Annex 2 - Proposed Grid Code Legal Text

Transcription

1 Annex 2 - Proposed Grid Code Legal Text FAULT RIDE THROUGH LEGAL TEXT This section contains the proposed legal text to give effect to the proposals. The proposed new text is in red and is based on Grid Code Issue X Revision XX. Section 1 Proposals for Grid Code Legal Text Changes Formatted: Normal, Centered Formatted: Font: +Body (Calibri), Bold Formatted: Normal Formatted: Font: +Body (Calibri) Key 1) Blue Text From G Code 2) Black Text Changes / Additional words 3) Orange/ Brown text From RfG 4) Highlighted Green text Questions for Stakeholders / Consultation 5) Highlighted yellow text Nomenclature / Table / Figure numbers to be finalised when more detail has been added XXX Definition Fault Ride Through DC Converter DC Converter Station DC Connected Power Park Module HVDC System Term The capability of Power Generating Modules and HVDC Systems to be able to be able to remain connected to the System and operate through periods of low voltage at the Grid Entry Point or User System Entry Point caused by secured faults Any User Apparatus used to convert alternating current electricity to direct current electricity, or vice versa. A DC Converter is a standalone operative configuration at a single site comprising one or more converter bridges, together with one or more converter transformers, converter control equipment, essential protective and switching devices and auxiliaries, if any, used for conversion. In a bipolar arrangement, a DC Converter represents the bipolar configuration. Updated - covered by Glossary and Definitions table An installation comprising one or more Onshore DC Converters connecting a direct current interconnector: to the NGET Transmission System; or, (if the installation has a rating of 50MW or more) to a User System of 110kV or above, and it shall form part of the External Interconnection to which it relates Updated - covered by Glossary and Definitions table A Power Park Module that is connected via one or more HVDC Interface Points to one or more HVDC Systems Updated - covered by Glossary and Definitions table An electrical power system which transfers energy in the form of high voltage direct current between two or more alternating current (AC) buses and comprises at least two HVDC converter stations with Transmission lines or cables between the HVDC Comment [NG1]: Suggest is revised in relation to Generators and HVDC Comment [NG2]: This requires further thought - the exisiting GB defintion has been used but with modifications and it is importnat to ensure that there are no unitended consequences as a result of these changes particulalry in respect of existing User's. Comment [NG3]: This requires further thought - the exisiting GB defintion has been used but with modifications and it is importnat to ensure that there are no unitended consequences as a result of these changes particulalry in respect of existing User's.

2 Converter Stations Updated - covered by Glossary and Definitions table Remote End DC In the case of an HVDC System, the Remote End DC Converter is Converter the end which is not connected to the GB Synchronous Area. Updated - covered by Glossary and Definitions table HVDC Interface Point A point at which HVDC equipment is connected to an AC network, at which technical specifications affecting the performance of the equipment can be prescribed. Updated - covered by Glossary and Definitions table HVDC Code European Commission Regulation (EU) 2016/1447 RfG Code European Commission Regulation (EU) 2016/631 Synchronous Area ed by synchronously interconnected TSO s such as the Synchronous Areas of Continental Europe, Great Britain, Ireland- Northern Ireland and Nordic and the Power System of Lithuania, Latvia and Estonia, together referred to as Baltic which are part of a wider synchronous area. Updated - covered by Glossary and Definitions table Onshore Synchronous Power Generating Module Type A Power Generating Module Type B Power Generating Module Type C Power Generating Module Type D Power Generating Module ECC.2 A Synchronous Power Generating Module located Onshore A Power-Generating Module with a Grid Entry Point or User System Entry Point below 110 kv and a Maximum Capacity of 0.8 kw or greater but less than 1MW; A Power-Generating Module with a Grid Entry Point or User System Entry Point below 110 kv and a Maximum Capacity of 1MW or greater but less than 10MW; A Power-Generating Module with a Grid Entry Point or User System Entry Point below 110 kv and a Maximum Capacity of 10MW or greater but less than 50MW; A Power-generating Module: with a Grid Entry Point or User System Entry Point at, or greater than, 110 kv; or with a Grid Entry Point or User System Entry Point below 110 kv and with Registered Capacity of 50MW or greater DEFINITIONS OF PHYSICAL QUANTITIES Comment [NG4]: These definitons require further review Formatted: Indent: First line: 0 cm Formatted: Indent: Left: 0 cm Formatted: Font: 11 pt, Not Bold Formatted: Font: 11 pt Formatted: Font: 11 pt, Not Bold Formatted: Normal, Indent: Left: 0.06 cm, Tab stops: Not at 3 cm Formatted: Font: 11 pt Formatted: Font: 11 pt Formatted: Indent: First line: 0 cm Formatted: Indent: First line: 0 cm Formatted: Indent: First line: 0 cm Formatted: Indent: Left: 0 cm, Hanging: 0.81 cm Formatted: Indent: Left: 0 cm, First line: 0 cm Formatted: Font: 11 pt Formatted: Indent: Left: 0 cm, Hanging: 0.81 cm Formatted: Arial 14, Indent: Left: 0.06 cm, Tab stops: Not at 3 cm

3 ECC.2.1 ECC ECC ECC ECC ECC ECC For the purposes of the Grid Code, physical quantities such as current or voltage are not defined terms as their meaning will vary depending upon the context of the obligation. For example, voltage could mean positive phase sequence root means square voltage, instantaneous voltage, phase to phase voltage, phase to earth voltage. The same issue equally applies to current, and it therefore felt that in view of these variations the terms current and voltage should remain undefined with the meaning depending upon the context of the application. The European Connection Codes define requirements of current and voltage but they have not been adopted as part of EU implementation. FAULT RIDE THROUGH General Fault Ride Through requirements, principles and concepts applicable to Type B, Type C and Type D Power Generating Modules and OTSDUW Plant and Apparatus subject to faults up to 140ms in duration. ECC section sets out the Fault Ride Through requirements on Type B, Type C and Type D Power Generating Modules, OTSDUW Plant and Apparatus and HVDC Equipment, DC Converters at a DC Converter Station, DC Connected Power Park Modules and Remote End DC Converters that shall apply in the event of a fault lasting up to 140ms in duration. Each Power Generating Module, Power Park Module, HVDC Equipment DC Converter at a DC Converter Station, DC Connected Power Park Module, Remote End DC Converter and OTSDUW Plant and Apparatus is required to remain connected and stable for any balanced and unbalanced fault where the voltage at the Grid Entry Point or User System Entry Point Connection Point or (HVDC Interface Point in the case of Remote End DC Converter Stations s or Interface Point in the case of OTSDUW Plant and Apparatus) remains on or above the heavy black line shown in sections ECC ECC Figures below. The voltage against time curves defined in ECC ECC expresses the lower limit (expressed as the ratio of its actual value and its reference 1pu) of the actual course of the phase to phase voltage (or phase to earth voltage in the case of asymmetrical/unbalanced faults) on the Systemnetwork voltage level at the Connection PointGrid Entry Point or User System Entry Point (or HVDC Interface Point in the case of Remote End HVDC Converter Stations or Interface Point in the case of OTSDUW Plant and Apparatus) during a symmetrical or asymmetrical/unbalanced fault, as a function of time before, during and after the fault. Voltage against time curve and parameters applicable to Type B Synchronous Power Generating Modules Formatted: Justified, Indent: Left: 0 cm, Hanging: 2.5 cm, Space After: 6 pt, Line spacing: Multiple 1.1 li, Tab stops: 2.5 cm, Left + Not at 3 cm Formatted: Font: +Body (Calibri), Bold, Underline, Font color: Black

4 Figure X - Voltage against time curve applicable to Type B Synchronous Power Generating Modules Voltage parameters (pu) Time parameters (seconds) Uret 0.3 tclear 0.14 Uclear 0.7 trec Urec1 0.7 trec Urec2 0.9 trec3 1.5 Table X Voltage against time parameters applicable to Type B Synchronous Power Generating Modules ECC Voltage against time curve and parameters applicable to Type C and D Synchronous Power Generating Modules connected below 110kV

5 Figure X - Voltage against time curve applicable to Type C and D Synchronous Power Generating Modules connected below 110kV Voltage parameters (pu) Time parameters (seconds) Uret 0.1 tclear 0.14 Uclear 0.7 trec Urec1 0.7 trec Urec2 0.9 trec3 1.5 Table X Voltage against time parameters applicable to Type C and D Synchronous Power Generating Modules connected below 110kV ECC Voltage against time curve and parameters applicable to Type D Synchronous Power Generating Modules connected at or above 110kV

6 ECC Figure X - Voltage against time curve applicable to Type D Synchronous Power Generating Modules connected at or above 110kV Voltage parameters (pu) Time parameters (seconds) Uret 0 tclear 0.14 Uclear 0.25 trec Urec1 0.5 trec Urec2 0.9 trec3 1.5 Table X Voltage against time parameters applicable to Type D Synchronous Power Generating Modules connected at or above 110kV Voltage against time curve and parameters applicable to Type B, C and D Power Park Modules connected below 110kV Figure X - Voltage against time curve applicable to Type B, C and D Power Park Modules connected below 110kV ECC Voltage parameters (pu) Time parameters (seconds) Uret 0.10 tclear 0.14 Uclear trec Urec trec Urec trec3 2.2 Table X Voltage against time parameters applicable to Type B, C and D Power Park Modules connected below 110kV Voltage against time curve and parameters applicable to Type D Power Park Modules with a Connection Point at or above 110kV, DC Connected Power Park Modules or OTSDUW Plant and Apparatus at the Interface Point.

7 CC For the avoidance of doubt, in the case of DC Connected Power Park Modules the voltage against time parameters specified below shall apply unless NGET has agreed to an alternative requirement which would be pursuant to the terms of the Bilateral Agreement. Any alternative agreed would still need to comply with the range of voltage against time parameters defined under RfG Code ((Regulation EU) 2016/631). Figure X - Voltage against time curve applicable to a Type D Power Park Modules with a Connection Point at or above 110kV, DC Connected Power Park Modules or OTSDUW Plant and Apparatus at the Interface Point. DC Converter at a DC Converter Station at the Connection Point or Remote End DC Converter at the HVDC Interface Point Formatted: Font: 11 pt Voltage parameters (pu) Time parameters (seconds) Uret 0 tclear 0.14 Uclear 0 trec Urec1 0 trec Urec trec3 2.2 Ublock Not defined Table X Voltage against time parameters applicable to a DC Converter at a DC Converter Station at the Connection Point or Remote End DC Converter at the HVDC Interface Point Type D Power Park Modules with a Connection Point at or above 110kV, DC Connected Power Park Modules or OTSDUW Plant and Apparatus at the Interface Point. Formatted: Font: 11 pt ECC Voltage against time curve and parameters applicable to HVDC Systems Converters at a DC Converter Station and Remote End HVDC Converter Stations

8 CC For the avoidance of doubt, in the case of Remote End HVDC Converter the voltage against time parameters specified below shall apply unless NGET has agreed to an alternative requirement which would be pursuant to the terms of the Bilateral Agreement. Any alternative agreed would still need to comply with the range of voltage against time parameters defined under the HVDC Code ((Regulation EU) 2016/1447). Figure X - Voltage against time curve applicable to HVDC Systems Converters at a DC Converter Station and Remote End HVDC Converter Stations. Voltage parameters (pu) Time parameters (seconds) Uret 0 tclear 0.14 Uclear 0 trec Urec1 0 trec Urec trec3 2.2 Table X Voltage against time parameters applicable to HVDC Systems Converters at a DC Converter Station and Remote End HVDC Converter Stations ECC In addition to the requirements in ECC ECC : (i) Each Type B, Type C and Type D Power Generating Module at the Grid Entry Point or User System Entry Point, HVDC EquipmentConverter at a DC Converter Station, DC Connected Power Park Module, Remote End DC Converter at an HVDC Interface Point (or OTSDUW Plant and Apparatus at the Interface Point) shall be capable of satisfying the above requirements when operating at Rated MW output and maximum leading Power Factor.

9 (ii) NGET will specify upon request by the User the pre-fault and post fault short circuit capacity (in MVA) at the Grid Entry Connection Point or User System Entry Point (or HVDC Interface Point in the case of a remote end HVDC Converter Stations or Interface Point in the case of OTSDUW Plant and Apparatus) in the Bilateral Agreement. (iii) The pre-fault voltage shall be taken to be 1.0pu and the post fault voltage shall not be less than be 0.9pu unless an a higher value is specified in the Bilateral Agreement. (iv) To allow a User to model the Fault Ride Through performance of its Type B, Type C and Type D Power Generating Modules or, HVDC EquipmentDC Converter at a DC Converter Station or Remote End HVDC Converter, NGET will provide additional network data as may reasonably be required byfor the User to undertake such study work in accordance with PC.A.8. Alternatively, NGET may provide generic values derived from typical cases. (v) NGET will publish fault level data under maximum and minimum demand conditions in the Electricity Ten Year Statement. (v) Each Generator (in respect of Type B, Type C, Type D Power Generating Modules and DC Connected Power Park Modules) and DC Converter Station Owners (in respect of HVDC Systems) shall satisfy the requirements in ECC (i) (iv) unless the protection schemes and settings for internal electrical faults trips requires disconnection of the Type B, Type C and Type D Power Generating Module, HVDC Equipment Converter at a DC Converter Station, Remote End DC Converter, DC Connected Power Park Module (or OTSDUW Plant and Apparatus) from the network. The protection schemes and settings should not jeopardise Fault Ride Through performance as specified in ECC (i) (iv). The undervoltage protection at the Grid Entry Point or User System Entry Connection Point (or HVDC Interface Point in the case of a Remote End HVDC Converter Stations or Interface Point in the case of OTSDUW Plant and Apparatus) shall be set by the Generator (or HVDC Converter Station Owner or OTSDUA in the case of OTSDUW Plant and Apparatus) according to the widest possible range unless NGET and the User have agreed to narrower settings detailed in the User s Bilateral Agreement. All protection settings associated with undervoltage protection shall be agreed between the Generator and/or HVDC System Owner with NGET and/or Relevant Transmission Licensee s and / or Relevant Network Operators (as applicable). Comment [NG5]: TBC that this can be done Comment [NG6]: It is assumed this includes Interconnectors Formatted: Font color: Auto

10 (vi) In addition to the requirements of ECC ECC Eeach Type B, Type C and Type D Power Generating Module, HVDC EquipmentConverter at a DC Converter Station, DC Connected Power Park Module, Remote End DC Converter at the HVDC Interface Point and OTSDUW Plant and Apparatus at the Interface Point shall be designed such that upon clearance of the fault on the Onshore Transmission System and within 0.5 seconds of restoration of the voltage at the Grid Entry Point or User System Entry Point or HVDC Interface Point in the case of a Remote End HVDC Converter Converter Stations or Interface Point in the case of OTSDUW Plant and Apparatus to 90% of nominal voltage or greater, Active Power output (or Active Power transfer capability in the case of OTSDW Plant and Apparatus or Remote End HVDC Converter Stationss) shall be restored to at least 90% of the level immediately before the fault. Once Active Power output (or Active Power transfer capability in the case of OTSDUW Plant and Apparatus or Remote End HVDC Converter Stationss) has been restored to the required level, Active Power oscillations shall be acceptable provided that: - The total Active Energy delivered during the period of the oscillations is at least that which would have been delivered if the Active Power was constant - The oscillations are adequately damped. For AC Connected Onshore and Offshore Power Park Modules Plant and Apparatus installed on or after 1 December 2017, comprising switched reactive compensation equipment (such as mechanically switched capacitors and reactors), such switched reactive compensation equipment shall be controlled such that it is not switched in or out of service during the fault but may act to assist in post fault voltage recovery. (vii) In the case of Synchronous Power Generating Modules, each Synchronous Power Generating Module shall inject maximum reactive current during the period of the fault without exceeding the transient rating of the Synchronous Power Generating Module. ECC ECC ECC ECC The requirements applicable to HVDC Converters, DC Connected Power Park Modules and Remote End HVDC Converters including OTSDUW DC Converters subject to faults and voltage disturbances at the Connection Point, Interface Point or HVDC Interface Point, including Active Power transfer capability shall be specified in the Bilateral Agreement. General Fault Ride Through requirements, principles and concepts applicable to Type C and Type D Power Generating Modules and OTDSUW Plant and Apparatus subject to for faults in excess of 140ms in duration. General Fault Ride Through requirements applicable to HVDC Equipment and OTSDUW DC Converters subject to faults and voltage dips in excess of 140ms. The requirements applicable to HVDC Equipment including OTSDUW DC Converters subject to faults and voltage disturbances at the Grid Entry Point or User System Entry Point or Interface Point or HVDC Interface Point, including Active Power transfer capability shall be specified in the Bilateral Agreement.

11 ECC This section (ECC ) sets out the Fault Ride Through requirements foron Type C and Type D Synchronous Power Generating Modules subject to faults and voltage disturbances on the Onshore Transmission System in excess of 140ms are defined in ECC (a) and the Fault Ride Through Requirements for, Power Park Modules and OTSDUW Plant and Apparatus subject to faults and voltage disturbances that shall apply in the event of Supergrid Voltage dips on the Onshore Transmission System greater than 140ms in duration are defined in ECC (b). (a) Requirements applicable to Synchronous Power Generating Units Modules subject to Supergrid Voltage dips on the Onshore Transmission System greater than 140ms in duration. In addition to the requirements of ECC ECC (a) each Synchronous Power Generating Module Unit, each with a Completion Date on or after 1 April 2005 shall: (i) remain transiently stable and connected to the System without tripping of any Synchronous Power Generating Module Unit for balanced Supergrid Voltage dips and associated durations on the Onshore Transmission System (which could be at the Interface Point) anywhere on or above the heavy black line shown in Figure X5a. Appendix X4A and Figures ECC.A.4A.3.2 (a), (b) and (c) provide an explanation and illustrations of Figure 5a; and, Figure 5a

12 (ii) provide Active Power output at the Grid Entry Point, during Supergrid Voltage dips on the Onshore Transmission System as described in Figure 5a, at least in proportion to the retained balanced voltage at the Onshore Grid Entry Point (for Onshore Synchronous Power Generating Modules Units) or Interface Point (for Offshore Synchronous Power Generating Modules Units) (or the retained balanced voltage at the User System Entry Point if Embedded) and shall generate maximum reactive current (where the voltage at the Grid Entry Point is outside the limits specified in ECC.6.1.4) without exceeding the transient rating limits of the Synchronous Power Generating Module Unit and, (iii) restore Active Power output following Supergrid Voltage dips on the Onshore Transmission System as described in Figure 5a, within 1 second of restoration of the voltage to 1.0pu of the nominal voltage at the: Comment [NG7]: Tony to add definition - completed, Not Highlight Onshore Grid Entry Point for directly connected Onshore Synchronous Power Generating Modules Units or, Interface Point for Offshore Synchronous Power Generating Modules Units or, User System Entry Point for Embedded Onshore Synchronous Power Generating Modules Units or User System Entry Point for Embedded Medium Power Stations not subject to a Bilateral Agreement which comprise Synchronous Generating Units and with an Onshore User System Entry Point (irrespective of whether they are located Onshore or Offshore) to at least 90% of the level available immediately before the occurrence of the dip. Once the Active Power output has been restored to the required level, Active Power oscillations shall be acceptable provided that: Comment [NG8]: This is contingent on the Large, Medium and Small debate. (b) - the total Active Energy delivered during the period of the oscillations is at least that which would have been delivered if the Active Power was constant - the oscillations are adequately damped. For the avoidance of doubt a balanced Onshore Transmission System Supergrid Voltage meets the requirements of ECC (b) and ECC Requirements applicable to Type C and Type D OTSDUW Plant and Apparatus and Power Park Modules and OTSDUW Plant and Apparatus subject to Supergrid Voltage dips on the Onshore Transmission System greater than 140ms in duration. In addition to the requirements of ECC (a) each OTSDUW Plant and Apparatus or each Power Park Module and / or any constituent Power Park Unit, each with a Completion Date on or after the 1 April 2005 shall: (i) remain transiently stable and connected to the System without tripping of any OTSDUW Plant and Apparatus, or Power Park Module and / or any constituent Power Park Unit, for balanced Supergrid Voltage dips and

13 associated durations on the Onshore Transmission System (which could be at the Interface Point) anywhere on or above the heavy black line shown in Figure 5b. Appendix 4A and Figures CC.A.4A.3.4 (a), (b) and (c) provide an explanation and illustrations of Figure 5b; and, Supergrid Voltage Level (% of Nominal) s 1.2s 2.5s 3 minutes Figure 5b Supergrid Voltage Duration (ii) provide Active Power output at the Grid Entry Point or in the case of an OTSDUW, Active Power transfer capability at the Transmission Interface Point, during Supergrid Voltage dips on the Onshore Transmission System as described in Figure 5b, at least in proportion to the retained balanced voltage at the Onshore Grid Entry Point (for Onshore Power Park Modules) or Interface Point (for OTSDUW Plant and Apparatus and Offshore Power Park Modules) (or the retained balanced voltage at the User System Entry Point if Embedded) except in the case of a Non-Synchronous Generating Unit or OTSDUW Plant and Apparatus or Power Park Module where there has been a reduction in the Intermittent Power Source or in the case of OTSDUW Active Power transfer capability in the time range in Figure 5b that restricts the Active Power output or in the case of an OTSDUW Active Power transfer capability below this level. and shall generate maximum reactive current (where the voltage at the Grid Entry Point, or in the case of an OTSDUW Plant and Apparatus, the Interface Point voltage, is outside the limits specified in ECC.6.1.4) without exceeding the transient rating limits of the OTSDUW Plant and Apparatus or Power Park Module and any constituent Power Park Unit; and, (iii) restore Active Power output (or, in the case of OTSDUW, Active Power transfer capability), following Supergrid Voltage dips on the Onshore Transmission System as described in Figure 5b, within 1 second of restoration of the voltage at the: Comment [NG9]: Implications on fast fault current injection for Power Park Moduks - needs to tie up with fast fault current injection requirements Comment [NG10]: FFCI will be picked up as part of ECC Onshore Grid Entry Point for directly connected Onshore Power Park

14 Modules or, Interface Point for OTSDUW Plant and Apparatus and Offshore Power Park Modules or, User System Entry Point for Embedded Onshore Power Park Modules or, User System Entry Point for Embedded Medium Power Stations which comprise Power Park Modules not subject to a Bilateral Agreement and with an Onshore User System Entry Point (irrespective of whether they are located Onshore or Offshore) to the minimum levels specified in ECC to at least 90% of the level available immediately before the occurrence of the dip except in the case of a Non-Synchronous Generating Unit, OTSDUW Plant and Apparatus or Power Park Module where there has been a reduction in the Intermittent Power Source in the time range in Figure 5b that restricts the Active Power output or, in the case of OTSDUW, Active Power transfer capability below this level. Once the Active Power output or, in the case of OTSDUW, Active Power transfer capability has been restored to the required level, Active Power oscillations shall be acceptable provided that: Formatted: Not Strikethrough, Not Highlight Comment [NG11]: This issue is contigent on the Large, Medium Small debate - the total Active Energy delivered during the period of the oscillations is at least that which would have been delivered if the Active Power was constant - the oscillations are adequately damped. For the avoidance of doubt a balanced Onshore Transmission System Supergrid Voltage meets the requirements of ECC (b) and ECC ECC Other Fault Ride Through Requirements (i) In the case of a Power Park Module including a DC Connected Power Park Module (comprising of wind-turbine generator units), the requirements in ECC X and CC do not apply when the Power Park Module (including a DC Connected Power Park Module) is operating at less than 5% of its Rated MW or during very high primary energy source conditions wind speed conditions when more than 50% of the wind turbine generator Power Park Units in a Power Park Module have been shut down or disconnected under an emergency shutdown sequence to protect User s Plant and Apparatus. (ii) In addition to meeting the conditions specified in ECC.6.1.5(b) and ECC.6.1.6, each Non-Synchronous Generating Unit, OTSDUW Plant and Apparatus or Power Park Module or DC Connected Power Park Module with a Completion Date after 1 April 2005 and any constituent Power Park Unit thereof will be required to withstand, without tripping, the negative phase sequence loading incurred by clearance of a close-up phase-to-phase fault, by System Back-Up Protection on the Onshore Transmission System operating at Supergrid Voltage.

15 (iii) In the case of an Onshore Power Park Module in Scotland with a Completion Date before 1 January 2004 and a Registered Capacity less than 30MW the requirements in CC (a) do not apply. In the case of an Onshore Power Park Module in Scotland with a Completion Date on or after 1 January 2004 and before 1 July 2005 and a Registered Capacity less than 30MW the requirements in CC (a) are relaxed from the minimum Onshore Transmission System Supergrid Voltage of zero to a minimum Onshore Transmission System Supergrid Voltage of 15% of nominal. In the case of an Onshore Power Park Module in Scotland with a Completion Date before 1 January 2004 and a Registered Capacity of 30MW and above the requirements in CC (a) are relaxed from the minimum Onshore Transmission System Supergrid Voltage of zero to a minimum Onshore Transmission System Supergrid Voltage of 15% of nominal. (iiiv) To avoid unwanted island operation, Non-Synchronous Generating Units in Scotland (and those directly connected to a Scottish Offshore Transmission System), Power Park Modules in Scotland (and those directly connected to a Scottish Offshore Transmission System), or OTSDUW Plant and Apparatus with an Interface Point in Scotland shall be tripped for the following conditions: (1) Frequency above 52Hz for more than 2 seconds (2) Frequency below 47Hz for more than 2 seconds (3) Voltage as measured at the Onshore Connection Point or Onshore User System Entry Point or Offshore Grid Entry Point or Interface Point in the case of OTSDUW Plant and Apparatus is below 80% for more than 2.5 seconds (4) Voltage as measured at the Onshore Connection Point or Onshore User System Entry Point or Offshore Grid Entry Point or Interface Point in the case of OTSDUW Plant and Apparatus is above 120% (115% for 275kV) for more than 1 second. The times in sections (1) and (2) are maximum trip times. Shorter times may be used to protect the Non-Synchronous Generating Units, or OTSDUW Plant and Apparatus or Power Park Modules. (iv) For the avoidance of doubt the requirements specified in ECC do not apply to Power Generating Modules connected to an unhealthy circuit and islanded from the Transmission System even for delayed auto reclosure times. Comment [NG12]: We need to check this with our Scottish and DNO colleagues to see if it is relevant. The proposal would be to remove it to avoid any form or regional difference

16 ECC.4 - APPENDIX 4 - FAULT RIDE THROUGH REQUIREMENTS FAULT RIDE THROUGH REQUIREMENTS FOR TYPE B, TYPE C AND TYPE D SYNCHRONOUS POWER GENERATING MODULES, ONSHORE POWER PARK MODULES, OFFSHORE POWER PARK MODULES (INCLUDING OFFSHORE POWER PARK MODULES WHICH ARE EITHER AC CONNECTED POWER PARK MODULES OR DC CONNECTED POWER PARK MODULES), HVDC SYSTEMS CONVERTERS AT A DC CONVERTER STATION, REMOTE END HVDC CONVERTERS AND OTSDUW PLANT AND APPARATUS ECC.A.4A.1 Scope The Fault Ride Through requirements are defined in ECC ECC (a), (b) and CC This Appendix provides illustrations by way of examples only of ECC ECC and further background and illustrations to ECC ECC and CC (2b) (i) and is not intended to show all possible permutations. ECC.A.4A.2 Short Circuit Faults At Supergrid Voltage On The Onshore Transmission System Up To 140ms In Duration For short circuit faults at Supergrid Voltage on the Onshore Transmission System (which could be at an Interface Point) up to 140ms in duration, the Fault Ride Through requirement is defined in ECC In summary any Power Generating Module (including a DC Connected Power Park Module) or, HVDC System Converter at a DC Converter Station or Remote End DC Converter is required to remain connected and stable whilst connected to a healthy circuit. Figure ECC.A.4.A.2 illustrates this principle.

17 Figure ECC.A.4.A.2 In Figure ECC.A.4.A.2 a solid three phase short circuit fault is applied adjacent to substation A resulting in zero voltage at the point of fault. All circuit breakers on the faulty circuit (Lines ABC) will open within 140ms. The effect of this fault, due to the low impedance of the network, will be the observation of a low voltage at each substation node until the fault has been cleared. Under this example, Generator X in Figure ECC.A.4.A.2, will trip as it is disconnected and isolated from the Transmission System by the opening of circuit breakers on circuit ABC. clearance of the fault. Generator Y and Generator Z (an Embedded Generator) would need to remain connected and stable as both are still connected to the Total System and remain connected to healthy circuits. The criteria for assessment is based on a voltage against time curve at each GridConnection Entry Point or User System Entry Point. The voltage against time curve at the Grid EntryConnection Point or User System Entry Point varies for each different type and size of Power Generating Module as detailed in ECC X ECC Y. The voltage against time curve represents the voltage profile at a Grid Entry Point or User System Entry Connection Point that would be obtained by plotting the voltage at that Grid Entry Point or User System Entry Connection Point before during and after the fault. This is not to be confused with a voltage duration curve (as defined under ECC X) which represents a voltage level and associated time duration. The post fault voltage at a Grid Entry Point or User System EntryConnection Point is largely influenced by the topology of the network rather than the behaviour of the Power Generating Module itself. The GeneratorPower Generating Facility Owner therefore needs to ensure each Power Generating Module remains connected and stable for a close up solid three phase short circuit fault for 140ms at the Grid Entry Point or User System Entry PointConnection Point. Two examples are shown in Figure ECC.A.4.A.2.X and ECC.A.4.A.2.Y. In Figure ECC.A.4.A.2.X, the post fault profile is above the heavy black line. In this case the Power Generating Module must remain connected and stable. In Figure ECC.A.4.A.2.Y the post fault voltage dips below the heavy black line in which case the Power Generating Module is permitted to trip.

18 Figure ECC.A.4.A.2.X Figure ECC.A.4.A.2.Y The process for demonstrating Fault Ride Through compliance against the requirements of ECC are detailed in ECP.A.3.5. ECC.A.4A.3 ECC.A.4A3.1 Supergrid Voltage Dips On The Onshore Transmission System Greater Than 140ms In Duration Requirements applicable to Synchronous Power Generating Modules Generating Units subject to Supergrid Voltage dips on the Onshore Transmission System greater than 140ms in duration. For balanced Supergrid Voltage dips on the Onshore Transmission System having durations greater than 140ms and up to 3 minutes, the Fault Ride Through requirement is defined in ECC (1b) and Figure 5a which is reproduced in this Appendix as Figure ECC.A.4A3.1 and termed the voltage duration profile.

19 This profile is not a voltage-time response curve that would be obtained by plotting the transient voltage response at a point on the Onshore Transmission System (or User System if located Onshore) to a disturbance. Rather, each point on the profile (ie the heavy black line) represents a voltage level and an associated time duration which connected Synchronous Power Generating Modules Units must withstand or ride through. Figures ECC.A.4A3.2 (a), (b) and (c) illustrate the meaning of the voltage-duration profile for voltage dips having durations greater than 140ms. Figure ECC.A.4A3.1

20 Figure ECC.A.4A3.2 (a) Figure ECC.A.4A3.2 (b)

21 Figure ECC.A.4A3.2 (c) ECC.A.4A3.2 Requirements applicable to Power Park Modules or OTSDUW Plant and Apparatus subject to Supergrid Voltage dips on the Onshore Transmission System greater than 140ms in duration For balanced Supergrid Voltage dips on the Onshore Transmission System (which could be at an Interface Point) having durations greater than 140ms and up to 3 minutes the Fault Ride Through requirement is defined in ECC (2b) and Figure 5b which is reproduced in this Appendix as Figure ECC.A.4A3.3 and termed the voltage duration profile. This profile is not a voltage-time response curve that would be obtained by plotting the transient voltage response at a point on the Onshore Transmission System (or User System if located Onshore) to a disturbance. Rather, each point on the profile (ie the heavy black line) represents a voltage level and an associated time duration which connected Power Park Modules or OTSDUW Plant and Apparatus must withstand or ride through. Figures ECC.A.4A.4 (a), (b) and (c) illustrate the meaning of the voltage-duration profile for voltage dips having durations greater than 140ms.

22 Figure ECC.A.4A3.3 Figure ECC.A.4A3.4 (a)

23 Figure ECC.A.4A3.4 (b) Figure ECC.A.4A3.4 (c)

24 DRAFT SCOPE AND BANDING LEGAL TEXT Key 1) Blue Text From Grid Code 2) Black Text Changes / Additional words 3) Orange/ Brown text From RfG 4) Highlighted Green text Questions for Stakeholders / Consultation 5) Highlighted yellow text Nomenclature / Table / Figure numbers to be finalised when more detail has been added Do we need a definitions section? DRAFT SCOPE AND BANDING LEGAL TEXT ECC.3.6 Subject to ECC3.8, the requirements set out in these European Connection Conditions shall not apply to Existing Users who should refer to the [Connection Conditions]. ECC.3.7 Existing Users are defined as: ECC Power-Generating Facilities (a) Generators whose Power-Generating Module(s) was already connected to the National Electricity Transmission System or Network Operator s System before 17 th May 2016; or (b) Generators who had concluded a final and binding contract for the purchase of Main Generating Plant before 17 th May The Generator must notify the Relevant System Operator and NGET (where it is not the Relevant System Operator) of the conclusion of this final and binding contract by 17 th November 2018; or Comment [NG1]: What about DCC/HVDC? (c) Generators who have been granted a relevant derogation by the Authority. ECC Demand Units or a User System: (a) [Insert Demand equivalent of Generator ] was not already connected to the National Electricity Transmission System or Network Operator s System on 7 th September 2016; or (b) [Insert Demand equivalent of Generator ] had not concluded a final and binding contract for the purchase of Plant and Apparatus by 7 th September The [Insert Demand equivalent of Generator ] must notify the Relevant System Operator and NGET (where it is not the Relevant System Operator) of conclusion of the contract by 7 th May 2019; or (c) [Insert Demand equivalent of Generator ] is not covered by a derogation granted by the Authority. ECC HVDC Systems or DC-connected Power Park Modules

25 (a) [Insert HVDC equivalent of Generator ] whose HVDC System(s), or DC-connected Power Park Module Owners whose DC-Connected Power Park Module(s), was already connected to the National Electricity Transmission System or Network Operator s System before 28 th September 2016; or (b) [Insert HVDC equivalent of Generator ] whose HVDC System(s), or DC-connected Power Park Module Owners whose DC-Connected Power Park Module(s), had not concluded a final and binding contract for the purchase of Plant and Apparatus by 28 th September The HVDC System Owner must notify the Relevant System Operator and NGET (where it is not the Relevant System Operator) of conclusion of the contract by 28 th May 2019; or (c) [Insert HVDC equivalent of Generator ] who have been granted a relevant derogation by the Authority. ECC.3.8 The requirements set out in these European Connection Conditions shall apply to the following Existing Users: ECC Generators owning a Type C or Type D Power-Generating Module which has been modified to such an extent that its Bilateral Agreement must be substantially revised or replaced, as determined by the Authority. ECC [Insert Demand equivalent of Generator ] owning a Demand Unit or a User System which has been modified to such an extent that its Bilateral Agreement must be substantially revised or replaced, as determined by the Authority. Comment [NG2]: Not sure how we capture DNO Connections which have a Connection Agreement rather than a Bilateral Agreement. This is one for our DNO colleagues but probbaly not an issue as anythink that is DNO connected will have its own connection agreement with the DNO anyway and we have no involvement unless they are party to the BM ECC [Insert HVDC equivalent of Generator ] owning an HVDC System or a DC-Connected Power Park Module which has been modified to such an extent that its Bilateral Agreement must be substantially revised or replaced, as determined by the Authority. Type (A-D) MW banding levels for GB, as required in RfG [Location and numbering TBC] Type A Type B which is a Power-Generating Module with a Grid Entry Point or User System Entry Point Connection Point below 110 kv and a MaximumRegistered Capacity of 0.8 kw or greater but less than 1MW; which is a Power-Generating Module with a Grid Entry Point or User System Entry PointConnection Point below 110 kv and MaximumRegistered Capacity of 1MW or greater but less than 10MW;

26 Type C Type D which is a Power-Generating Module with a Grid Entry Point or User System EntryConnection Point below 110 kv and a MaximumRegistered Capacity of 10MW or greater but less than 50MW; which is a Power-generating Module: with a Grid Entry Point or User System Entry PointConnection Point at, or greater than, 110 kv; or with a Grid Entry Point or User System Entry Point Connection Point below 110 kv and with MaximumRegistered Capacity of 50MW or greater Comment [NG3]: Now added as definitions - see main Glossary and Definitions Table

27 PROPOSED FAST FAULT CURRENT INJECTION LEGAL DRAFTING Key 1) Blue Text From Grid Code 2) Black Text Changes / Additional words 3) Orange/ Brown text From RfG 4) Highlighted Green text Questions for Stakeholders / Consultation 5) Highlighted yellow text Nomenclature / Table / Figure numbers to be finalised when more detail has been added 6) bm recommendations DRAFT FAST FAULT CURRENT INJECTION LEGAL TEXT OPTION 1 NOTE;- AS PART OF THE STAKEHOLDER DISCUSSIONS THREE OPTIONS FOR FAST FAULT CURRENT INJECTION HAVE BEEN DISCUSSED. IT IS ANTICPATED THAT ONLY ONE OF THESE OPTIONS WILL ONLY EVENTUALLY BE INCOPORATED INTO THE FINAL GRID CODE AS APPROVED BY THE AUTHORITY. THE TEXT BELOW COVERS OPTION 1 ALONE, OPTION 2 AND 3 ARE COVERED IN SEPARATE DOCUMENTS. IT SHOULD BE NOTED THAT FAST FAULT CURRENT INJECTION POSES SIGNIFICANT CHALLENGES BOTH FOR DEVELOPERS AND NETWORK OPERATORS IN THE FUTURE. THE CURRENT PURPOSE OF THIS WORK IS TO IMPLEMENT RFG. BASED ON THE ANALYSIS NATIONAL GRID S PREFERRED OPTION IS TO ADOPT AN APPROACH OUTLINED IN OPTION 1, HOWEVER IT IS RECONGINSED THAT THIS IS NOT WITHOUT ITS CHALLENGES AND OPTION 2 AND OPTION 3 ARE ALSO VALID ALTERNTIVES. IF AS A RESULT OF THIS CONSULTATION, THE GENERAL CONCENSUS IS TO ADOPT EITHER OPTION 2 OR OPTION 3, NATIONAL GRID WOULD RECOMMEND THAT AN EXPERT / STAKEHOLDER FFCI WORKGROUP IS ESTABLISHED IN THE IMMEDIATE SHORT TERM TO INVESTIGATE TECHNCIAL SOLUTIONS AND MARKET BASED SOLUTIONS FOR THE LONGER TERM INTEGRITY OF THE SYSTEM IN THE 2020 S. GLOSSARY AND DEFINITIONS A complete review of the Glossary and Definitions will be required when the full suite of European Codes has been implemented. The current assumption is to use GB definitions where appropriate with use of European definitions where required. The current European definitions used in the text are summarised below but it should be stressed that this is very much work in progress and further revisions will be required in the future. Term Fast Fault Current Definition A current delivered by a Power Park Module or HVDC System during and after a voltage deviation caused by an electrical fault within the System with the aim of identifying a fault by network Protection systems at the initial stage of the fault, supporting System voltage retention at a later stage of the Formatted: Font color: Auto

28 Operating Angle Reactive Current Contract Date fault and System voltage restoration after fault clearance. The angle of the voltage source of a Power Park Module, HVDC Equipment (whose converter control system meets the requirements of ECC ) with respect to the System The current provided in the steady state condition which is 90 degrees out of phase with the active power The date at which a User has concluded a final and binding contract for its main Plant and Apparatus Formatted: Font color: Auto Formatted: Font color: Auto Comment [NG1]: Need to tidy up this to ensure consistency, Font color: Auto ECC.2 ECC.2.1 DEFINITIONS OF PHYSICAL QUANTITIES For the purposes of the Grid Code, physical quantities such as current or voltage are not defined terms as their meaning will vary depending upon the context of the obligation. For example, voltage could mean positive phase sequence root means square voltage, instantaneous voltage, phase to phase voltage, phase to earth voltage. The same issue equally applies to current, and it therefore felt that in view of these variations the terms current and voltage should remain undefined with the meaning depending upon the context of the application. The European Connection Codes define requirements of current and voltage but they have not been adopted as part of EU implementation., Font color: Auto Formatted: Font color: Auto, Font color: Auto Formatted: Font color: Auto CONNECTION CONDITIONS Formatted: Indent: Left: 0 cm, First line: 0 cm ECC FAST FAULT CURRENT INJECTION ECC General Fast Fault Current injection, principles and concepts applicable to Type B, Type C and Type D Power Park Modules and HVDC EquipmentDC Converters at a DC Converter Station, DC Connected Power Park Modules and Remote End DC Converters ECC (i) (ii) This section sets out the Fast Fault Current injection requirements for Type B, Type C and Type D Power Park Modules, DC Converters at a DC Converter Station, DC Connected Power Park Modules and Remote End DC Converters. Generators and DC Converter Station Owners who own Type B, Type C and Type D Power Park Modules, DC Converters at a DC Converter Station shall have the option of meeting either the requirements of ECC or ECC Formatted: Indent: Left: 0 cm, Hanging: 3 cm, No bullets or numbering

29 ECC ECC Generators or DC Converter Station Owners should notify NGET which option they wish to select within 28 days of signing a Connection Agreement or such longer period as NGET may agree, in any event this being no later than 3 months before the Completion Date of the offer for a final CUSC Contract. For the avoidance of doubt, the requirements defined under ECC shall only be available to Generators and DC Converter Station Owners which have a Completion Date before 1 January In the case of a DC Connected Power Park Module or Remote End HVDC Converter, the requirements of ECC or ECC shall apply unless NGET has agreed to an alternative requirement which would be pursuant to the terms of the Bilateral Agreement. Any alternative agreed would still need to comply with the requirements defined under the HVDC Code ((Regulation EU) 2016/1447). ECC Fast Fault Current injection - Option 1 ECC (ii) For Generators or DC Converter Station Owners selecting to satisfy the Fast Fault Current Injection requirements Option 1 Eeach Type B, Type C and Type D Power Park Module, DC Converter at a DC Converter Station shall be required to satisfy the following requirements which apply to both balanced and unbalanced faults:- (i) Each Type B, Type C and Type D Power Park Module and HVDC EquipmentDC Converter at a DC Converter Station shall across the frequency range defined in CC behave as a voltage source behind a reactance over the 5Hz to 1kHz frequency band before, during and after the fault. A reactance of 10% of machine rating would be considered appropriate for this application unless NGET has agreed to an alternative valueotherwise specified in the Bilateral Agreement; and The phase voltages of the voltage source (as described in ECC (i)) may be changed in order to limit the amount of current delivered in any phase to no less than 1.5pu; (iii) The phase angle and frequency of the voltage source (as described in ECC (i)) shall remain unchanged during the period of the fault. For the avoidance of doubt the phase angle of the current delivered into the System from each Power Park Module or HVDC EquipmentConverter will be a function of the System load during the fault. (iv) Upon clearance of the fault or disturbance, the phase voltages of the voltage source (as described in ECC (i)) shall maintain current up to a maximum of 1.5p.u current until restoration of the voltage to the minimum levels specified in ECC For the avoidance of doubt, the post fault current and Active Power recovery will be determined by the System impedance following fault clearance. Formatted: Indent: Left: 0 cm, Hanging: 3 cm Comment [NG2]: Need to check with Legal that there is no need to refer to DC Connected Power Park Modules or Remote End DC Converters by reference to ECC Comment [NG3]: Tie into paragraph 1 ECC

30 (v) For directly connected Type B, Type C and Type D Power Park Modules and DC Converters at a DC Converter Station HVDC Equipment the measurement of the voltage deviation at each Grid Entry Point shall be in accordance with the requirements defined under ECC.6.1.5(b); and (vi) The reactive current delivered from each Type B, Type C and Type D Power Park Module or HVDC Equipment DC Converter at a DC Converter Station shall respond instantaneously and in proportion to the change in System voltage at the Grid Entry Point Connection Point or User System Entry Point. These requirements apply over the full voltage against time periods specified in ECC ; and (vii) In addition to the requirements of ECC X.X (Fault Ride Through) Generators in respect of Type B, Type C and Type D Power Park Modules or DC Connected Power Park Modules and HVDC System Owners in respect of HVDC SystemsConverter at a DC Converter Station are required to confirm to NGET, their repeated ability to supply Fast Fault Current to the System each time the voltage at the Grid Entry Connection Point or User System Entry Point falls outside the limits specified in ECC and ECC Generators and DC SystemConverter Station Owners are required to inform and obtain the agreement of NGET prior to the Completion Date regarding the maximum number of repeated operations that can be performed under such conditions and any limiting factors to repeated operation such as protection or thermal rating; and (viii) In the event that the Power Park Module, DC Connected Power Park Module or HVDC SystemConverter at a DC Converter Station fails to limit the current as detailed in ECC (i), it is permissible to restrict the maximum current to no less than 1.5pu as agreed with NGET by other means. The User shall provide details of the and agree the details to NGET of the mechanism for this current limiting condition including any necessary control block diagrams as required in PC.A.5.4.2(b) and PC.A of the Planning Code. For the avoidance of doubt, each Power Park Module and HVDC Equipment will also need to comply with the full fault ride through requirements detailed in ECC including the requirements for Active Power recovery. (ix) Generators and HVDC Converter Station Owners should have the capability to limit the fault infeed based on their current continuous MW output. There should be three parameter settings associated with this feature which shall be notified to NGET specified in the Bilateral Agreement. These shall be the maximum current infeed in pu on MVA rating adjustable between 1.05pu and 1.5pu with a default value of 1.5pu, minimum current infeed adjustable between 0.5pu with a default value of 1.5pu and the pu Active Power below which the fault current ramps down frorm the high level to the low level specified by the other parameters. This will be adjustable between 0 to 1pu Active Power and it will default to zero pu shown in Figure X1. Comment [NG4]: AJ to tidy up - text updated and amended, Highlight

31 Figure X1 ECC In addition to the requirements of ECC each Type B, Type C and Type D Power Park Module or HVDC Equipment Converter at a DC Converter Station shall also be required to satisfy the following requirements:- (i) Following the clearance of the disturbance, reactive current delivery from each Power Park Module or HVDC Equipment DC Converter at a DC Converter Station shall not increase voltages to levels beyond those specified within ECC and CC6.1.7 and shall ensure that the Power Park Module or HVDC Equipment DC Converter at a DC Converter Station is designed such that there is no risk of transient over voltages arising from clearance of the fault; and (ii) In addition to the requirements of ECC (reactive capability) each Type B, Type C and Type D Power Park Module or HVDC Converter at a DC Converter Station Equipment is required to meet the reactive capability requirements shown in Figure X2.

32 Formatted: Centered, Indent: Left: 0 cm, Hanging: 2.5 cm, No bullets or numbering Formatted: Centered, No bullets or numbering Formatted: Level 1 Text, Numbered + Level: 1 + Numbering Style: i, ii, iii, + Start at: 1 + Alignment: Left + Aligned at: 2.51 cm + Indent at: 3.78 cm, Adjust space between Latin and Asian text, Adjust space between Asian text and numbers, Tab stops: 3.75 cm, Left Formatted: Font: 11 pt, Bold, Font color: Auto, English (U.K.) Formatted: Font: 11 pt, Bold, Font color: Auto, English (U.K.) Formatted: Font: 11 pt, Bold, Font color: Auto, English (U.K.) (iii) (iv) Figure X2 Formatted: Font: 11 pt, Bold, Font color: Auto, English (U.K.) Formatted: Font: 11 pt, Font color: Auto, English (U.K.) (iii) The short term Active Power overload capability defined in Figure X2 shall be limited to the lesser of a maximum value of 1.33pu of the Rated Active Power of each Power Park Module or HVDC Equipment DC Converter at a DC Converter Station or 0.33pu increase in Active Power from the current operating point. It shall be required to be sustained for a period of no greater than 20 seconds, with the exact requirements being pursuant to the terms of the Bilateral Agreement. Comment [NG5]: This requires further work. As part of our studies we know we can adequatley manage with (iv) (v) For the voltage source defined in ECC rapid changes to the phase voltage (V), frequency (F) and phase angle in the greater than 5Hz band are not permitted whilst the operating point remains within the extended capability zone specified in Figure X2. The voltage source specified in ECC will maintain a balanced three phase sinusoidal voltage up to 1kHz provided the quality of supply limits remain within the limits of ECC6.1.5, ECC6.1.6 and ECC (Quality of Supply Requirements) provided that each Power Park Module or HVDC Equipment is operating within its normal operating range specified in ECCC6.3.2 (Reactive Capability Requirements). If the levels stated are exceeded, they may be reduced by adjusting the wave shape or phase voltages. The speed at which this occurs shall be limited such that they are bandwidth limited to less than 5Hz unless otherwise agreed with NGET and specified in the Bilateral Agreement. Formatted: Font: Italic, Highlight Formatted: Font: 11 pt Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt Formatted: Font: 11 pt Formatted: Font: Italic, Highlight Formatted: Font: 11 pt

33 (vi) When operating within the extended range and operating at 1.05pu or above of rated current, the requirements of ECC.6.1.5, ECC and ECC may be relaxed such that each Power Park Module or HVDC Equipment DC Converter at a DC Converter Station injects balanced three phase current and that the sinusoidal voltage source specified in ECC operates over a reduced bandwith of between 5Hz to 75Hz. Normal operation shall be resumed once the current falls below 1.05pu. (i) The overall control system (including damping performance) of each Type B, Type C and Type D Power Park Module or HVDC Equipment DC Converter at a DC Converter Station shall be designed in accordance with the requirements of ECC.6.3.X.X(Control System Design as taken from Grid Code Appendix 6) (ii) An illustration and examples of the performance requirements expected are illustrated in Appendix 4EC1 Formatted: Font: 11 pt Formatted: Font: 11 pt Formatted: Font: 11 pt Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt Formatted: Font: 11 pt Formatted: Font: 11 pt Formatted: Font: 11 pt Formatted: Font: 11 pt

34 ECC.A.X.X ECC.A ECC.A DRAFT FAST FAULT CURRENT INJECTION LEGAL TEXT ADDITIONAL APPENDIX TO THE CONNECTION CONDITIONS FAST FAULT CURRENT INJECTION - OPTION 1 CONTROL SYSTEM REQUIREMENTS Scope This Appendix sets out the functional performance and control system performance requirements for Type B, Type C and Type D Power Park Modules and, HVDC Equipment Converters at a DC Converter Station, DC Connected Power Park Modules and Remote End DC Converters which are required to satisfy option 1 of the Fast Fault Current injection requirements specified under ECC This Appendix does not limit any site specific requirements that may be required included in a Bilateral Agreement where which in NGET's reasonable opinion these facilities are necessary for system reasons. Should a Generator or DC Converter Station Owner anticipate making a change to the Fast Fault Current control system it shall notify NGET under the Planning Code (PC.A.1.2(b) and (c)) as soon as the Generator or HVDC SystemConverter Station Owner anticipates making the change. The change may require a revision to the Bilateral Agreement. (Just need to make sure this works legally). Formatted: Indent: Left: 0 cm, First line: 0 cm Formatted: Justified, Indent: Left: 0 cm, Hanging: 2.5 cm Formatted: Font: +Body (Calibri), 11 pt, Not Bold ECC.A.1.2 ECC.A ECC.A ECC.A ECC.A Functional Performance Each Type B, Type C and Type D Power Park Module and HVDC Equipment, DC Converters at a DC Converter Station, DC Connected Power Park Modules and Remote End DC Converters should behave like a balanced 3ph voltage source behind a reactance over the 5Hz to 1kHz band over the normal voltage and frequency range as specified in ECC and ECC ;-and Provide an equivalent synchronous rotor model where the rate of change of the rotor voltage / Electro motive force(emf) and change in angle and frequency are limited to less than 5Hz when operating within the extended operating region specified within ECC In order to limit the effects of the change in System phase during the voltage disturbance, the control system of each Power Park Module or, HVDC Equipment Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter shall be required to contribute to System inertia. An equivalent inertia constant of between 2 7 MWs/MVA would be required with the exact inertia constant shall be agreed between the User and NGET in accordance with the requirements of the Bilateral Agreement. During fault conditions or voltage depressions dynamic breaking will be applied to the rotor model specified in ECC For example for Grid Entry Point or User System Entry Point voltage levels of less than 0.85pu for up to 500ms, the equivalent inertia could temporality become infinite. Manufacturers may specify and agree alternative arrangements in the Bilateral Agreement subject to review and agreement of NGET. Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt Comment [NG6]: This requires a... Formatted: Indent: Left: 2.54 cm Formatted: Font: 11 pt Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt Formatted: Font: 11 pt, Not Bold

35 ECC.A ECC.A ECC.A.1.3 ECC.A ECC.A.1.4 ECC.A ECC.A.1.5 ECC.A ECC.A ECC.A ECC.A.1.6 The Power Park Module or HVDC Equipment, DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter will be capable of transiently providing up to 33% additional real power and down to 0% real power in response to changes in frequency or Operating Angle in line equivalent inertia set in ECC.A It must be capable of sustaining this duration for events from 52Hz to 47Hz and 47Hz to 52Hz. Any energy storage components with limited capability intended for the purpose of real power delivery as described in ECC must only be used for this purpose ensuring this feature is continuously available and not for wider commercial gain. Requirements The control system of each Power Park Module or HVC Equipment DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter shall include a voltage source which shall meet the following functional specification.. Steady State Control Each Power Park Module or, DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter is required to satisfy the voltage control requirements at the Grid Entry Point or User SystemConnection Entry Point as detailed in ECC (PPM Power Park Module voltage control requirements) Transient Control The voltage/reactive power regulator of each Power Park Module or, HVDC EquipmentConverter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter is required to satisfy the requirements of ECC.A.7 (Power Park Module voltage control requirements). In addition to the requirements of ECC.A when each Power Park Module or, HVDC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC ConverterEquipment is subjected to a large voltage disturbance, the voltage/reactive power regulator of each Power Park Module or, HVDC Equipment Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter shall have an equivalent field time constant which shall be specified in the Bilateral Agreement. This will normally be not less than 50 ms and not greater than 300 ms. Upon clearance of a fault or disturbance, each Power Park Module, or HVDC Equipment DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter shall have a damped or damped oscillatory characteristic. These requirements are described in ECC.A.1.6 below. Power Oscillations Damping Control Formatted: Indent: Left: 1.27 cm, First line: 1.27 cm Formatted: Font: 11 pt Formatted: Justified, Indent: Left: 0 cm, Hanging: 2.5 cm Formatted: Indent: Left: 1.27 cm, First line: 1.27 cm Formatted: Justified, Indent: Left: 0 cm, Hanging: 2.5 cm Formatted: Font: 10 pt Formatted: Font: 11 pt, English (U.K.), Highlight Formatted: Level 1 Text Comment [NG7]: We need to specify the Bilateral Agreement here as this follows current practice

36 ECC.A ECC.A ECC.A ECC.A ECC.A ECC.A ECC.A To allow each Power Park Module and HVDC Equipment, DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter to maintain second and subsequent equivalent rotor model swing stability (which is the equivalent rotor model of the converter) and also to ensure an adequate level of low frequency electrical damping power, the control system of each Power Park Module or, HVDC Equipment DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter shall include a power oscillation damping facility as a means of supplementary control. Whatever supplementary control signal is employed, it shall be of the type which operates into the Power Park Module or HVDC Equipment, DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter control system to cause the Power Park Module, or HVDC Equipment DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter to act in a manner which results in the damping power being improved while maintaining adequate synchronising power. This signal will modulate the 3 phase voltage signal described in ECC changing either the amplitude, frequency or/and phase. The signal will be bandwidth limited to <5Hz. The arrangements for the supplementary control signal shall ensure that the power oscillations damping facility output signal relates only to changes in the supplementary control signal and not the steady state level of the signal. For example, if Power Park Module or HVDC Equipment, DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter electrical power output is chosen as a supplementary control signal then the power oscillation damping facility output should relate only to changes in Power Park Module or HVDC Equipment, DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter electrical power output and not the steady state level of power output. Additionally the power oscillation damping facility should not react to changes in isolation. For example during rapid changes in steady state load or when providing frequency response. If the output signal from the power oscillation damping facility modulates the voltage, it shall be limited to not more than ±10% of the Power Park Modules or Power Park Unit s or HVDC EquipmentConverter s input voltage. The gain of the power oscillation damping facility shall be such that it shall not cause control system instability The Generator or HVDC SystemConverter Station Owner will agree the settings of the power oscillation damping facility with NGET prior to the on-load commissioning detailed in BC2.11.2(d) (This will need to be updated in the code). To allow assessment of the performance before on-load commissioning, the Generator or HVDC SystemConverter Station Owner will provide to NGET a report covering the areas specified in ECP.A (This will need to be updated in the code).

37 ECC.A ECC.A ECC.A.1.75 ECC.A ECC.A ECC.A ECC.A.1.86 The power oscillation damping facility must be active within the overall Power Park Module or HVDC EquipmentConverter control system at all times when the Power Park Module or HVDC Equipment Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter is connected to the System and exporting Active Power. Where a power oscillation damping facility is fitted to a battery system or DC Converter it must have the facility to function when the battery Systemor DC Converter is both importing and exporting. Instructions to Generators or HVDC SystemConverter Station Owners would be in accordance with the requirements of the Balancing Code. Overall Control System Characteristics The overall Power Park Module or, DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter HVDC Equipment control system including the power oscillation damping facility, shall include elements that 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 will be judged to be acceptable for this application. The response of the Power Park Module or, HVDC Equipment Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter control system including the power oscillation damping facility shall be demonstrated by injecting similar step signal disturbances into the Power Park Module or HVDC Equipment control system voltage reference as detailed in OC5A.2.2 and OC5.A.2.4 (These references will need to be updated). The Power Park Module or, HVDC Equipment Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter control system shall include a facility to allow step injections into the voltage reference of the Power Park Module, or HVDC EquipmentConverter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter control system, with the Power Park Module or HVDC Equipment Onshore Generating Unit operating at points specified by NGET (up to rated MVA output). The damping shall be judged to be adequate if the corresponding Active Power response to the disturbances decays within two cycles of oscillation. A facility to inject a band limited random noise signal into the voltage reference of the Power Park Module or, HVDC Equipment Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter control system shall be provided for demonstrating the frequency domain response of the power oscillation damping facility. The tuning of the power oscillation damping facility shall be judged to be adequate if the corresponding Active Power response shows improved damping over the frequency range 0.3Hz 2Hz when the power oscillation damping facility is switched into service within the Power Park Module control system.. Other Control System requirements Formatted: Font: 11 pt, Underline Formatted: Font: 11 pt Formatted: Font: Italic, Highlight Comment [RI8]: PSS uses voltage control to provide additional damping to the existing damper winding. In our VSM model its one continuous gain control from no damping to full damping.

38 ECC.A ECC.A ECC.A ECC.A ECC.A Any additional Power Park Module or, HVDC EquipmentConverter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter control system requirements which are necessary for System reasons shall be specified by NGET in the Bilateral Agreement. If the operating point moves outside the extended capability region specified in ECC , the Power Park Module or HVDC Equipment, DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter may rapidly reduce real or Reactive Power, voltage or current by reducing pulse width, phase angle, Frequency and or voltage to bring the device back within but not below the extended rating. Operation within the extended rating should be available up to a level of 0.33pu active power greater than the current operating point for the period required to support a frequency change of 52Hz to 47Hz with the equivalent simulated inertia as defined in ECC.A Operation within the extended Active Power rating is only applicable for changes in operating angle and system frequency. Decreases in system frequency will be followed by frequency recovery through either frequency response from plant in Frequency Sensitive Mode or load rejection. During frequency recovery the Power Park Module, or HVDC Equipment DC Converter at a DC Converter Station, DC Connected Power Park Module and Remote End DC Converter may reduce its output in line with the simulated inertia specified in ECC.A.1.2.3, allowing recharging of storage and cooling of power components. Operation at the extended rating should be available again after this period. Subsequent cycles should be available on a continuous on-going basis provided that on average the device has only operated at full rating. Formatted: No underline, Highlight Formatted: Font: 11 pt, No underline, No underline Formatted: No underline, Highlight Formatted: Font: 11 pt Formatted: No underline, Highlight Formatted: Font: 11 pt, Highlight Formatted: No underline, Highlight Formatted: Font: 11 pt Formatted: Font: 11 pt, Highlight Formatted: No underline, Highlight Formatted: Indent: Left: 0 cm, First line: 0 cm, Tab stops: 3.5 cm, Left + Not at 3 cm

39 APPENDIX 4EC1 FAST FAULT CURRENT INJECTION REQUIREMENTS OPTION 1 APPENDIX EADX FAST FAULT CURRENT INJECTION REQUIREMENTS FOR POWER PARK MODULES, DC CONVERTERS AT A DC CONVERTER STATION, DC CONNECTED POWER PARK MODULES AND REMOTE END DC CONVERTERS ECC.AX1 ECC.AX1.1 ECC.AX1.2 ECC.AX1.2 Scope The fast fault current injection requirements are defined in ECC , ECC or ECC This Appendix provides illustrations by way of examples of ECC , ECC and ECC and is not intended to show all possible permutations. As detailed in ECC Generators who own Type B, Type C and Type D Power Park Modules or DC Connected Power Park Modules or DC Converter Station Owners who Own a DC Converter at a DC Converter Station or a Remote End DC Converter shall have the option of meeting either the requirements of (iii) (iv) (v) ECC or ECC or ECC Generators and DC Converter Station Owners should be aware that the requirements defined under ECC and ECC shall only be available to Generators and DC Converter Station Owners which have a Contract Date before 1 January ECC.AX2 Fast Fault Current Injection requirements (ECC ) Option 1 ECC.AX.2.1 Fast Fault Current Injection behaviour during a solid three phase close up short circuit fault lasting up to 140ms ECC.AX2.1.1 For a voltage depression at a Grid Entry Point or User System Entry Connection Point, the Fast Fault Current Injection requirements are detailed in ECC Figure ECCAX2.1 shows a theoreticaln example of a 500MW Power Park Module subject to a close up solid three phase short circuit fault connected directly connected to the Transmission System operating at 400kV.

40 Voltage Figure ECCAX2.1 ECC.AX2.1.2 Assuming negligible impedance between the fault and substation C, the voltage at Substation C will be close to zero until circuit breakers at Substation C open, typically within ms, subsequentially followed by the opening of circuit breakers at substation A and B, typically 140ms after fault inception. The operation of circuit breakers at Substations A, B and C will also result in the tripping of the 1800MW Generator which is permitted under the SQSS. An example of the voltage trace at Substation CB is shown in Figure ECC.AX Voltage At Substation C Time Formatted: Indent: First line: 0 cm Figure EXXAX2.2 Voltage Trace at Substation C

41 Reactive Current ECC.AX2.1.3 The Power Park Module is required to satisfy the requirements of ECC , and an example of the expected reactive current delivered by the Power Park Module before, during and after the fault is shown in Figure ECCXXAX2.3.AX2.2 below. Generators and HVDC System Owners should be aware that the reactive current delivered must be in phase with the voltage waveform at the Grid Entry Connection Point or User System Entry Point which is a function of the load. Generators and HVDC System Owners should be aware that the Power Park Module should maintain the same phase and frequency as the pre-fault condition Reactive Current Injection Formatted: Indent: First line: 1 cm Time Figure EXXAX2.31 Reactive Current Injected from Power Park Module connected to Substation C Formatted: Space After: 0 pt ECC.AX2.1.4 As shown in Figure EXXAX2.31 the delivery of reactive current is applied instantaneously upon application of the fault in the same way as a Synchronous Generating Unit. ECC.AX.2.2 Fast Fault Current Injection behaviour during a voltage dip at the Connection Point lasting in excess of 140ms ECC.AX2.2.1 Under the fault ride through requirements specified in ECC (Voltage dips cleared in excess of 140ms), Type B, Type C and Type D Power Park Modules and DC Converters are also required to remain connected and stable for voltage dips on the Transmission System in excess of 140ms. Figure ECCAX2.2.1(a) shows an example of a 500MW Power Park Module connected to the Transmission System and Figure ECCAX2.2.1(b) shows the corresponding voltage dip seen at the Connection Point which has resulted from a remote fault on the Transmission System cleared in a backup operating time of 710ms.

42 Figure ECCAX2.2.1(a) Figure ECCAX2.2.1(b) ECC.AX2.2.2 In this example, the voltage dips to 0.5pu for 710ms. Under ECC (iv) each Type B, Type C and Type D Power Park Module is required to deliver reactive current into the System and shall respond instantaneously and in proportion to the change in System voltage at the Grid Entry Point or User System Point up to a maximum value of 1.5pu of rated current. An example of the delivered reactive current at the Connection Point is shown in Figure ECC.AX2.2.2.

43 Reactive current Reactive Current Injection Axis Title Figure EXXAX2.21 Reactive Current Injected from Power Park Module connected to Substation C Formatted: Space After: 0 pt ECC.AX2.2.3 Generators should be aware that whilst this is only an example, under all situations the delivery of reactive current should instantaneously follow the change in load and voltage on the system during the period of the voltage disturbance.

44 PROPOSED FAST FAULT CURRENT INJECTION LEGAL DRAFTING Key 1) Blue Text From Grid Code 2) Black Text Changes / Additional words 3) Orange/ Brown text From RfG 4) Highlighted Green text Questions for Stakeholders / Consultation 5) Highlighted yellow text Nomenclature / Table / Figure numbers to be finalised when more detail has been added DRAFT FAST FAULT CURRENT INJECTION LEGAL TEXT OPTION 2 NOTE;- AS PART OF THE STAKEHOLDER DISCUSSIONS THREE OPTIONS FOR FAST FAULT CURRENT INJECTION HAVE BEEN DISCUSSED. IT IS ANTICPATED THAT ONLY ONE OF THESE OPTIONS WILL ONLY EVENTUALLY BE INCOPORATED INTO THE FINAL GRID CODE AS APPROVED BY THE AUTHORITY. THE TEXT BELOW COVERS OPTION 1 ALONE, OPTION 2 AND 3 ARE COVERED IN SEPARATE DOCUMENTS. Formatted: Justified, Indent: Left: 0 cm, First line: 0 cm, Tab stops: 0 cm, Left + Not at 2.5 cm IT SHOULD BE NOTED THAT FAST FAULT CURRENT INJECTION POSES SIGNIFICANT CHALLENGES BOTH FOR DEVELOPERS AND NETWORK OPERATORS IN THE FUTURE. THE CURRENT PURPOSE OF THIS WORK IS TO IMPLEMENT RFG. BASED ON THE ANALYSIS NATIONAL GRID S PREFERRED OPTION IS TO ADOPT AN APPROACH OUTLINED IN OPTION 1, HOWEVER IT IS RECONGINSED THAT THIS IS NOT WITHOUT ITS CHALLENGES AND OPTION 2 AND OPTION 3 ARE ALSO VALID ALTERNTIVES. IF AS A RESULT OF THIS CONSULTATION, THE GENERAL CONCENSUS IS TO ADOPT EITHER OPTION 2 OR OPTION 3, NATIONAL GRID WOULD RECOMMEND THAT AN EXPERT / STAKEHOLDER FFCI WORKGROUP IS ESTABLISHED IN THE IMMEDIATE SHORT TERM TO INVESTIGATE TECHNCIAL SOLUTIONS AND MARKET BASED SOLUTIONS FOR THE LONGER TERM INTEGRITY OF THE SYSTEM IN THE 2020 S. GLOSSARY AND DEFINITIONS A complete review of the Glossary and Definitions will be required when the full suite of European Codes has been implemented. The current assumption is to use GB definitions where appropriate with use of European definitions where required. The current European definitions used in the text are summarised below but it should be stressed that this is very much work in progress and further revisions will be required in the future. Term Fast Fault Current Definition A current delivered by a Power Park Module or HVDC System during and after a voltage deviation caused by an electrical fault within the System with the aim of identifying a fault by network Protection systems at the initial stage of the fault, supporting System voltage retention at a later stage of the fault and System voltage restoration after fault clearance. Formatted: Font color: Auto

45 Reactive Current Contract Date The current provided in the steady state condition which is 90 degrees out of phase with the active power The date at which a User has concluded a final and binding contract for its main Plant and Apparatus Formatted: Font color: Auto Formatted: Font color: Auto Comment [NG1]: Need to tidy up this to ensure consistency, Font color: Auto ECC.2 ECC.2.1 DEFINITIONS OF PHYSICAL QUANTITIES For the purposes of the Grid Code, physical quantities such as current or voltage are not defined terms as their meaning will vary depending upon the context of the obligation. For example, voltage could mean positive phase sequence root means square voltage, instantaneous voltage, phase to phase voltage, phase to earth voltage. The same issue equally applies to current, and it therefore felt that in view of these variations the terms current and voltage should remain undefined with the meaning depending upon the context of the application. The European Connection Codes define requirements of current and voltage but they have not been adopted as part of EU implementation., Font color: Auto Formatted: Font color: Auto, Font color: Auto Formatted: Font color: Auto CONNECTION CONDITIONS Formatted: Indent: Left: 0 cm, First line: 0 cm ECC FAST FAULT CURRENT INJECTION ECC General Fast Fault Current injection, principles and concepts applicable to Type B, Type C and Type D Power Park Modules and HVDC EquipmentDC Converters at a DC Converter Station, DC Connected Power Park Modules and Remote End DC Converters ECC (i) (ii) ECC This section sets out the Fast Fault Current injection requirements for Type B, Type C and Type D Power Park Modules, DC Converters at a DC Converter Station, DC Connected Power Park Modules and Remote End DC Converters. Generators and DC Converter Station Owners who own Type B, Type C and Type D Power Park Modules, DC Converters at a DC Converter Station shall have the option of meeting either the requirements of ECC or ECC Generators or DC Converter Station Owners should notify NGET which option they wish to select within 28 days of signing a Connection Agreement or such longer period as NGET may agree, in any event this being no later than 3 months before the Completion Date of the offer for a final CUSC Contract. For the avoidance of doubt, the requirements defined under ECC shall only be available to Generators and DC Converter Station Owners which have a Completion Date before 1 January Formatted: Indent: Left: 0 cm, Hanging: 3 cm, No bullets or numbering Formatted: Indent: Left: 0 cm, Hanging: 3 cm

46 ECC In the case of a DC Connected Power Park Module or Remote End HVDC Converter, the requirements of ECC or ECC shall apply unless NGET has agreed to an alternative requirement which would be pursuant to the terms of the Bilateral Agreement. Any alternative agreed would still need to comply with the requirements defined under the HVDC Code ((Regulation EU) 2016/1447). ECC Fast Fault Current injection - Option 21 ECC (i) For Generators and DC Converter Station Owners selecting to satisfy the Fast Fault Current Injection requirements Option 2 Eeach Type B, Type C and Type D Power Park Module or HVDC EquipmentConverter Station Owner shall be required to satisfy the following requirements. Generators and DC Converter Station Owners should be aware that this option is only available to Type B, Type C and Type D Power Park Modules and DC Converter Station Owners with a Contract Date before 1 January 2021 unless otherwise specified in the Bilateral Agreement. For any balanced or unbalanced fault which results in the voltage on one or more phases falling to zero at the Grid Entry Point or User System Entry Point each Type B, Type C and Type D Power Park Module or HVDC EquipmentConverter Station shall be required to inject a reactive current above the shaded red area shown in Figure X3(a) and Figure X3 (b). Comment [NG2]: Need to check with Legal that there is no need to refer to DC Connected Power Park Modules or Remote End DC Converters by reference to ECC Comment [NG3]: Tie into paragraph 1 ECC Formatted: Indent: Left: 0 cm, Hanging: 3 cm Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Bold Formatted: Indent: Left: 0 cm, Hanging: 3 cm, No bullets or numbering Figure X3(a)

47 Figure X3(b) (ii)(i) (i) The converter of each Type B, Type C and Type D Power Park Module or HVDC EquipmentConverter at a DC Converter Station is permitted to block upon fault clearance in order to mitigate against the risk of instability that would otherwise occur due to transient overvoltage excursions. Figure X3(a) and Figure X3(b) shows the impact of variations in fault clearance time which shall be no greater than 140ms. Where the User is able to demonstrate to NGET that blocking is required in order to prevent the risk of transient over voltage excursions as specified in ECC (iv)) Generators and HVDC SystemConverter Station Owners are required to both advise and agree with NGET of the control strategy in accordance with the terms of the Bilateral Agreement, which must also include the approach taken to de-blocking. Not withstanding this requirement, Generators and HVDC Converter StationSystem Owners should be aware of their requirement to fully satisfy the requirements of ECC (fault ride through). In addition, the reactive current injected from each Power Park Module orand HVDC EquipmentConverter Station Owner shall be injected in proportion and remain in phase to the change in System voltage at the Connection Point or User System Entry Point during the period of the fault. For the avoidance of doubt, a small delay time of no greater than 20ms from the point of fault inception is permitted before injection of the in phase reactive current. For voltage depressions of 0.65p.u or below, reactive current injection shall take priority over active current injection up to a maximum of 1.25p.u. of the rating of the Power Park Module or HVDC Converter Equipmentat a DC Converter Station. Formatted: Indent: Left: 3.25 cm, Hanging: 1.75 cm, No bullets or numbering, Tab stops: 5 cm, Left + Not at 3.25 cm Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt, Not Bold Formatted: Font: 11 pt, Bold

48 (iii)(ii) (iv)(iii) (v) Each Type B, Type C and Type D Power Park Module or HVDC Equipment Converter at a DC Converter Station shall be designed to reduce the risk of transient over voltage levels arising following clearance of the fault. Generators or HVDC Converter StationSystem Owners shall be permitted to block where the anticipated transient overvoltage would not otherwise exceed the maximum permitted values specified in ECC Any additional requirements relating to transient overvoltage performance will be specified by NGET in the Bilateral Agreement. In addition to the requirements of ECC X.X (Fault Ride Through) Generators in respect of Type B, Type C and Type D Power Park Modules and HVDC SystemConverter Station Owners are required to confirm to NGET, their repeated ability to supply Fast Fault Current to the System each time the voltage at the Grid Entry Point or User System Entry PointConnection Point falls outside the limits specified in ECC Generators and HVDC Converter StationEquipment Owners should inform NGET of the maximum number of repeated operations that can be performed under such conditions and any limiting factors to repeated operation such as protection or thermal rating; and An illustration and examples of the performance requirements expected are illustrated in Appendix 4EC2. Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt, Highlight Formatted: Indent: Left: 0 cm, First line: 0 cm, Tab stops: 3.5 cm, Left + Not at 3 cm

49 APPENDIX 4EC2 FAST FAULT CURRENT INJECTION REQUIREMENTS OPTION 2 APPENDIX EADX FAST FAULT CURRENT INJECTION REQUIREMENTS FOR POWER PARK MODULES, DC CONVERTERS AT A DC CONVERTER STATION, DC CONNECTED POWER PARK MODULES AND REMOTE END DC CONVERTERS ECC.AX1 Scope ECC.AX3 Fast Fault Current Injection requirements (ECC ) Option 2 ECC.AX3.1 Fast Fault Current Injection behaviour during a solid three phase close up short circuit fault lasting up to 140ms ECC.AX3.1.1 For a voltage depression at a Grid Entry Connection Point or User System Entry Point, the Fast Fault Current Injection requirements are detailed in ECC Figure ECCAX3.1.1 shows an example of a 500MW Power Park Module subject to a close up solid three phase short circuit fault connected directly connected to the Transmission System operating at 400kV. Figure ECCAX3.1

50 Reactive Current ECC.AX3.1.2 Assuming negligible impedance between the fault and substation C, the voltage at Substation C will be close to zero until circuit breakers at Substation C open, typically within ms, subsequentially followed by the opening of circuit breakers at substations A and B, typically 140ms after fault inception. The operation of circuit breakers at Substations A, B and C will also result in the tripping of the 800MW Generator. The Power Park Module is required to satisfy the requirements of ECC , and an example of the expected reactive current injected by the Power Park Module before, during and after the fault is shown in Figure ECC.AX2.2. Reactive Current Injection Formatted: Indent: First line: 0 cm Time Figure ECC.AX2.2 Reactive Current Injected from the Power Park Module connected to Substation C. Formatted: Centered It is important to note that bblocking is permitted upon fault clearance in order to limit the impact of ttransient oovervoltages. This effect is shown in Figure ECC.AX3.1.2(a) and Figure ECC.A.X.3.1.2(b)

51 Modify Figure Superimpose Reactive Current on top of curve Figure ECC.AX3.1.2(a) Modify Figure Superimpose Reactive Current on top of curve Figure ECC.AX3.1.2(b) ECC.AX3.1.3 So long as the reactive current injected is above the shaded area as illustrated in Figure ECC.AX3.1.2(a) or ECC.AX3.1.2, the Power Park Module would be considered to be compliant with the requirements of ECC Taking the example outlined in ECC.AX3.1.1 where the fault is cleared in 140ms, the following diagram in Figure ECC.AX3.1.3 results.

52 Formatted: Indent: First line: 0 cm Figure ECC.AX3.1.3 Blue curve Injected Reactive Current injected from Power Park Module, Red Curve Grid Code Fast Fault Current Injection requirement (option 2) Formatted: Centered, Indent: First line: 0 cm ECC.AX3.2 Fast Fault Current Injection behaviour during a voltage dip at the Connection Point lasting in excess of 140ms ECC.AX3.2.1 Under the fault ride through requirements specified in ECC (Voltage dips cleared in excess of 140ms), Type B, Type C and Type D Power Park Modules are also required to remain connected and stable for voltage dips on the Transmission System in excess of 140ms. Figure ECCAX3.2.1(a) shows an example of a 500MW Power Park Module connected to the Transmission System and Figure ECCAX3.2.1(b) shows the corresponding voltage dip seen at the Connection Point which has resulted from a remote fault on the Transmission System cleared in a backup operating time of 710ms.

53 Figure ECCAX3.2.1(a) Figure ECCAX3.2.1(b) ECC.AX3.2.2 In this example, the voltage dips to 0.5pu for 710ms. Under ECC (ii) each Type Type B, Type C and Type D Power Park Module is required to inject reactive current into the System and shall respond in proportion to the change in System voltage at the Connection Point up to a maximum value of 1.25pu of rated current. An example of the expected injected reactive current at the Grid Entry Connection Point or User System Entry Point is shown in Figure ECC.AX3.2.2.

54 Figure EXXAX3.2.2 Reactive Current Injected for a 50% voltage dip for a period of 710ms. Formatted: Indent: First line: 0 cm

55 PROPOSED FAST FAULT CURRENT INJECTION LEGAL DRAFTING Key 1) Blue Text From Grid Code 2) Black Text Changes / Additional words 3) Orange/ Brown text From RfG 4) Highlighted Green text Questions for Stakeholders / Consultation 5) Highlighted yellow text Nomenclature / Table / Figure numbers to be finalised when more detail has been added DRAFT FAST FAULT CURRENT INJECTION LEGAL TEXT OPTION 3 NOTE;- AS PART OF THE STAKEHOLDER DISCUSSIONS THREE OPTIONS FOR FAST FAULT CURRENT INJECTION HAVE BEEN DISCUSSED. IT IS ANTICPATED THAT ONLY ONE OF THESE OPTIONS WILL ONLY EVENTUALLY BE INCOPORATED INTO THE FINAL GRID CODE AS APPROVED BY THE AUTHORITY. THE TEXT BELOW COVERS OPTION 1 ALONE, OPTION 2 AND 3 ARE COVERED IN SEPARATE DOCUMENTS. IT SHOULD BE NOTED THAT FAST FAULT CURRENT INJECTION POSES SIGNIFICANT CHALLENGES BOTH FOR DEVELOPERS AND NETWORK OPERATORS IN THE FUTURE. THE CURRENT PURPOSE OF THIS WORK IS TO IMPLEMENT RFG. BASED ON THE ANALYSIS NATIONAL GRID S PREFERRED OPTION IS TO ADOPT AN APPROACH OUTLINED IN OPTION 1, HOWEVER IT IS RECONGINSED THAT THIS IS NOT WITHOUT ITS CHALLENGES AND OPTION 2 AND OPTION 3 ARE ALSO VALID ALTERNTIVES. IF AS A RESULT OF THIS CONSULTATION, THE GENERAL CONCENSUS IS TO ADOPT EITHER OPTION 2 OR OPTION 3, NATIONAL GRID WOULD RECOMMEND THAT AN EXPERT / STAKEHOLDER FFCI WORKGROUP IS ESTABLISHED IN THE IMMEDIATE SHORT TERM TO INVESTIGATE TECHNCIAL SOLUTIONS AND MARKET BASED SOLUTIONS FOR THE LONGER TERM INTEGRITY OF THE SYSTEM IN THE 2020 S. GLOSSARY AND DEFINITIONS A complete review of the Glossary and Definitions will be required when the full suite of European Codes has been implemented. The current assumption is to use GB definitions where appropriate with use of European definitions where required. The current European definitions used in the text are summarised below but it should be stressed that this is very much work in progress and further revisions will be required in the future. Term Fast Fault Current Definition A current delivered by a Power Park Module or HVDC System during and after a voltage deviation caused by an electrical fault within the System with the aim of identifying a fault by network Protection systems at the initial stage of the fault, supporting System voltage retention at a later stage of the fault and System voltage restoration after fault clearance. Formatted: Font color: Auto

56 Reactive Current Contract Date The current provided in the steady state condition which is 90 degrees out of phase with the active power The date at which a User has concluded a final and binding contract for its main Plant and Apparatus Formatted: Font color: Auto Formatted: Font color: Auto Comment [NG1]: Need to tidy up this to ensure consistency, Font color: Auto ECC.2 ECC.2.1 DEFINITIONS OF PHYSICAL QUANTITIES For the purposes of the Grid Code, physical quantities such as current or voltage are not defined terms as their meaning will vary depending upon the context of the obligation. For example, voltage could mean positive phase sequence root means square voltage, instantaneous voltage, phase to phase voltage, phase to earth voltage. The same issue equally applies to current, and it therefore felt that in view of these variations the terms current and voltage should remain undefined with the meaning depending upon the context of the application. The European Connection Codes define requirements of current and voltage but they have not been adopted as part of EU implementation., Font color: Auto Formatted: Font color: Auto, Font color: Auto Formatted: Font color: Auto CONNECTION CONDITIONS Formatted: Indent: Left: 0 cm, First line: 0 cm ECC FAST FAULT CURRENT INJECTION ECC General Fast Fault Current injection, principles and concepts applicable to Type B, Type C and Type D Power Park Modules and HVDC EquipmentDC Converters at a DC Converter Station, DC Connected Power Park Modules and Remote End DC Converters ECC (i) (ii) ECC This section sets out the Fast Fault Current injection requirements for Type B, Type C and Type D Power Park Modules, DC Converters at a DC Converter Station, DC Connected Power Park Modules and Remote End DC Converters. Generators and DC Converter Station Owners who own Type B, Type C and Type D Power Park Modules, DC Converters at a DC Converter Station shall have the option of meeting either the requirements of ECC or ECC Generators or DC Converter Station Owners should notify NGET which option they wish to select within 28 days of signing a Connection Agreement or such longer period as NGET may agree, in any event this being no later than 3 months before the Completion Date of the offer for a final CUSC Contract. For the avoidance of doubt, the requirements defined under ECC shall only be available to Generators and DC Converter Station Owners which have a Completion Date before 1 January Formatted: Indent: Left: 0 cm, Hanging: 3 cm, No bullets or numbering Formatted: Indent: Left: 0 cm, Hanging: 3 cm

57 ECC In the case of a DC Connected Power Park Module or Remote End HVDC Converter, the requirements of ECC or ECC shall apply unless NGET has agreed to an alternative requirement which would be pursuant to the terms of the Bilateral Agreement. Any alternative agreed would still need to comply with the requirements defined under the HVDC Code ((Regulation EU) 2016/1447). ECC Fast Fault Current injection - Option 3 ECC (i) For Generators and DC Converter Station Owners selecting to satisfy the Fast Fault Current Injection requirements Option 2 Eeach Type B, Type C and Type D Power Park Module or HVDC EquipmentConverter Station Owner shall be required to satisfy the following requirements. Generators and DC Converter Station Owners should be aware that this option is only available to Type B, Type C and Type D Power Park Modules and DC Converter Station Owners with a Contract Date before 1 January 2021 unless otherwise specified in the Bilateral Agreement. For any balanced or unbalanced fault which results in the voltage on one or more phases falling to zero at the Grid Entry Point or User System Entry Point each Type B, Type C and Type D Power Park Module or HVDC EquipmentConverter Station shall be required to inject a reactive current above the shaded red area shown in Figure 4X3(a) and Figure 4X3 (b). Comment [NG2]: Need to check with Legal that there is no need to refer to DC Connected Power Park Modules or Remote End DC Converters by reference to ECC Comment [NG3]: Tie into paragraph 1 ECC Formatted: Indent: Left: 0 cm, Hanging: 3 cm Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Bold Formatted: Indent: Left: 0 cm, Hanging: 3 cm, No bullets or numbering Figure X43(a)

58 Figure X43(b) (i) The converter of each Type B, Type C and Type D Power Park Module or HVDC EquipmentConverter at a DC Converter Station is permitted to block upon fault clearance in order to mitigate against the risk of instability that would otherwise occur due to transient overvoltage excursions. Figure X43(a) and Figure X43(b) shows the impact of variations in fault clearance time which shall be no greater than 140ms. Where the User is able to demonstrate to NGET that blocking is required in order to prevent the risk of transient over voltage excursions as specified in ECC (iv)) Generators and HVDC SystemConverter Station Owners are required to both advise and agree with NGET of the control strategy in accordance with the terms of the Bilateral Agreement, which must also include the approach taken to de-blocking. Not withstanding this requirement, Generators and HVDC Converter StationSystem Owners should be aware of their requirement to fully satisfy the requirements of ECC (fault ride through). Formatted: Indent: Left: 3.25 cm, Hanging: 1.75 cm, No bullets or numbering, Tab stops: 5 cm, Left + Not at 3.25 cm Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Highlight Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt, Bold Formatted: Font: 11 pt, Not Bold Formatted: Font: 11 pt, Bold