance even if they have the same nominal capacity.

8.1.3. Specification of Reactive Requirements in Grid CodesAll Grid Codes reviewed include specific reactive power specifications for wind (or renewable)

generation. However they vary in respect of the point at which the requirement is specified, range of

voltage at the connection point considered, the extent to which exceptions are envisaged, as well as

the actual specification of the capability, whether it is expressed in terms of power factor, reactive

power expressed as a fraction of rated power or otherwise. It should be borne in mind that gridcodes will to a greater or lesser extent have been influenced by codes developed earlier in other

jurisdictions.

The reactive power specifications are summarised in Table 8.1 and are discussed in the following

paragraphs.

Several codes express the reactive power requirement at the interface point or point of connection,

whereas others express requirements at the low voltage side of the main grid transformer, perhaps

because this is closer to the way requirements for synchronous machines were expressed, metered

and understood traditionally.

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Table 8.1 - Reactive Power Requirements

Code Reactive Requirement Specified atReactive Power Range

(p.u. of full output)

Equivalent full

load power factor

Denmark Grid Connection Point -0.33 0.33 0.95 0.95

GermanyGrid Connection Point(Transmission Code)

-0.228 0.48-0.33 0.41

-0.41 0.33 *

0.975 0.90.05 0.9250.925 0.95

UK Grid Entry Point 0.95 0.95

Ireland LV side of grid transformer -0.33 0.33 0.95 0.95

Spain -0.3 0.3

Texas Point of interconnection 0.95 0.95

AlbertaLow voltage side of transmissiontransformer

0.95 0.9

QubecHV side of transformer at point ofinterconnection

0.95 - .95

Ontario Connection point -0.33 0.33

ENTSO-E

High-voltage terminals of the step-uptransformer to the voltage level ofthe Connection Point

Range equivalent to 0.75 puMust lie between -0.5 ind and

0.65 cap

Must lie between0.894 ind and

0.838 cap

Australia Connection Point 0.395 (automatic)

* The German Transmission Codes provides for three variants, one of which is selected by the TSO,depending on network requirements

Figs 16 and 17 ofthe Danish Technical regulation 3.2.5 for wind power plants with a power output

greater than 11 kW, September 2010, shown below (Figs 8.1 and 8.2 in this document), illustrate

how these requirements are expressed in many codes. Fig 16 shows that the reactive requirement is

specified as a fraction of rated power over most of the operating range. This is generally deemed

reasonable as it is likely that most wind turbine generators in a farm will be operating over a wide

range of output. In Denmark, Spain, this range goes down to 20% of rated output, in Ireland 50%and in Texas 10%. In Quebec, the requirement is related to the wind generators in service. In many

other countries and systems such as Germany and the UK the requirement is expressed in terms of

power factor. Below the constant reactive requirement range a constant (minimum) power factor

is specified.

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Figure 8.1 (Figure 16 from Danish Technical regulation 3.2.5) showing reactive power requirements for wind power

plants greater than 25MW

Figure 8.2 (Figure 17 from Danish Technical regulation 3.2.5) showing the voltage control range for wind power plants

greater than 25MW

These Danish requirements illustrate a number of other features:

The reactive requirement, both capacitive and inductive, is reduced above 80% output, going

from reactive power equivalent to 0.95 power factor at full load at 80% output to 0.975 power

factor at full load. This probably reflects a reduced requirement for reactive at high levels of

active power, coupled with the increased cost of providing for simultaneous maximum active

and reactive output. In Spain only the capacitive requirement is reduced above 80% output. In

Ireland there is no reduction. In Qubec it is stated that if studies show that the reactive power

cannot be completely utilised, a higher power factor (than 0.95) may be accepted, but never

higher than 0.97.

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The reactive requirement is reduced for voltages above or below nominal voltage, on the basis

that maximum inductive reactive capability is unlikely to be required at low system voltage or

maximum capacitive capability at high system voltage. The German variants also display voltage

dependent requirements.

The Alberta code, which expresses requirements in terms of power factor, explicitly requires that asubstantial proportion of the reactive capability be dynamic. Other codes do not have such a

specific provision, but other code requirements such as those related to fault ride through and

voltage regulation are likely to require that a substantial proportion of the reactive capability be

dynamic.

As summarised in Table 8.1, there are some variations in the actual values of reactive power

specified, but a power factor of 0.95 is common.

8.1.4. NER SpecificationThe Automatic Access Standard requires reactive capability at the connection point equivalent to apower factor of 0.93 at full output throughout the operating range of voltage (+/- 10% of normal

voltage) and active power. The minimum access standard is no capability to supply or absorb. The

guidelines for negotiation require that a negotiated standard be sufficient to ensure that all system

standards are met, and provide for a requirement to install supplementary equipment or for the

generator and NSP enter into an appropriate commercial arrangement.

In South Australia a reactive capability equivalent to a power factor of 0.93 at full output is specified.

In addition, 50% of the capability must be dynamic.

Comments:

The minimum standard, stated as no capability to supply or absorb is taken to mean that the

generator must at least be able to maintain zero reactive exchange with the system. This standard

would seem to be below the no harm level, as varying output from a generator with zero reactive

exchange will lead to voltage variations, depending on the strength and reactance to resistance ratio

of the network at the point of connection. Furthermore, this zero reactive exchange requirement

does not exploit the inherent capability of virtually any generation installation.

The negotiated approach facilitates system optimisation, but imposes a significant burden on

NSP/AEMO to carry out studies and establish long-term system requirements. Can long term

envisaged developments be taken into account? Is there a need for a longer-term plan including

reactive power to inform the negotiated approach?

8.2. Voltage Control Capability8.2.1. IntroductionVoltage control by synchronous generators is fundamental to the control and stability of power

systems, and voltage control capability is a requirement of virtually all grid codes. With the

widespread deployment of wind generation voltage control requirements were deemed to apply for

transmission level connections. However, it was necessary to re-draft code requirements because of

the different generator technologies used. Voltage control capability is sought from wind generation

because:

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Wind generation is perceived as displacing conventional generation which has voltage control

capability

Wind generation, due to its variations, can lead to voltage fluctuations on the system. A voltage

control capability would mitigate these variations.

The use of voltage source converters in the interface between the wind generator and the

power system would tend to facilitate voltage control.

However, it would appear that voltage control for a wind farm is normally implemented through a

centralised controller which determines reactive power set points for the individual wind turbines or

other devices in the wind farm. This can inhibit rapid response to system changes.

8.2.2. Voltage control requirements in grid codesVoltage control requirements are expressed in a variety of ways in grid codes. The issues specified

can include:

The ability to receive a set point (which may be local to the wind farm or remote)Range of set points

Droop settings

Time to change a set point

Transient response to step changes

The requirements in various grid codes are summarised in Table 8.2, and are discussed in further

detail below.

The UK Grid Code requires continuous steady state control of voltage at the grid entry point, with a

set point voltage and slope characteristic as shown in Fig CC.A.7.2.2a reproduced below (Figure 8.3in this document). The controller must be capable of the following

The slope must be adjustable over a range of 2% to 7%.

Deviations from set point to be corrected within 5s.

The time to implement a new set point or slope does not appear to be stated.

The response to a step change to commence within 0.2s, with 90% of the plant capability to

be produced within 1s.

The settling time must be less than 2s, with peak to peak reactive power oscillations no

more than 5% by that time.

The Irish Grid Code is similar albeit less specific. It requires a similar response to that of a

synchronous generators automatic voltage regulator. The voltage set point is at the HV side of the

interface transformer, which is normally also the connection point. The slope must be adjustable

over a range of 2% to 10%. A change to the voltage set point must be capable of being received

automatically and of being implemented within 20s. Two weeks notice is required for a change in

the slope setting. 90% of the steady state response to a step change in set point or voltage must be

achieved within 1s.

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Table 8.2

Voltage Control Requirements

Code Control Specified Set Points Specified Droop Settings Transient Response Set Point Changes

Denmark

Reactive Power ControlPower Factor ControlVoltage Control (> 25 MW)

Required 10 s

Germany

Reactive Power ControlPower Factor ControlVoltage Control

Immediate 1 min

UK 95% - 105% 2% - 7% 90% within 1 s

Ireland Voltage regulation similar to AVR HV side of grid transformer 1% - 10% 90% within 1 s 20 s

Spain AVRVoltage, Reactive or Power Factorset points

0 25(Mvar pu/Voltage dev pu)

Full response in 1 min

Texas

Must be capable of producing a definedquantity of Reactive Power to maintain aVoltage Profile established by ERCOT

Alberta

Continuously-variable, continuously-acting,closed loop control voltage regulationsystem.

95% - 105%Reactive current compensation

0 10% 95% in 0.1s to 1s

QubecAVR system comparable with synchronousgenerator

0 10%

Ontario AVR95% - 105% of rated voltageNot more than 13% impedancefrom HV terminal

50 ms for 5% step

ENTSO-E

Reactive Power ControlPower Factor ControlVoltage Control

95% - 105% 2% - 7% 90% within 1 s

Australia

(Automatic)

95% - 105% of normal voltageReactive current compensation

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Figure 8.3 (Figure CC.A.7.2.2a from National Grid UK Grid Code) showing the UK voltage control requirement for wind

power plants.

In Denmark, Germany and Spain there is provision for power factor control, reactive power control

or voltage control. The German Transmission Code states only that the generator voltage control

must take immediate action in the case of voltage changes. A new set point must be implemented

within 1 minute. In Denmark, set point changes must be implanted within 10s. There is provision for

a droop setting. In Spain, the slope can range between 0 and 25 (Mvar p.u. / Voltage deviation p.u.);

the entire response to a change must be achieved within 1 minute.

Alberta requires a continuously-variable, continuously-acting, closed loop control voltage regulation

system. The set point can range from 95% to 105%, and the droop 0-10%. Reactive current

compensation may be required. 95% of the response to a step change must be achieved between

0.1s to 1s after change. Qubec also requires a droop setting between 0 and 10%.

8.2.3. NER RequirementsThe NER requirements with regard to voltage control are largely technology neutral without specific

requirements for wind or asynchronous generation.

The NER minimum access standard is essentially that the generator should not degrade system

performance or inhibit the NSP in achieving its performance standards. It should have power factor

or reactive power control. The automatic access standard provides for a voltage set point range of

95% to 105% of normal voltage, and for reactive current compensation. It specifies transient

response requirements as a rise time of less than 2s for a 5% step and for a settling time of 5s to

7.5s. The negotiated standard must be the highest level that the generator can reasonably achieve

including by installation of additional dynamic reactive power equipment, and through optimising its

control systems.

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The Essential Services Commission of South Australia (ESCOSA) Licence Conditions for wind

generation in South Australia provide for reactive power or power factor control, with the capability

of switching to a voltage support mode during disturbances.

The negotiated standard requirements appear to allow AEMO and the relevant NSP to obtain a high

level of voltage control capability from generators, where it is required.

9. Requirement to provide a dynamic model9.1. IntroductionTime domain dynamic simulation is widely used to investigate transient stability in power systems,

and standard models have been developed for most power system equipment such as round-rotor

and salient pole synchronous machines, excitation/automatic voltage regulation systems, power

system stabilisers, speed governing systems, static Var compensators, DC links etc. Power system

analysis suites generally include a library of standard models together with a facility for user-developed models. Standard models for some equipment such as governors and excitation systems

have been proposed through IEEE to encompass most types of these devices encountered on power

systems.

When commercial wind generation first became a reality, incorporation of wind generation in

dynamic simulations was not a significant issue because (1) the proportion of wind generation was

small and was not therefore expected to have a significant impact on system performance and (2)

most wind generation was expected to be tripped by interface protection during system

disturbances and thus would not impact on system performance in the critical period immediately

after the disturbance. However, as penetration of wind generation increased, automaticdisconnection for system disturbances was no longer acceptable. This combined with the increased

impact of the larger amount of wind generation meant that wind could potentially affect system

transient stability, and it would therefore be necessary to include wind generation in dynamic

simulations.

9.2. Issues relating to modelling of WTGs9.2.1. Initial development of models for transient stability studiesEarly wind turbines used fixed speed induction generators, possibly with pitch control to improve

energy capture over a range of wind speeds. Although stability programs typically included modelsfor induction generators, these did not take account of the effect of the wind turbine, and its

controls, on the power system. A considerable amount of research on modelling wind turbine

generators for system stability studies was published, especially in the early 2000s4. At the same

time, wind turbine generators were becoming more sophisticated with the adoption of variable

speed technologies with power electronic converters. The introduction of requirements to ride

through disturbances rather than trip meant manufacturers had to develop ride through strategies

4 See, for example; Akhmatov, V., Analysis of dynamic behaviour of electric power systems with large amountof wind power, PhD thesis, Technical University of Denmark, April 2003. Available at

http://www.dtu.dk/upload/centre/cet/projekter/99-05/05-va-thesis.pdfand Slootweg J. G., de Haan, S. W. H,Polinder, H., Kling, W. L., General Model for Representing Variable Speed Wind Turbines in Power SystemDynamics Simulations, IEEE Transactions on Power Systems, Vol. 18, No. 1, February 2003

http://www.dtu.dk/upload/centre/cet/projekter/99-05/05-va-thesis.pdfhttp://www.dtu.dk/upload/centre/cet/projekter/99-05/05-va-thesis.pdfhttp://www.dtu.dk/upload/centre/cet/projekter/99-05/05-va-thesis.pdf

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that would protect the converters from over voltage or over current, while remaining connected to

the network. Manufacturers were anxious to protect their intellectual property in these concepts

and designs, and were (still are?) unwilling to divulge details of their control systems.

9.2.2. System Operator and Manufacturer PerspectivesThere are also conflicting perspectives from network operators on the one hand and WTG

manufacturers on the other with regard to the development of dynamic models.

Network operators require models that will represent with sufficient accuracy those aspects of

WTG performance that will affect system stability, but without unnecessary detail that might

affect the ability to run simulations for extensive networks with large numbers of machines.

Models must be able to self-initialise successfully (i.e. determine values for all internal variables

from boundary conditions in a loadflow study). In the event of a simulation failing, network

operators will want to be able to investigate and find the source of the problem. Network

operators will want the models to be validated, so that they can have confidence in simulation

results. It would be preferable to use standard models that are incorporated in the power

system analysis package by its developers, rather than special-purpose user-written models

that must be incorporated by others, leading to additional risks of difficulty setting up and

running simulations.

Wind turbine generator manufacturers are concerned with achieving a high degree of modelling

accuracy: they want to avoid the risk of actual plant performance differing from model-predicted

performance under any conditions. They also want to protect their intellectual property. They

also appear to have attempted to adapt models developed for machine design purposes for use

in transient stability models. The resulting models have been found to be excessively complex,

to incorporate very short time constants and to be unsuitable for use in large scale systemsimulations5.

9.2.3. Standard Models or Manufacturer-Specific ModelsThe system operators preference, mentioned above, for models that would be integrated easily in

stability studies, and that would