Grid Code Frequency Response Working Group Requirements for

Grid Code Frequency Response Working Group Requirements for System Inertia Antony Johnson, System Technical Performance

Overview ® Resume’ of System Inertia ® Future Transmission System need ® System Studies ® Requirements and issues for System Inertia ® Proposals ® Conclusions

Resume’ of System Inertia ® Inertia is the stored rotating energy in the system ® Following a System loss, the higher the System Inertia (assuming no frequency response) the longer it takes to reach a new steady state operating frequency. ® Modern Generation Technologies employing power electronic converters currently do not contribute to System Inertia ® ie the equivalent of a vehicle travelling down a hill without engine breaking ® Under the Gone Green Scenario in 2020 over half the generation fleet is likely to comprise of such technologies. ® Further growth is expected in HVDC which currently does not contribute to System Inertia ® The implications of this are a substantial erosion in System Frequency Control and consequent required increases in additional reserve and response ® Additional background information is available from the presentation given at the Frequency Response Working Group Meeting of 15 February 2010

The maths behind inertia Typical H for a synchronous generator can range from 2 to 9 seconds (MWs/MVA)

An NGET Future Scenario ‘Gone Green 2020’ ®Plant closures ® ® ® 12 GW Coal & oil LCPD 7. 5 GW nuclear Some gas & additional coal ®Significant new renewable ® ® ® 29 GW wind (2/3 offshore) Some tidal, wave, biomass & solar PV Renewable share of generation grows from 5% to 36% ®Significant new non renewable build ® ® 3 GW of new nuclear ® 11 GW of new gas 3 GW of new supercritical coal (some with CCS) ®Electricity demand remains flat (approx 60 GW) ® ® Reductions from energy efficiency measures Increases from heat pumps & cars

Test Network ® Simplified GB system representation ® 25 GW demand ® 11 generators ® Frequency Response selected between 3 – 6 Generators depending upon Inertia - Green ® 1320 MW Loss - Red ® No Load Response ® Additional Reserve Calculated Depending upon System inertia

1320 MW Loss – Effect of Inertia and FR Full H – Three Machines selected for FR to achieve 49. 19 Hz (approx 49. 2 Hz) H/2 – Six Machines selected for FR to achieve 49. 19 Hz (approx 49. 2 Hz) F = 49. 19 Hz H/2 – Three Machines selected for FR as in Red Curve

1320 MW Loss – Effect of Inertia and FR H/2 – Six Machines selected for FR to achieve 49. 19 Hz (approx 49. 2 Hz) – Blue H/2 – Three Machines selected for FR as in Red Curve - Green Full H – Three Machines selected for FR to achieve 49. 19 Hz (approx 49. 2 Hz) - Red Frequency Insensitive Plant Frequency Sensitive Plant

Test Network ® Simplified GB system representation ® 25 GW demand ® 11 generators ® Frequency Response selected between 3 – 6 Generators depending upon Inertia - Green ® 1320 MW Loss - Red ® Load Response Both Frequency and Voltage ® Additional Reserve Calculated Depending upon System inertia

1320 MW Loss – Effect of Inertia alone with V/F Load Response Full H, No Frequency Response and Load Response H/2, No Frequency Response and Load Response

1320 MW Loss – Effect of Inertia and Frequency Response with Load Response Full H – Two Machines selected for FR to achieve 49. 235 Hz H/2 – Three Machines selected for FR to achieve 49. 215 Hz H/2 – Two Machines selected for FR as in Base Case – Minimum Frequency 49. 124 Hz

1320 MW Loss – Effect of Inertia and Frequency Response with Load Response H/2 – Two Machines selected for FR as in Base Case – Minimum Frequency 49. 124 Hz - Green H/2 – Three Machines selected for FR to achieve 49. 215 Hz - Blue Full H – Two Machines selected for FR to achieve 49. 235 Hz - Red Frequency Sensitive Plant Frequency Insensitive Plant

Test Network ® Simplified GB system representation ® 25 GW demand ® 15 generators ® 1800 MW Loss - Red ® Load Response Both Frequency and Voltage Frequency – ®selected Response between 3 10 Generators depending upon Inertia – Green ® Load Reduction introduced for comparison purposes

1800 MW Loss – Effect of Inertia alone with V/F Load Response Full H, No Frequency Response and Load Response H/2, No Frequency Response and Load Response

1800 MW Loss – Effect of Inertia, Frequency Response and Load Reduction with V/F Load Response Full H, 10 Machines providing Frequency Response f = 49. 107 Hz 2 H, 10 Machines providing Frequency Response f = 49. 289 Hz Full H, 6 Machines providing Frequency Response, 480 MW of load reduction at 4 seconds f = 49. 203 Hz Full H, 3 Machines Providing Frequency Response (in 1320 MW case frequency above 49. 2 Hz) Full H, No Frequency Response and Load Response H/2, No Frequency Response and Load Response

Assessment of Study Work ® Inertia has a significant effect on System Frequency ® Increased rate of change of frequency (Hz/s) for a lower system inertia ® With Frequency response included, the minimum recorded system frequency is increased ® If System Inertia is allowed to drop substantially additional fast acting Reserve / Response will need to be scheduled at additional cost to ensure standards of security are maintained. ® Fast Acting Load Reduction (ie block tripping) is more effective than that provided by Generators in containing a frequency fall ® There needs to be co-ordination between requirements for inertia, delivery of primary response and delivery of secondary response – 10% P, 10% S and 10% H is only adequate if Generators / loads adequately contribute towards system inertia ® Under an 1800 MW loss scenario the need for system inertia becomes even more critical ® Analysis undertaken to date demonstrates the need for Generators and HVDC Converter Owners to contribute towards System Inertia unless additional reserve is scheduled at considerable cost

Requirements for Inertia ® Contribution towards System Inertia can be achieved by a modification to the Control System in order to control df/dt ® Three wind turbine manufacturers have published information on systems to contribute towards system inertia (Enercon, Vestas and GE). ® Discussions are ongoing with other manufactures ® The Costs of installing such a requirement is believed to be negligible – certainly against the cost of installing additional fast acting frequency response (Volumes double) ® Hydro Quebec have introduced Inertial requirements in their Grid Code ® Analysis suggests that an inertial requirement would be applicable to all forms of generation where there is decoupling between the Generator and System

Additional Issues for Inertia ® Since the Control Systems would rely on a df/dt control, which is a noise amplifying process some consideration will need to be given to adequate filtering ® In order to reduce complexity and following discussions with manufacturers it is suggested that such a facility would only be applicable to plant in Limited Frequency Sensitive Mode of operation. ® The ability of Generators to recover following contribution to System Inertia needs to be examined in more detail. ® To minimise wear on the generator, it is suggested a dead band is introduced to the df/dt term. ® A static dead band value still requires evaluation but a value in the range of 0. 003 Hz/s is thought to be adequate based on the current experience – see attached slide

Deadband

High Level Proposals (1) ® In order to limit the rate of change of frequency following a generation loss or load loss, each Generating Unit, Power Park Module or DC Converter shall be required to contribute towards System Inertia. ® For Generating Units, DC Converters and Power Park Modules (including Power Park Units thereof) which do not inherently have a capability to provide inertia to the Transmission System, then each Generating Unit, DC Converter and Power Park Module shall be fitted with a Control System to contribute towards system inertia. ® Any such Control System should aim to control df/dt in order to reduce the rate of change of active power and hence rate of change of system frequency. Such a Control System would need to reflect and maximise the synthetic value of the Inertia Constant H.

High Level Proposals (2) ® In addition, the Inertial Control System fitted to each Generating Unit, Power Park Module and DC Converter shall: ® operate whenever the Generating Unit, DC Converter and Power Park Module (including the Power Park Unit thereof) is selected to Limited Frequency Sensitive Mode of operation. ® have an adjustable dead band of between 0. 001 Hz/s – 0. 01 Hz /s. The initial dead band shall be set to 0. 003 Hz/s ® Include elements to limit the bandwidth of the output signal. The bandwidth limiting must be consistent with the speed of response requirements and ensure that the highest frequency of response cannot excite torsional oscillations on other plant connected to the network. A bandwidth of 0 -5 Hz would be judged acceptable for this application. All other control systems employed within the Generating Unit, Power Park Module (including the Power Park Unit thereof) and DC Converter should also meet this requirement. ® For the avoidance of doubt there is no requirement for the Inertial Control System to be active when the Generating Unit, Power Park Module (including the Power Park Unit thereof) or DC Converter is operating in Frequency Sensitive Mode.

Conclusions ® Machine inertia significantly affects the rate of change of System Frequency ® In a System containing dynamic frequency response, a low system inertia will result in a lower minimum system frequency ® There needs to be co-ordination between requirements for inertia, delivery of primary response and delivery of secondary response – is 10% P, 10% S and 10% H still adequate especially in an 1800 MW scenario ® It would be significantly more expensive to allow system inertia to be eroded (as new Generation Technologies are introduced) and hold more fast acting response than mandating the need for a control system to contribute towards system inertia. ® The cost of fitting an inertial control is believed to be insignificant in comparison with holding additional response. ® Requirements for an inertial control need to reflect issues such as control system dynamics, dead band complexity ® Some additional study work is required in respect of exact control system performance. ® The Control System would only be required to be active when the Generator is operating in Limited Frequency Sensitive Mode of operation. ® National Grid has already started discussion with several turbine manufacturers to determine settings.

References / Further Information ® Contribution of Wind Energy Converters with Inertia Emulation to frequency control and frequency stability in Power Systems – Stephan Wachtel and Alfred Beekmann – Enercon – Presented at the 8 th International Workshop on Large Scale Integration of Wind Power into Power Systems as well as on Offshore Wind Farms, Bremen Germany, 14 – 15 October 2009. ® Variable Speed Wind Turbines Capability for Temporary Over-Production – German Claudio Tarnowski, Philip Carne Kjaer, Poul E Sorensen and Jacob Ostergaard ® Study on Variable Speed Wind Turbine Capability for Frequency Response - German Claudio Tarnowski, Philip Carne Kjaer, Poul E Sorensen and Jacob Ostergaard ® GE Energy – Wind. INERTIATM Control fact sheet – Available on GE Website at : - http: //www. geenergy. com/businesses/ge_wind_energy/en/downloads/GEA 17210. pdf ® Transmission Provider Technical Requirements for the Connection of Power Plants to the Hydro-Quebec Transmission System – February 2006 ® Amendment Report SQSS Review Request GSR 007 Review of Infeed Loss limits – Prepared by the SQSS Review Group for Submission to the Authority – 10 th September 2009 available at: - http: //www. nationalgrid. com/NR/rdonlyres/EF 5 C 0829 -1 C 5 E-4258 -8 F 73 -70 DC 62 C 43 F 49/36936/SQSS 1320 Reportv 10_final. pdf