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Date:- 14 March 2012 COMPARISON OF GB AND EUROPEAN GRID CODE REQUIREMENTS Key to Tables Symbol N/A N/S Article 4(3) Definition Not specified in GB Grid Code but other requirements may apply in other industry Codes such as the System Operator Transmission Owner Code (STC) Distribution Code or Engineering Recommendations such as G59, ETR 113 and G83. Not specified in ENTSO-E RfG Code often because not deemed to be a cross border issue but other National requirements may apply. Where reference in the Table is given to Article 4(3) this means that any decision made by a Relevant Network Operator, or Relevant TSO and a Relevant Network Operator or Power Generator may require agreement with the National Regulating Authority. Notes:Table 1 compares the ENTSO-E Network Code – Requirements for Generators (RfG) with the GB Grid Code. In other words each clause of the ENTSO-E RfG has been compared against the GB Grid Code. This table is deliberately light on detail to identify where the ENTSO-E RfG is possibly more onerous (red text) or less onerous (green text) than the GB Grid Code. Table 2 compares the GB Grid Code with the ENTSO-E RfG. This is a much more detailed Table comparing the exact requirements of the GB Grid Code with the exact requirements of the ENTSO-E RfG. The reader should however be aware that in adopting this comparison there may be elements in the ENTSO-E RfG that have not been identified as and this is where Table 1 is considered to be helpful. Table 3 compares the GB Grid Code with the ENTSO-E RfG in respect of Offshore Power Park Modules. As the ENTSO-E RfG makes extensive reference to the Onshore ENTSO-E RfG requirements, Table 3 compares in detail the Offshore ENTSO-E RfG with the GB Grid Code. These Tables have been prepared in good faith with limited internal review and indicate National Grid’s interpretation of the differences between the GB Grid Code and ENTSO-E RfG. Where there is a conflict between these Tables and the Code, the Code should be taken as the definitive text. TABLE 1 – COMPARISION OF ENTSO-E RfG TO GB GRID CODE ENTSO-E – RfG GB Code Requirements applicable to Type A Units - 400W – 1MW but equally applicable to Type A, B, C and D Units This comparison only applies to the GB Code and not other codes such as the Distribution Code, STC or other documents such as G59, etc. The purpose of this table is simply to provide a comparison between the ENTSO-E RfG and GB Code with reference to the ENTSO-E RfG. Article 7 – General Requirements - Type A Units Article 7 (1) (a) - Frequency range Consistent with GB Grid Code – CC.6.1.3, CC.6.3.12 and CC.6.3.13 (CC.6.3.12 and CC.6.3.13 apply only to Large and Medium Power Stations. Rate of change of Frequency limits not specially covered in GB Grid Code although reference can be made in the Bilateral Agreement as specified in CC.6.3.12 - applies only to Large and Medium Generators). Consistent with GB Code but only for BM Units (ie Generation operating in the wholesale Electricity Market) – BC.3.7.2. For Embedded Small Power Stations which are not BMU’s – N/A. The BC’s will apply to BMU’s. Article 7 (1) (b) – Rate of Change of Frequency Article 7 (1) (c) – Limited Frequency Sensitive Mode – Over- frequency Article 7 (1) (d) – Fitting of logic interface in order to disconnect from the Network 1 TABLE 1 – COMPARISION OF ENTSO-E RfG TO GB GRID CODE ENTSO-E – RfG GB Code Article 8 – General Requirements - Type B Units Article 8 (1) – All Type B units must meet the same requirements as Type A units Article 8 (2) – Reduction of Active Power in steps not bigger than 20% of maximum capacity Article 8 (3) – Reconnection requirements following a Network Disturbance For Small Power Stations – N/A. For Large and Medium Power Stations more stringent requirements apply. Applicable only to Power Stations for which NGET have a direct relationship – specified under the Grid Code Balancing Codes Not believed to conflict with the GB Grid Code. Article 8 (4) (a) – General System Management requirements – Control schemes and settings as agreed with the TSO, Network Operator and Power Generating Facility Owner – Isolated Network Operation, damping, system disturbances Article 8 (4) b) Information Exchange – Power Generating facilities shall be equipped with information exchange facilities between the Relevant Network Operator and Power Generating Facility. Article 9 – General Requirements - Type C Units Article 9 (1) – All Type C units must meet the same requirements as Type A and B units except Articles 7(1)(d) and Article 8(2)(a) Article 9(2) (a) – Active Power controllability and Control range Article 9(2)(b) – Synthetic inertia Not believed to conflict with the GB Grid Code. Requirements for information exchange are covered in CC.6.5 Control Telephony, CC.6.5.8 – Instructor Facilities and CC.6.5.9 – Fax machines. Consistent with GB Grid Code – CC.6.3.6(a), CC.6.3.7 and BC3. Not currently specified in GB Grid Code but the Frequency Response Working Group are investigating these issues. Not specified in GB Grid Code – ENTSO-E RfG requirement is over and above the requirement in the GB Grid Code. Consistent with GB Grid Code – CC.6.3.7 and CC.A.3. Note:- The ENTSO-E RfG specifies a frequency response capacity (as a percentage of Registered Capacity of between 2 and 10%). The GB Grid Code specifies a minimum frequency response capability of 10% of Registered Capacity. Consistent with GB Grid Code – CC.6.3.6(a), CC.6.3.7, CC.A.3 and BC3 This is not currently specified in the GB Grid Code. There is no mandatory requirement for Demand Disconnection from Pumped Storage Demand to control system frequency. Currently only applicable to HVDC Converters and Pumped Storage or Demand Customers for whom NGET have a Commercial Contract. Broadly consistent with GB Code – OC5.4.1(c) – Ancillary Services and instructions via EDL – CC.6.5.8. In GB there is no requirement for Automatic Generation Control (AGC) which is specified under ENTSO-E RfG Article 9(2)(g)(2). Some of the frequency response monitoring signals which are provided back to NGET are not currently provided (eg droop and deadband). Does not contravene GB Grid Code. Article 9(2)(c) – Limited Frequency Sensitive Mode – Under Frequency Article 9(2)(d) – Frequency Sensitive Mode Article 9(2)(e) – Frequency restoration Article 9(2)(f) – Disconnection due to under frequency – any Power Generating Facility being capable of acting as a load except for auxiliary supply (including pumped storage) shall be capable of disconnecting its load in case of underfrequency Article 9(2)(g) – Real Time Monitoring of Frequency Sensitive Mode operation Article 9(3) – Voltage Stability – automatic disconnection at specified voltages if required by the Relevant Network Operaotor Article 9(4)(a) – Steady State Stability at any operating point within the PQ diagram Article 9(4)(b) – Generating Units shall be designed such that the shaft torsional stress which may be excited by transient Active Power steps up to 50% of its maximum capacity are considered a routine part of normal operation and shall be taken into account when specifying the shaft characteristics Article 9(4)(c) – Auto Re-closure. Requirements specified by TSO pursuant to Article 4(3) Article 9(5)(a) – Black Start Consistent with GB Grid Code – CC.6.3.8 Not explicitly defined in the GB Grid Code, however such switching is considered routine and the RfG helps to provide greater transparency Does not contravene GB Grid Code Consistent with GB Grid Code – CC.6.3.5 Article 9(5)(b) – Island Operation Article 9(5)(c)(1) – Quick Re-synchronisation capability – as agreed with TSO, Relevant Network Operator and Power Generating Facility. Article 9(5)(c)(2) – The generating unit whose minimum re-synchronisation time after its disconnection from an external power supply exceeds 15 minutes shall be designed for tripping to house load from any operating point in the P Q Capability Diagram without using any switchgear position signals for identifying house load Operation. Article 9(5)(c)(3) – Generating Units shall be capable of continuing operation following tripping to house load, irrespective of any auxiliary connection to the external network. The minimum operation time shall be decided by the Relevant Network Operator pursuant to Article 4(3) in coordination with the Consistent with GB Grid Code – CC.6.3.7(c)(i), although references to switchgear position are unclear. Consistent with GB Grid Code Not currently specified in GB Grid Code. Not currently specified in GB Grid Code. 2 TABLE 1 – COMPARISION OF ENTSO-E RfG TO GB GRID CODE ENTSO-E – RfG GB Code Relevant TSO. Article 9(5)(c)(4) – All Power Generating Facility Control Systems shall remain in automatic mode Generally most control systems would be expected to remain in automatic mode but there are occasions where such equipment may be switched into manual mode but only with the approval of NGET. Consistent with GB Grid Code – covered in Bilateral Agreement and Relevant Electrical Standards (RES). Consistent with GB Grid Code (CC.6.2.2) and Bilateral Agreement Not currently specified in GB Grid Code but not believed to be an issue Consistent with Grid Code (CC.6.2.2.3.4 – Pole Slipping Protection) and Bilateral Agreement Consistent with GB Grid Code (CC.6.1.5 - Quality of Supply and CC.6.6 – System Monitoring) and Bilateral Agreement Consistent with GB Grid Code (Planning Code). Note the GB Grid Code does not at present require Generating Units to provide electromagnetic transient simulations but note these are at the request of the TSO and pursuant to Article 4(3) Consistent with GB Grid Code Consistent with GB Grid Code BC1.A.1.1 Consistent with GB Grid Code – CC.6.3.11 Consistent with GB Grid Code – CC.6.1.5, CC.6.1.6, CC.6.1.7 Covered under CUSC and Grid Code Modification process Article 9(6)(a) – Synchronisation Article 9(6)(b) – Protection Schemes and Settings Article 9(6)(c) – Priority ranking of protection and control Article 9(6)(d) – Loss of Stability Article 9(6)(e) – Instrumentation and monitoring – Fault Recording, Dynamic System Monitoring, Quality of Supply Article 9(6)(f) – Simulation Models Article 9(6)(g) – Installation of devices for system operation and/or security Article 9(6)(h) – Minimum and maximum limits on rates of change of Active Power Article 9(6)(i) – Neutral earthing arrangements of step up transformers Article 9(6)(j) – Power / Voltage Quality Article 9(6)(k) – Modernisation / replacement of Generating Plant and Equipment Article 10 – General Requirements - Type D Units Article 10(1) – All Type D units must meet the same requirements as Type A, B and C units except Articles 7(1)(d), Article 8(2)(a) and Article 9(3)(a). Article 10(2(a) – Voltage ranges Article 11 – Requirements for Type B Synchronous Generating Units Article 11(2) Voltage stability – Reactive Power Capability and Excitation System requirements Article 11(3) – Fault Ride Through Consistent with GB Grid Code (CC.6.1.4) Consistent with GB Grid Code (CC.6.3.2 and CC.6.3.8). For Small Power Stations N/A. GB Grid Code requirements (CC.6.3.15) are slightly different (see Table 2 below). In summary, the differences from the GB Code as against the ENTSO-E RfG are:i) Voltage profile is defined at the Connection Point whereas in GB, requirement applies only to Transmission System faults which occur at 200kV or above. ii) The ENTSO-E RfG stipulates a voltage range for both short duration and long duration faults. The TSO will be able to define the voltage profile requirements within a range of up to 150ms and optionally up to 250ms. Note in GB the fault ride through for short duration faults only applies for up to 140ms. The minimum voltage at the Connection voltage will be in the range of between 0.3 p,u and 0.05 p.u. The voltage duration curve (ie the time for which a Generator must withstand low voltages in GB is longer than that stipulated in ENTSO-RfG. For longer duration faults, the voltage duration curve in GB is more onerous than Europe. Compliance issues have been experienced in GB which it is believed the ENTSO-E RfG will resolve. The ENTSO-E RfG implementation will give an opportunity to resolve GB Grid Code anomalies. iii) The TSO (pursuant to article 4(3)) is required to define pre and post fault operating conditions (the details are covered in Table 2 below on the Generating unit. iv) The Relevant TSO (pursuant to Article 4(3)) shall specify the Active Power Recovery characteristics. v) In general there are slight differences but the ENTSO-E RfG are considered to be slightly easier than the GB requirements. Article 12 – Requirements for Type C Synchronous Generating Units Article 12(1) – All Type C Synchronous Generating Units must meet the general requirements listed in Articles 7, 8 and 9 as well as the specific type B Synchronous Generating Unit requirements listed in Article 11, except Article 11(2)(a). Article 12 (2) – Output Power with Falling Frequency and Active Power Regulation – specified by TSO. Article 12 (3) – Reactive Power Capability Consistent with GB Grid Code (CC.6.3.3 and CC.6.3.7) ENTSO-E RfG is broadly consistent with GB Grid Code but is specified in a slightly different way as detailed in 3 TABLE 1 – COMPARISION OF ENTSO-E RfG TO GB GRID CODE ENTSO-E – RfG GB Code table 2 below. The principle differences are as follows:i) TSO to define a U/Q profile (Voltage / Reactive Power profile), Figure 6 - which is not replicated in the GB Code. ii) Under the ENTSO-E RfG the maximum Q/Pmax range specified for GB is 0.95 at the HV terminals of the Generator Transformer. This equates to a Power Factor range of approximately 0.9 Power Factor Lead to 0.9 Power Factor lag at the HV terminals of the Generator Transformer. The ENTSO-E RfG does not provide any distinction between lead and lag – ie the mid point. Under the GB Grid Code the requirement is for a Power Factor of 0.85 Power Lag to 0.95 Power Factor Lead at the Generating Unit terminals. iii) These requirements apply at a steady state voltage of 0.1p.u. (ie 10%) Consistent with GB Grid Code (CC.6.3.7) Article 12 (4) – Power and Speed Control Article 13 – Requirements for Type D Synchronous Generating Units Article 13(1) – All Type D Synchronous Generating Units must meet the general requirements listed in Articles 7, 8, 9 and 10 as well as the specific type B and C Synchronous Generating Unit requirements listed in Article 11 and 12. Article 13(2) – Excitation System Performance requirements including Power System Stabilisers Article 13(3) – Fault Ride Through Consistent with GB Grid Code (CC.6.3.8 and CC.A.6) GB Grid Code requirements (CC.6.3.15) are slightly different (see Table 2 below). In summary, the differences from the GB Code as against the ENTSO-E RfG are:i) Voltage profile is defined at the Connection Point whereas in GB requirement applies only to Transmission System faults which occur at 200kV or above. ii) The ENTSO-E RfG stipulates a voltage range for both short duration and long duration faults. The TSO will be able to define the voltage profile requirements within a range of up to 150ms and optionally up to 250ms at zero voltage at the Connection Point. The voltage duration curve (ie the time for which a Generator must withstand low voltages in GB is longer than that stipulated in Europe by 10ms (ie a move from 140ms to 150ms) for short duration faults. For longer duration faults, the voltage duration curve in GB is more onerous than Europe. Compliance issues have been experienced in GB which it is believed the ENTSO-E RfG will resolve. iii) The TSO (pursuant to article 4(3)) is required to define pre and post fault operating conditions (the details are covered in Table 2 below on the Generating unit. In general there are slight differences but the ENTSO-E RfG are considered to be slightly easier than the GB requirements. Article 14 – Requirements for Type A Power Park Modules Article 14 (1) – All Type A Power Park Modules must meet the same General requirements as Type A units. Article 14(1)(a) – Reactive Power requirements at the Connection Point defined by DSO Article 15 – Requirements for Type B Power Park Modules Article 15(1) – All Type B Power Park Modules must meet the general requirements listed in Articles 7, and 8 as well as the specific requirements for Type A Power Park Modules listed in Article 14. Article 15(2)(a) and (b) – Reactive current injection at the Connection Point for balanced and unbalanced faults. For Small Power Stations – N/A. The GB Grid Code is not detailed on this issue other than under CC.6.3.15 (fault ride through). The GB Grid Code states (within clause CC.6.3.15) that a Generating Unit or Power Park Module should inject maximum reactive current without exceeding the Transient Rating of the Generating Unit or Power Park Module. The ENTSO-E RfG is very different on these requirements. By specifying a minimum reactive power requirement there may be a technical constraints on the delivery of active power during the disturbance. The RfG has been drafted with a view to a national choice of priority between real and reactive power exchange. Further detailed scrutiny may be needed in order to ensure that intent of retaining the GB priority for real current can be retained without overstressing the equipment. GB Grid Code requirements (CC.6.3.15) are slightly different (see Table 2 below). In summary, the differences from the GB Code as against the ENTSO-E RfG are:i) Voltage profile is defined at the Connection Point whereas in GB the requirement applies only Article 15(3) – Fault Ride Through 4 TABLE 1 – COMPARISION OF ENTSO-E RfG TO GB GRID CODE ENTSO-E – RfG GB Code to Transmission System faults which occur at 200kV or above. The ENTSO-E RfG stipulates a voltage range for both short duration and long duration faults. The TSO will be able to define the voltage profile requirements within a range of up to 400ms. The minimum voltage at the Connection voltage will be in the range of between 0.15 p,u and 0.05 p.u. The TSO (pursuant to article 4(3)) is required to define pre and post fault operating conditions (the details are covered in Table 2 below on the Generating unit. iii) The Relevant TSO (pursuant to Article 4(3)) shall specify the Active Power Recovery characteristics upon recovery of the voltage to 85%. In general the ENTSO-E RfG and GB Code are broadly similar but it is noted that the ENTSO-E RfG has a slightly longer Voltage Duration profile than the current GB Code. ii) Article 16 – Requirements for Type C Power Park Modules Article 16(1) – All Type C Power Park Modules must meet the general requirements listed in Articles 7, 8 and 9 as well as the specific requirements for Type B Power Park Modules (except Type A Power Park Modules). Article 16(2) – Synthetic Inertia – specified by TSO pursuant to Article 4(3) Not currently specified in GB Grid Code but the Frequency Response Working Group are investigating these issues. ENTSO-E RfG is fully consistent with the GB Grid Code (CC.6.3.2(c)) but is specified in a slightly different way as detailed in table 2 below. The principle differences are as follows:iv) TSO to define a U/Q profile (Voltage / Reactive Power profile), Figure 10 - which is not replicated in the GB Code. v) Under the ENTSO-E RfG the maximum Q/Pmax range specified for GB is 0.66 at the Connection Point. This equates to a Power Factor range of 0.95 Power Factor Lead to 0.95 Power Factor lag)(ie the same as the GB Code). The ENTSO-E RfG does not provide any distinction between lead and lag but simply provides a range. These requirements apply at a steady state voltage range of 0.1 p.u (ie 10%) Consistent with GB Grid Code (CC.6.3.2(c)). In the GB the requirement of Figure 1 of CC.6.3.2(c)) does have a reduction in reactive capability when operating in the leading mode of operation (below 50%) MW output and the reactive capability requirement is further reduced when the plant is operating below 20% of Registered Capacity. The ENTSO-E RfG does not capture this current GB requirement. Consistent with GB Grid Code (CC.6.3.15) but not explicitly specified. Consistent with GB Grid Code (CC.6.3.8 and CC.A.7) Article 16(3) (b) – Reactive Power capability at maximum capacity Article 16(3) (c) – Reactive Power capability below maximum capacity Article 16(3)(d) – Priority of Reactive Power or Active Power specified by TSO pursuant to Article 4(3) Article 16(3)(e) – Reactive Power Control Modes – ie Voltage Control, Reactive Power Control or Power Factor Control Article 17 – Requirements for Type D Power Park Modules Article 17(1) – All Type D Power Park Modules must meet the general requirements listed in Articles 7, 8, 9 and 10 as well as the specific requirements for Type C Power Park Modules (except for Type A Power Park Modules). Article 17 (1)(a) – Fault Ride Through Capability GB Grid Code requirements (CC.6.3.15) are slightly different (see Table 2 below). In summary, the differences from the GB Code as against the ENTSO-E RfG are:i) Voltage profile is defined at the Connection Point whereas in GB the requirement applies only to Transmission System faults which occur at 200kV or above. ii) The ENTSO-E RfG stipulates a voltage range for both short duration and long duration faults. The minimum voltage at the Connection voltage will be 0 p.u for between 150ms and 250ms. The time for which a Generator must withstand low voltages as stipuated in ENTSO-E RfG is longer than that stipulated in GB by 10ms (ie a move from 140ms to 150ms) for short duration faults. The TSO (pursuant to article 4(3)) is required to define pre and post fault operating conditions (the details are covered in Table 2 below on the Generating Unit. iii) The Active Power Recovery characteristics are specified in Article 15 (Type B Power Park Modules). In general the ENTSO-E RfG and GB Code are broadly similar but it is noted that the ENTSO-E RfG has a 5 TABLE 1 – COMPARISION OF ENTSO-E RfG TO GB GRID CODE ENTSO-E – RfG GB Code slightly longer Voltage Duration profile than the current GB Code. Table 3 of this document details the GB and ENTSO-E RfG differences between Offshore Power Park Modules. This comparison has been completed on the basis of comparing the ENTSO-E RfG with the GB Code such that no elements of the ENTSO-E RfG have been omitted. The reader is therefore referred to Table 3 of this document to compare the differences between the Offshore GB Code and Offshore ENTSO-E RfG. The GB Grid Code does not currently specify a compliance requirement. At the present time the compliance requirements are currently specified in two guidance notes (Guidance Notes for Synchronous Generators, Issue 11, September 2008 and Guidance Notes for Power Park Developers, Issue 2, September 2008). A Consultation has been held on the proposed Compliance Requirements for inclusion in the Grid Code which is currently with Ofgem (the Regulator) for final approval. Requirements for Offshore Power Park Modules – Articles 18 - 23 Operational Notification Procedure – Article 24 - 51 6 (Comparison based on GB Grid Code Issue 4 Revision 9 only and ENSTO - E RFG Internal Version dated 24 January 2012) (Note – Does not include other Industry Codes) Requirement Plant Type Large Frequency Range (GB CC.6.1.3 ENTSO-E – Article 7- 1(a) Table 2 Synchronous and Asynchronous Voltage Operating Range (GB CC.6.1.4) (ENTSO-E – Article 9 – 3a) and Article 10 – 2 a) – 1 Tables 5.1 and 5.2) Synchronous and Asynchronous Power Quality Harmonic Content (GB CC.6.1.5(a) ENTSO-E – Article 9 – 6 j1),2) Synchronous and Asynchronous TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 51.5 – 52 Hz for 15 minutes 51 – 51.5 Hz for 90 minutes 49.0 – 51 Hz Continuous 47.5 – 49 Hz 90 minutes 47 – 47.5 Hz 20 seconds 50 – 100MW N/A (SPT / SHETL) At 400 kV 5% (although voltages between +5% and +10% will not last longer than 15 minutes) At 275 kV 10% At 132 kV 10% Below 132 kV 6% The harmonic distortion from all sources under both Planned Outage and fault conditions shall comply with the requirements of the Tables of Appendix A of Engineering Recommendation G5/4. The Electromagnetic Compatibility levels will be specified by NGET in the 1 – 10 MW 400W – 1 MW As per Type A As per Type A Between 300 kV and 400kV 0.9 p.u – 1.05 p.u and between 1.05 p.u and 1.1p.u for 15 minutes Between 110kV and 300kV 0.9 – 1.10 p.u As defined by the Relevant Network Operator as defined in Article 9 – 3a) pursuant to Article 4(3). N/S 51.5Hz – 52.0 Hz for 15 minutes 51 Hz – 51.5 Hz for 90 minutes 49 Hz – 51 Hz Unlimited 48.5 – 49 Hz – defined by TSO but pursuant to Article 4(3) 47.5 – 48.5Hz for 90 minutes 47 – 47.5 Hz for 20 seconds N/S As per Type C Specified by the Relevant Network Operator which shall be consistent with National and International technical rules. N/S N/S > 30MW or connected at 110kV or above As per Type A As per Large N/A unless directly connected For directly Connected Power Stations – as per Large. N/A As per Large N/A for Embedded Power Stations – specified by DNO. 7 A 30 – 10 MW < 50MW < 30MW (SPT) < 10 MW (SHETL) N/A unless directly connected Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Bilateral Agreement Power Quality Phase Unbalance (GB CC.6.1.5(b)) ENTSO-E – Article 9 – 6 j 1), 2) Power Quality Phase Unbalance during infrequent short duration peaks (GB CC.6.1.6) ENTSO-E – Article 9 – 6j 1), 2) Synchronous and Asynchronous Synchronous and Asynchronous N/A for Embedded Power Stations (Specified by DNO) For Directly Connected Users Under Planned Outage Conditions the maximum Phase Voltage Unbalance should in England and Wales should remain below 1% and in Scotland below 2% unless abnormal conditions prevail. N/A for Embedded Power Stations – specified by DNO For Directly Connected Users Under Planned Outage Conditions stated in CC.6.1.5(b) infrequent short duration peaks with a maximum value of 2% are permitted for phase (voltage) unbalance subject to the prior agreement of NGET under the Bilateral Agreement. A 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW 1 – 10 MW 400W – 1 MW For directly Connected Power Stations – as per Large. N/A As per Type C Specified by the Relevant Network Operator which shall be consistent with National and International technical rules. N/S N?S N/A As per Type C Specified by the Relevant Network Operator which shall be consistent with National and International technical rules. N/S N/S N/A for Embedded Power Stations – specified by DNO For directly Connected Power Stations – as per Large. N/S for Embedded Power Stations – specified by DNO N/Ae for Embedded Power Stations – specified by DNO 8 Requirement Plant Type Large Voltage Fluctuations (GB CC.6.1.7(a) and (b) ENTSO-E – Article 9 – 6 j 1), 2) Synchronous and Asynchronous TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) For Directly Connected Users – Voltage fluctuations at a Point of Common Coupling with a fluctuating load directly connected to the Onshore Transmission System shall not exceed (a) in England and Wales, 1% of the voltage level for step changes which occur repetitively. Any large voltage excursions other than step changes may be allowed up to a level of 3% provided that this does not constitute a risk to the Transmission System. In Scotland the limits for voltage level step changes are defined in P28 50 – 100MW N/A (SPT / SHETL) For directly Connected Power Stations – as per Large. < 50MW < 30MW (SPT) < 10 MW (SHETL) N/A N/A for Embedded Power Stations – specified by DNO For voltages above 132 kV the Flicker Severity (short term) of 0.8 Unit and a Flicker Severity (Long Term) of 0.6 Unit for voltages of 132 kV and below, Flicker Severity *(Short Term) of 1.0 Unit and a Flicker Severity (Long Term) of 0.8 Unit, as set out in 9 > 30MW or connected at 110kV or above As per Type C A 30 – 10 MW 1 – 10 MW 400W – 1 MW Specified by the Relevant Network Operator which shall be consistent with National and International technical rules. N/S N/S Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B A 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW 1 – 10 MW 400W – 1 MW Applicable only for Direct Connections Applicable only for Direct Connections Applicable only for Direct Connections As per Type C N/S N/S The Protection Operating Times will be specified by NGET in the Bilateral Agreement but shall not be faster than:- N/A for Embedded Connections specified by DNO N/A for Embedded Connections specified by DNO The probability that the fault clearance time stated in accordance with the Bilateral Agreement will be exceeded by any given fault must be less than 2%. The Relevant Network Operator shall define the Settings necessary to protect the Network taking into account the characteristics of the Power Generating Facility. The Power Generating Facilities and Network Settings relevant to the Power Generating Facility shall be coordinated and agreed between the Network Operator and Generator as defined in Article 9 6 b) pursuant to Article 4(3). N/A for Embedded Connections Electrical protection of the Generating > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Engineering Recommendation P28 as current at the Transfer Date. N/S for Embedded Power Stations – specified by DNO. Protection Fault Clearance Times (CC.6.2.2.2.2(a) Article 9 – 6 b) and Article 9 – 6b) – 2). Synchronous and Asynchronous At 400kV:- 80ms At 275kV:- 100ms At 132kV and below:- 120ms 10 Requirement Plant Type Large Back Up Protection Requirements GB CC.6.2.2.2.2(b) ENTSO-E Article 9 – 6b) Synchronous and Asynchronous TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) specified by DNO 50 – 100MW N/A (SPT / SHETL) Applicable only to directly connected Generators Applicable only for Direct Connections Applicable only for Direct Connections N/A for Embedded Connections specified by DNO N/A for Embedded Connections – specified by DNO In the event that clearance times defined under CC.6.2.2.2.2(a) are not met, Generators are required to provide Back-up Protection. NGET will also provide back-up Protection. The two back-up protections will be co-ordinated to provide discrimination. < 50MW < 30MW (SPT) < 10 MW (SHETL) On a Generating Unit or Power Park Module where only One Main protection is provided the back up protection provided by the Generator is required to operate within 300ms. Where two main protections are provided or for directly connected 11 > 30MW or connected at 110kV or above As per Type C 30 – 10 MW Unit shall take precedence over operational controls taking into account system security, health and safety of staff and the public and mitigation of the damage to the Generating Unit in accordance with Article 9 – 6 b),2). the Relevant Network Operator shall define the Settings necessary to protect the Network taking into account the characteristics of the Power Generating Facility as per Article 9 – 6b) pursuant to the requirements of Article 4(3).. A 1 – 10 MW 400W – 1 MW N/S N/S Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Generators and Power Park Modules connected at or below 132kV the back up clearance time shall operate to give a fault clearance time of no slower than 800ms in England and Wales and 300ms in Scotland Generators and Power Park Modules shall also be required to withstand, without tripping, the loading incurred by clearance of breaker fail protection or back up protection Circuit Breaker Fail Protection CC.6.2.2.2.2(c)(d) ENTSO-E – Article 9 – 6b). Synchronous and Asynchronous N/A for Embedded Connections specified by DNO The Generator is required to provide circuit breaker fail protection for direct connections at 400 or 274kV and for direct connections in Scotland at 132 kV. In the event of a protection system failure circuit breaker fail is required to initiate tripping so as to interrupt fault current within the next 200ms. The target performance for the System Fault A 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW 1 – 10 MW 400W – 1 MW Applicable only for Direct Connections Applicable only for Direct Connections As per Type C N/S N/S N/A for Embedded Connections– specified by DNO N/Afor Embedded Connections – specified by DNO The Relevant Network Operator shall define the Settings necessary to protect the Network taking into account the characteristics of the Power Generating Facility as per Article 9 – 6b) but pursuant to the requirements of Article 4(3). 12 Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Dependability index shall be not less than 99%. Protection Equipment to be provided GB CC.6.2.2.3 ENTSO-E Article 9 – 6 b) – 3), Article 9 – 6 b) c) and d) Synchronous and Asynchronous N/A for Embedded Connections specified by DNO For direct connections the following mandatory requirements are necessary 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW As per Large for Directly connected and Embedded Plant As per Large for Directly Connected and Embedded Plant As per type C Agreed between the Network Operator and Power Generating Facility pursuant to Article 4(3). The protection systems can include the following requirements Loss of Excitation protection No busbar, mesh corner circuit breaker fail protection equipment or AC or DC wiring may be worked upon in the absence of a representative from NGET External and internal short circuit Asymmetric load (Negative Phase sequence) Stator and rotor overload Over/under excitation Over / under undervoltage at the connection point Over / under voltage at the alternator terminals Inter-area oscillations Robustness against power swings (for example angle and voltage stability Over and underfrequency Asynchronous operation (pole slip) Protection against inadmissible shaft torsions (for example In addition, the following requirements shall apply as specified by NGET in the Bilateral Agreement Protection of Interconnecting Connections Circuit Breaker Fail Pole Slipping Protection (Synchronous Plant only) Signals for Tariff Metering and the coordination of relay settings across the 13 1 – 10 MW A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Connection Point. 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW subsynchronous resonance Generating Unit line protection Unit transformer protection Backup schemes against protection and switchgear malfunction Overfluxing Inverse power Rate of change of frequency Neutral voltage displacement as per Article 9 – 6 b) 3). For Embedded Generators the requirements will be specified by the DNO at the connection point other than requirements for Pole Slipping protection and Tariff Metering Signals In addition with regard to priority ranking of protection and control the Power generating facility shall organise their protections and control devices in compliance with the following priority ranking organised in decreasing order of importance Network System and Generating Unit Protections Synthetic Inertia (if applicable) Frequency Control (Active Power adjustment) Power Restriction and Power gradient constraints as per Article 9 – 6 c). 14 1 – 10 MW A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Short Circuit Ratio GB CC.6.3.2(a) (ENTSO-E – Article 34 – 3. Reactive Capability (GB - CC.6.3.2) (ENTSO-E Synchronous – Article 11 – 2a), Article 12 – 3(a) and (b) Asynchronous Article 14-1a), Article 16 – 3(b) and (c) Synchronous 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above In the event of loss of stability of a single generating unit it shall automatically disconnect in order to support system security and prevent damage to the Generating Unit as per Article 9 – 6 – d) pursuant to the requirements of Article 4(3). As per type B A 1 – 10 MW 400W – 1 MW No less than 0.5 unless a lower value is specified by the TSO pursuant to the requirements of Article 4(3). N/S For plant of 1600MVA or greater no less than 0.4. For Plant less than 1600MVA no less than 0.5 No less than 0.5 N/A Asynchronous Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Synchronous 0.85 PF Lead to 0.95 Lag at Rated MW Output at Generator Unit Terminals As per Large N/S As per Type C 0.95 PF Lead to 0.95 PF Lag at Rated MW output. Capability to meet requirements of Fig 1 of Connection Conditions. In Scotland the reactive capability of As per Large N/A As per Type C Specified by the Relevant Network Operator at the high voltage terminals of the step up transformer at the Connection Point or at the alternator terminals if no transformer exists as per Article 11 – 2a) pursuant to the requirements of Article 4(3). As per Type A N/S Asynchronous Voltage – Q/Pmax range (at 1p.u voltage) at the Connection Point (ie the HV side of the Generator Transformer. Equates to approx 0.92 PF lead to 0.876 PF lag at Rated MW Output as specified by the TSO pursuant to Article 4(3). Voltage – Q/Pmax range (at 1p.u voltage) at the Connection Point. Equates to approx 0.97 PF lead to 0.92 PF lag at Rated MW Output as specified by the TSO. At 15 As per Type B 30 – 10 MW Specified by the Relevant DSO in accordance with Article 14 – 1a) but must be pursuant to Article 4(3). Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 0.95 Power Factor Lead to Power Factor Lag applies at the HV Side of the Connecting Transformer at 132kV, 275kV or 400kV. 50 – 100MW N/A (SPT / SHETL) Synchronous Power Output not to fall more than prorata with frequency as per Figure 2 of Connection Conditions As per Large N/A As per Type C Asynchronous As per Synchronous As per Large N/A N/S Voltage Changes in the normal operating Range (GB – CC.6.3.4 (Synchronous ENTSO-E – Article 11 – 2), Article 12 – 3(a) and (b)) Synchronous Reactive Power output under steady state conditions should be within the voltage range of 5% at 400kV, 275kV and 132 kV and lower voltages As per Large N/A As per Type C Voltage Changes in the normal operating Range (GB – CC.6.3.4 (Asynchronous Asynchronous As per Synchronous but in addition requirements for voltage and reactive power requirements As per Large N/Ae As per Type C Output Power with Falling Frequency (GB - CC.6.3.3) (ENTSO-E Synchronous – Article 12 – 2(a) and (b) Asynchronous (Not Specified) < 50MW < 30MW (SPT) < 10 MW (SHETL) 16 > 30MW or connected at 110kV or above 30 – 10 MW lower Active Power outputs the Power Park Module must operate as specified by the TSO and remain consistent to the Q/Pmax range anywhere in the operating diagram of Figure 11 pursuant to Article 4(3) Specified by TSO pursuant to Article 4(3) but within the boundaries of Below 49Hz – maximum reduction rate of 2% of maximum capability per 1Hz frequency drop below 49 Hz Below 49.5 Hz up to a maximum reduction rate of 10% of maximum capacity per 1Hz frequency drop below 49.5 Hz. N/S Generating Unit is required to meet a Voltage – Q/PMax curve as specified by the TSO pursuant to Article 4(3) at both full load (Article 12 -3(a) (1) – (2) and Article 12 3(b) at lower loads. Power Park Module is required to meet a Voltage – Q/PMax curve as specified by the TSO A 1 – 10 MW 400W – 1 MW N/S N/S N/S N/S DSO to define requirement as per Article 11- 2) pursuant to Article 4(3). N/S As per Type B. DSO to define requirement as per Article 14 -1(a) pursuant to Article 4(3). Requirement Plant Type Large ENTSO-E – Article 14 – 1(a), Article 16 - 3(b) and Article 16 – 3(c) (Asynchronous – Black Start (GB CC.6.3.5) ENTSO-E – Article 9 – 5(a) Contribution to Frequency Control by continuous Modulation of Active Power (GB – CC.6.3.6(a) ENTSO-E – Article 9 – 2(a) Contribution to Voltage Control by continuous Modulation of Reactive Power (GB – CC.6.3.6(b) ENTSO-E Article 11 – 2(a) and (b) and Article 12 - 3 Requirement for Power Station to be fitted with a Proportional Turbine Speed Governor GB – CC.6.3.7(a) ENTSO-E - Article 9 – 2(a) and Article 12 – 4(a) Requirement for Frequency Controller or TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) if Embedded and connected at 33kV and below are also specified 50 – 100MW N/A (SPT / SHETL) Synchronous and Asynchronous Specified by NGET in the Bilateral Agreement As per Large Not applicable As per Type C Synchronous Required As per Large Not applicable As per Type C pursuant to Article 4(3) at both full load (Article 16 -3(b) and Article 16 - 3(c) at lower loads. Not a mandatory requirement but specified by the TSO pursuant to Article 4(3) depending upon System Security in a Synchronous area. Required Asynchronous Required unless the Power Park Module is in Scotland and has a Registered Capacity of less than 50MW. As per Large N/A As per Synchronous Synchronous and Asynchronous Required As per Large N/A Synchronous Required Required Asynchronous Required except in relation to Power Park Modules in Scotland which have a Registered Capacity of less than 50MW Required except in relation to Power Park Modules in Synchronous and Asynchronous 400W – 1 MW N/S N/S N/S N/S As per Synchronous N/S N/S As per Type C Required as per Article 12 – 3 pursuant to Article 4(3). Required as specified by the Relevant DSO in accordance with Article 11 – 2(a) and (b) and pursuant to Article 4(3) N/S N/A As per Type C N/S N/S Required N/A As per Type C Required as per Article 9 – 2(a) pursuant to Article 4(3) and Article 12 – 4(a) Required as per Article 9 – 2(a) N/S N/S Required N/A As per Type C Required as specified in Article 9 – 2(e) pursuant to N/S N/S 17 > 30MW or connected at 110kV or above 30 – 10 MW A 1 – 10 MW < 50MW < 30MW (SPT) < 10 MW (SHETL) Requirement Plant Type Large Governor to be designed and operated to an appropriate standard / specification (GB CC.6.3.7(a)(i),(ii) ENTSO-E – Article 9 – 2(e). Requirement for the Frequency Controller or Turbine speed Governor to Control the Generating Unit or Power Park Module Active Power with stability over the entire operating range (GB CC.6.3.7 (b) ENTSO-E - Article 8 – 2 and Article 9 – 2 Ability of a Generating Unit Frequency Controller or Governor to control system frequency below 52Hz unless this causes the Generating Unit or Power Park Module to operate below its designed minimum operating level. (GB CC.6.3.7(c)(i)) (ENTSO-E – Article 9 – 5(b) Governor Droop or Frequency Control Droop (GB CC.6.3.7 (c)(ii)) ENTSO-E Article 7 TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Scotland which have a Registered Capacity of less than 50MW 50 – 100MW N/A (SPT / SHETL) Synchronous and Asynchronous Required (Not applicable to Power Park Modules in Scotland which have a Registered Capacity of less than 50MW) Required N/A As per Type C Synchronous and Asynchronous Required (Not applicable to Power Park Modules in Scotland which have a Registered Capacity of less than 50MW) Required N/A Synchronous and Asynchronous Droop Setting to be between 3 and 5% (Not applicable to Power Park Modules in Scotland Droop Setting to be between 3 and 5% N/A < 50MW < 30MW (SPT) < 10 MW (SHETL) 30 – 10 MW A 1 – 10 MW 400W – 1 MW Required as per Article 9 – 2 pursuant to Article 4(3) Required for reducing power output in steps no more than 20% of maximum capacity as specified in Article 8 – 2 pursuant to Article 4(3). N/S As per Type C Required as specified by Relevant Network Operator and TSO in accordance with Article 9 – 5(b) pursuant to Article 4(3). N/S N/S As per Type C For Plant in Frequency Sensitive Mode Droop specified by the TSO but must As per Type A Not specified for Plant in Frequency Sensitive Mode. For Plant operating in Limited > 30MW or connected at 110kV or above Article 4(3) 18 Requirement Plant Type Large – 1(c)(2) and Article 9 –2) d) - 1 – Table 3. TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) which have a Registered Capacity of less than 50MW) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW A 1 – 10 MW 400W – 1 MW be between 2 and 20% as detailed in Article 9 – 2d) –1) Table 3 Frequency Control /Governor Deadband Settings (GB CC.6.3.7(c)(iii)) ENTSO-E - Article 9 – 2)d) - 1 – Table 3 Synchronous and Asynchronous Deadband to be 0.03Hz or 0.015Hz (Not applicable to Power Park Modules in Scotland which have a Registered Capacity of less than 50MW) Deadband to be 0.03Hz or 0.015Hz N/A As per Type C For Plant in Frequency Sensitive Mode Deadband specified by the TSO but must be between 0 – 0.5 Hz as detailed in Article 9 – 2)d) – 1 - Table 3 N/S Frequency Sensitive Mode Droop is defined by the TSO but must be between the range of 2 and 12% as per Article 7 – 1(c)(2) No/S Target Frequency Settings GB CC.6.3.7 (d) ENTSO-E Article 9 – 2) d) - 8) Synchronous and Asynchronous Unit Load Controller or Power Park Module Load Controller to a Target Frequency either continuously or in a maximum of 0.05Hz steps over at least the range of 50 0.1Hz N/A As per Type C Defined by the TSO with the target frequency range set between 49.9 and 50.1 Hz as defined in Article 9 – 2) d) 8) N/S N/S Frequency Performance Requirements for Plant operating in Frequency Sensitive Mode (GB CC.6.3.7(e) and Appendix 3 of the GB Connection Conditions (ENTSO-E Article 9 - 2 d)) Synchronous and Asynchronous Unit Load Controller or Power Park Module Load Controller to a Target Frequency either continuously or in a maximum of 0.05Hz steps over at least the range of 50 0.1Hz (Not applicable to Power Park Modules in Scotland which have a Registered Capacity of less than 50MW) Generating Units and Power Park Modules must be capable of providing at least 10% of their Registered Capacity (when subject to a 0.5Hz change or greater (and proportionally for lower frequency changes)) as Primary, Secondary Generating Units and Power Park Modules must be capable of providing at least 10% of their Registered Capacity (when subject to a -0.5Hz change or greater(and proportionally for lower frequency changes)) as Primary, Secondary N/A As per Type C Parameters for frequency response performance specified by TSO in accordance with Article 9 – 2) d)– but in general these are similar to that required by the GB Grid Code. The TSO must define the parameters for minimum frequency N/S N/S 19 Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) and High Frequency Response as defined in Figures CC.A.3.1, CC.A.3.2 and CC.A.3.3 Note – Primary Response – defined as additional release of Active Power gradually increasing over the period 0 – 10 seconds and sustained for a further 20 seconds, Secondary Response – Active Power gradually released over the period 0 – 30 seconds and sustained for a further 30 minutes and High Frequency Response is the reduction in Active Power to a frequency rise which must be achievable within 10 seconds and sustainable thereafter. Synchronous Generating Unit Excitation System Requirements GB CC.6.3.8(a)(i) ENTSO-E Article 11 Synchronous (Not applicable to Asynchronous Plant) (Not applicable to Power Park Modules in Scotland which have a Registered Capacity of less than 50MW) Required to have a continuously acting automatic excitation control system to provide constant terminal voltage of 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above and High Frequency Response as defined in Figures CC.A.3.1, CC.A.3.2 and CC.A.3.3 Note – Primary Response – defined as additional release of Active Power gradually increasing over the period 0 – 10 seconds and sustained for a further 20 seconds, Secondary Response – Active Power gradually released over the period 0 – 30 seconds and sustained for a further 30 minutes and High Frequency Response is the reduction in Active Power to a frequency rise which must be achievable within 10 seconds and sustainable thereafter. As per Large 30 – 10 MW A 1 – 10 MW 400W – 1 MW Required to have a permanent automatic excitation control system in order to provide constant alternator N/S response capability as a percentage of Registered Capacity (Pmax) which is between 2 – 10%, the Initial delay time shall be less than 2 seconds (which is not covered in the GB Code) and full delivery of Active Power shall be achieved as specified by the TSO but shall be less than 30 seconds. Generating Units to be capable of providing full Active Power Frequency Response (to be specified) for a period of between 15 minutes and 30 minutes and Generators must operate between their maximum and minimum headroom See Article 9 – 2d)6). N/A 20 As per Type B As per Type B Requirement Plant Type Large – 2(b) Synchronous Generating Unit Excitation System Performance Requirements GB CC.6.3.8(a)(ii) and Appendix 6 of the Connection Conditions (ENTSO-E Article 11-2(b), Article 12 – 3(a)(5) and Article 13 – 2) b) (c), (d), (e), (f), (g) and (h) Synchronous (Not applicable to Asynchronous Plant) TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) the Synchronous Generating Unit without instability over the entire operating range 50 – 100MW N/A (SPT / SHETL) Either specified in the Bilateral Agreement if historical plant or detailed in Appendix 6 of the Connection Conditions if the Connection date is after 1 January 2009. In general the following high level requirements apply, As per Large < 50MW < 30MW (SPT) < 10 MW (SHETL) N/A i) The Excitation System shall comprise of an Excitation Source, Power System Stabiliser and Automatic Voltage Regulator ii) Steady State Voltage Control to limit the change in terminal voltage from no load to full load iii) Transient Voltage Control Performance when on open circuit with performance requirements to achieve 100% voltage being achieved within less than 0.6 seconds and the > 30MW or connected at 110kV or above In addition to the requirements of Type B and Type C (as appropriate) the following requirements apply as specified in Article 13 – 2) b), (c), (d), (e), (f), (g) and (h). In general the following high level requirements apply which shall be pursuant to Article 4(3). i) Steady State Voltage Control to limit the change in terminal voltage from no load to full load the parameters being defined by the Relevant Network Operator ii) Transient Voltage Control Performance when on open circuit with performance requirements for the time to achieve 100% voltage and the time to settle within 5% of the voltage change being specified by the Relevant 21 30 – 10 MW None other than in respect of the requirements of Type B. The Relevant Network Operator will specify what additional facilities are installed on the Synchronous Power Generating Facility in order to carry out voltage and Reactive Power control within its area as detailed in Article 12 – 3(a)(5) pursuant to Article 4(3). A 1 – 10 MW 400W – 1 MW terminal voltage without instability over the entire operating range of the synchronous Generating Unit as per Article 11 – 2(b). Not specified other than in respect of the requirement to have a automatic excitation control system as detailed in Article 11-2(b) as noted above N/S Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) time to settle within 5% of the voltage change achieved within 3 seconds. iv) Performance requirements for the Exciter rise Time will be specified by the TSO but shall generally be between 50ms and 300ms. v) Requirements for Excitation System on load Positive Ceiling Voltage will be specified by NGET but will generally be between 2 p.u and 4 p.u or Rated field voltage vi) Requirements for a negative ceiling voltage of 80% of the positive ceiling voltage if a static exciter is employed vii) Maintenance of free firing when the Generator terminals are exposed to a drop of between 20 – 30% of rated terminal voltage viii) The Excitation System (if static) should obtain a positive on load ceiling voltage of not less than 80% upon recovery of the Generating Unit following fault clearance. ix) The overall 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) 22 > 30MW or connected at 110kV or above Network Operator. iii) Requirements for Excitation System on load Positive Ceiling Voltage will be specified by the Relevant Network Operator iv) Requirements for a negative ceiling voltage if a static exciter is employed will be specified by the Relevant Network Operator v) Maintenance of free firing when the Generator terminals are exposed to a drop of 25% of rated terminal voltage vi) The Excitation System (if static) should obtain a positive on load ceiling voltage of not less than 80% upon recovery of the Generating Unit following fault clearance. vii) The overall Excitation Control System shall limit the bandwidth of the output signal so as not to cause torsional oscillations on other plant connected to the network. The Bandwidth shall be limited to 3Hz unless otherwise specified by the 30 – 10 MW 1 – 10 MW A 400W – 1 MW Requirement Plant Type Large Power Park Module Voltage Control Requirements GB – CC.6.3.8(a)(iii) Article 14 -1(a) and Article 16 –3) (e) Asynchronous (Not applicable to Synchronous Plant) TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Excitation Control System shall limit the bandwidth of the output signal so as not to cause torsional oscillations on other plant connected to the network. x) The Excitation System shall be equipped with an Under Excitation Limiter xi) The Excitation System shall be equipped with an Over Excitation Limiter. 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) Each Power Park Module is required to have a continuously acting automatic control system to control the voltage at the Connection Point without instability over the entire operating range of the Power Park Module. Any Plant or Apparatus used in the provisions of such voltage control may be located at the Power Park Unit Terminals, an intermediate bus bar of the Connection Point As per Large N/A 23 > 30MW or connected at 110kV or above TSO. viii) The Excitation System shall be equipped with an Under Excitation Limiter ix) The Excitation System shall be equipped with an Over Excitation Limiter x) Co-ordination is required between the Stator Current Limiter and Overexcitation Limiter xi) The Excitation System shall include a Power System Stabiliser if specified by the Relevant TSO. As per Type C A 30 – 10 MW 1 – 10 MW 400W – 1 MW The Power Park Module shall be capable of providing Reactive Power automatically by operation in either Voltage Control mode, Reactive Power Control Mode or Power Factor Control Mode or by a combination of two of these as defined in Article 16 –3) (e). As per type A Power Park Modules are only required to have a Reactive Power Capability at the high voltage terminals of the step up transformer to the voltage level of the Connection Point or at the alternator terminals, if no step up transformer exists as defined by the Relevant DSO as defined in Article 14 -1(a) pursuant to Article 4(3). Requirement Plant Type Large Power Park Module Voltage Control Performance Requirements GB – CC.6.3.8(a)(iv) and Appendix 7 of the Connection Conditions (ENTSO-E Article 14 -1(a) and Article 16 – 3) (e) and (f) Asynchronous (Not applicable to Synchronous Plant) TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Either specified in the Bilateral Agreement if historical plant or detailed in Appendix 7 of the Connection Conditions if the Connection date is after 1 January 2009. In general the following high level requirements apply:- 50 – 100MW N/A (SPT / SHETL) As per Large < 50MW < 30MW (SPT) < 10 MW (SHETL) N/A i) Continuous steady state voltage control is required at the Connection Point with a setpoint voltage and slope characteristic as shown in Figure CC.A.7.2.2(a) ii) The control system shall be capable of operating to a setpoint voltage of between 95% and 105% with a resolution of 0.25%. iii) The initial setpoint voltage will be 100% but NGET may specify and alternative setpoint voltage within the range of 95% to 105%. iv) The setpoint voltage should be adjustable between 95% and 105% to a tolerance of 0.25% (ie 95%, 95.25%, 95.5%...) v) The Slope setting > 30MW or connected at 110kV or above As per Type C 1 – 10 MW 400W – 1 MW In addition to the requirements of Type A (as appropriate) the following requirements apply as specified in Article 16 – 3) (e) and (f). In general the following high level requirements apply:- As per Type A Power Park Modules are only required to have a Reactive Power Capability as defined by the Relevant DSO as defined in Article 14 -1(a) and pursuant to Article 4(3). i) The Power Park Module shall be capable of contributing to voltage control at the Connection Point by provision of Reactive Power exchange with the System with a setpoint voltage covering at least 0.95 to 1.05 p.u in steps no greater than 0.01p.u with a Slope with a range of at least 2-7% in steps no greater than 0.5%. The Reactive Power output shall be zero when the Grid voltage value at the Connection Point equals the voltage setpoint. The setpoint may be operated with or without a deadband selectable in a range from 0 to +10% of nominal 24 A 30 – 10 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) should also be adjustable with a range of between 2 and 7% with a resolution of 0.5% (ie slope settings of 2, 2.5, 3.5 %... may be specified. vi) The Voltage control System should have a steady state operating range over a range of setpoint voltages (95% - 105%) and slopes 2-7% as detailed in Figures CC.A.7.2.2b and CC.a.7.2.2c (in the case of 33kV Connections or below) of Appendix 7 of the Connection Conditions. vii) If the operating point of the Power Park Module deviate so that it is no longer on the operating characteristic defined by the setpoint voltage and slope the control system shall act progressively to return the value to a point on the required characteristic within 5 seconds viii) The automatic control system should also be able to respond to 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW network voltage in steps no greater than 0.5%. ii) Following a step change in voltage 90% of the change in Reactive Power shall be achieved within 1 second and settle at the value defined by the operating slope within 5 seconds with a steady state reactive tolerance no greater than 5%. iii) For Reactive Power Control Mode the Power Park Module shall be capable of setting the Reactive Power target anywhere in the Reactive Power Range and with setting steps no greater than 5MVAr or 5% (whichever is smaller) of full Reactive Power, controlling the Reactive Power at the Connection Point to an accuracy within 5MVAr or 5% whichever is smaller of the full reactive Power. iv) For Power Factor Control, Power Factor Control shall be capable of being controlled at the Connection Point as defined by the 25 1 – 10 MW A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) transient events. ix) For an onload step change in Connection Point Voltage the reactive power output response shall commence within 0.2 seconds of the application of the step 90% of the full delivery of reactive power shall be achieved within 1 seocnd. x) Under transient conditions the Settling time shall be no greater than 2 seconds from the application of the step change in voltage and the peal to peak magnitude of any oscillations shall be less than 5% of the change in steady state Reactive Power within this time frame. xi) The Requirement for a Power System Stabiliser will be specified in the Bilateral Agreement x) The overall voltage control system shall respond to minor variations, steps, gradual changes or major variations xi) The overall voltage control system shall have a 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW Relevant DSO with Target Power Factor steps of no greater than 0.01.The Relevant Network Operator will specify the tolerance expressed in MVAr of % within a period of time following a sudden change of Active Power or step change in voltage at the Connection Point pursuant to Article 4(3). v) The Control Mode, parameter settings and operating point for steady state Reactive Power exchange at the Connection Point shall be determined by the Relevant Network Operator in co-ordination with the Relevant TSO pursuant to Article 4(3). vi) The Relevant Network Operator on co-ordination with the Relevant TSO will determine which reactive power control mode (ie Voltage Control, Reactive Power Control or Power Factor Control mode) shall apply. vii) The Relevant TSO will determine 26 1 – 10 MW A 400W – 1 MW Requirement Plant Type Large Other Reactive Power Control Modes Grid Code CC.6.3.8(a)(v) TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) limited bandwidth output of between 0 – 5 Hz. 50 – 100MW N/A (SPT / SHETL) Synchronous Reactive Power and Power Factor Control Modes (excluding VAR limiters) are not required unless specified by NGET in the Bilateral Agreement As per Large N/A As per Type B and C Asynchronous Reactive Power and Power Factor Control Modes (excluding VAR limiters) are not required unless specified by NGET in the Bilateral Agreement As per Large N/A As per Type C ENTSO-E – Synchronous Article 11 – 2(b) Article 12 –3(a) (5)Asynchronous Article 14 -1(a) Article 16 – 3(e)(6). < 50MW < 30MW (SPT) < 10 MW (SHETL) 27 > 30MW or connected at 110kV or above 30 – 10 MW if the Power Park Module is to be fitted with a Power Oscillation Damping facility (Power System Stabiliser) pursuant to Article 4(3). None other than in respect of the requirements of Type B. The Relevant Network Operator will specify what additional facilities are installed on the Synchronous Power Generating Facility in order to carry out voltage and Reactive Power control within its area as detailed in Article 12 –3(a) (5) pursuant to Article 4(3). The Relevant Network Operator on co-ordination with the Relevant TSO will determine which reactive power control mode (ie Voltage Control, Reactive Power Control or Power Factor Control mode) shall apply in accordance with Article 16 – 3)(e) (6). A 1 – 10 MW 400W – 1 MW Required to have a permanent automatic excitation control system in order to provide constant alternator terminal voltage without instability over the entire operating range of the synchronous Generating Unit as per Article 11 – 2(b). N/S As per Type A Power Park Modules are only required to have a Reactive Power Capability to provide Reactive Power at the high voltage terminals of the step up transformer to the voltage level of the Connection Point or at the alternator terminals if no step up transformer exists as defined by the Relevant DSO as defined in Article 14 -1(a) pursuant to Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW 1 – 10 MW A 400W – 1 MW Article 4(3). Steady State Load Inaccuracies GB CC.6.3.9 ENTSO-E Article 9 – 2(a)(2) Synchronous and Asynchronous Negative Phase Sequence Loadings GB CC.6.3.10 ENTSO-E Article 11 – 3(a)(5) and Article 13 – 3(a)(5) Synchronous only (Asynchronous captured under CC.6.3.15 Fault Ride Through requirements) Neutral Earthing (GB CC.6.3.11 ENTSO-E Article 9 – 6(i) Synchronous and Asynchronous Frequency Sensitive Relays (GB - CC.6.3.12 ENTSO-E Article 7 – (1)(a) and Article 1 – (b) Synchronous and Asynchronous The standard deviation of load error at steady state load over a 30 minute period must not exceed 2.5% of a Genset’s Registered Capacity. Each Synchronous Generating Unit is required to withstand without tripping the negative phase loading incurred by clearance of a close up phase to phase fault by system back up protection on the Transmission System. At nominal system voltages of 132kV and above the higher voltage windings of a transformer of a Generating Unit or Power Park Module must be star connected with the star point suitable for connection to Earth As specified in CC.6.1.3 the System Frequency could rise to 52Hz or fall to 47Hz. Each Generating Unit must continue to operate within this frequency range As per Large N/A As per Type C Specified by Relevant Network Operator under Article 9 – 2(a)(2) pursuant to Article 4(3). N/S N/S As per Large N/A Specified by the Relevant Network Operator in accordance with Article 13 – 3(a)(5) As per Type B Specified by the Relevant Network Operator in accordance with Article 11 – 3(a)(5) and pursuant to Article 4(3) N/S As per Large N/A As per Type C Specified by the Relevant Network Operator as per Article 9 – 6 (i) N/S N/S As per Large N/A As per Type A As per Type A As per Type A Tripping within the frequency and time ranges as specified in Table 2 of Article 7 – (1)(a) (which is broadly similar to the GB Frequency / time requirements) to be is prohibited 28 Requirement Plant Type Large Plant operation / protection outside the defined frequency / time operating ranges (GB CC.6.3.13 ENTSO-E Article 71(a)(2) and (3). Synchronous and Asynchronous Fast Start Capability GB CC.6.3.14 (ENTSO-E Article 9 – 5(c)) Synchronous and Asynchronous TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) for at least the time periods defined in CC.6.1.3 unless NGET has agreed within the Bilateral Agreement to any Frequency level relays or rate of change of frequency relays which will trip the Generating Unit or Power Park Module 50 – 100MW N/A (SPT / SHETL) Generating Units and Power Park Modules will be will be responsible for protecting their plant outside the range 52 – 47 Hz. Should such excursions arise it is up to the Generating Unit to disconnect their plant for the reasons of safety of plant and apparatus. NGET may specify in the Bilateral Agreement the requirement for a Genset to have a Fast Start Capability. Such Gensets may be used for Operating Reserve and be initiated by Frequency level relays in the range 49 – 50Hz As per Large N/A As per Type A As per Type A As per Type A N/A unless specified by NGET N/A As per Type C Quick resynchronisation capability is required in the case of disconnection as agreed between the Network Operator and Generator as per Article 9 – 5(c) pursuant to Article 4(3) N/S < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW 1 – 10 MW A 400W – 1 MW unless otherwise agreed by the Relevant TSO pursuant to Article 4(3) 29 A Generating Unit shall not disconnect from the Network due to rates of change of Frequency up to 2Hz/s other than by loss of mains protection as specified in Article 7 – 1(b). A Generating Unit shall be capable of automatic disconnection at specified frequencies if required by the Relevant Network Operator or as specified in the National Grid Code in accordance with Article 7 – 1(a)(2) and (3) pursuant to Article 4(3). N/S Requirement Plant Type Large Fault Ride Through for short term faults up to 140ms. (CC.6.3.15(a) and Appendix 4A of the Connection Conditions ENTSO-E Article 11-3(a)(b)) Article 13-3(a)) Synchronous TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) In GB the Fault Ride Through Requirements for Synchronous and Asynchronous Plant are broadly the same. For faults up to 140ms in duration the following high level requirements apply: 50 – 100MW N/A (SPT / SHETL) As per Large < 50MW < 30MW (SPT) < 10 MW (SHETL) N/A i) Each Generating Unit and Power Park Module shall remain transiently stable and connected to the System for any close up solid balanced or unbalanced fault operating at Supergrid Voltage (ie above 200kV) for a total fault clearance time of up to 140ms. A solid three phase fault or unbalanced earth fault may result in zero voltage on the faulted phase at the point of the fault. ii) Each Generating Unit or Power Park Module shall be designed such that upon clearance of the fault on the Transmission System and within 0.5 seconds of the restoration of the voltage at the Connection Point to 30 > 30MW or connected at 110kV or above Under ENSTO-E The Fault Ride Through requirements are segregated between Synchronous and Asynchronous Plant unlike GB. A voltage Time profile is also specified over the whole time frame unlike GB which specifies the requirement for the period between 0 – 140ms and for voltage dips after 140ms. A 30 – 10 MW 1 – 10 MW 400W – 1 MW As per Type B Under ENSTO-E The Fault Ride Through requirements are segregated between Synchronous and Asynchronous Plant unlike GB. A voltage Time profile is also specified over the whole time frame unlike GB which specifies the requirement for the period between 0 – 140ms and for voltage dips after 140ms. N/S Under the ENTSOE Code Synchronous Generators are required (as per Article 13-3(a) (pursuant to Article 4(3)) to:- Under the ENTSOE Code Synchronous Generators are required (as per Article 11-3(a)(b) (pursuant to Article 4(3)) to:- i) The TSO (pursuant to Article 4(3)) will define a voltage against time profile at the Connection Point (within the boundaries defined by Figure 7 minimum voltage at the connection point being 0 p.u for 150ms up to 250ms) under which the Synchronous Generating Unit shall stay connected and stable after the i) The TSO (pursuant to Article 4(3) will define a voltage against time profile at the Connection Point (within the boundaries defined by Figure 5 – minimum voltage at the connection point being defined by the TSO but could range between 0.3 p.u and 0.05 p.u for between 150ms and 250ms) under which the Synchronous Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) the minimum levels defined in CC.6.1.4, 90% of the pre fault Active Power generated by the Generating Unit or Power Park Module shall be restored and supplied to the System. iii) In addition during the period of the fault when the voltage is outside of nominal limits each Generating Unit or Power Park Module shall generate maximum reactive current without exceeding the transient rating of the Generating Unit or Power Park Module 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) 31 > 30MW or connected at 110kV or above power system has been disturbed by secured faults on the network (balanced and unbalanced faults) unless the protection scheme requires the disconnection of the Generating Unit from the Network. ii) The voltage against time profile shall be expressed as the lower limit of the lowest phase voltage (in the case of asymmetrical faults the lowest phase voltage shall be used irrespective of the voltage drop on the other two phases) as a function of time both during and after the fault. iii) Each TSO (pursuant to Article 4(3))will define the pre-fault and post fault conditions for fault ride through in terms of the pre fault minimum short circuit capacity at the Connection Point, the conditions for pre fault active and Reactive Power operating point of the Generating Unit at the Connection Point and Voltage at the Connection 30 – 10 MW 1 – 10 MW Generating Unit shall stay connected and stable after the power system has been disturbed by secured faults (balanced and unbalanced faults) on the network unless the protection scheme requires the disconnection of the Generating Unit from the Network ii) The voltage against time profile shall be expressed as the lower limit of the lowest phase voltage (in the case of asymmetrical faults the lowest phase voltage shall be used irrespective of the voltage drop on the other two phases) as a function of time both during and after the fault. iii) Each TSO (pursuant to Article 4(3)) will define the pre-fault and post fault conditions for fault ride through in terms of the pre fault minimum short circuit capacity at the Connection Point, the conditions for pre fault active and Reactive Power operating point of the Generating Unit A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) 32 > 30MW or connected at 110kV or above Point and conditions for the calculation of the post fault minimum short circuit capacity at the Connection Point iv) Each Network Operator(pursuant to Article 4(3) shall define the pre and post fault parameters for fault ride through capability as an outcome of the calculations at the Connection Point regarding the prefault minimum short circuit capacity at each Connection Point expressed in MVA, the pre fault operating point of the generating unit expressed in Active Power output and Reactive Power Output at the Connection Point and voltage at the Connection Point, the Post fault minimum short circuit capacity at each Connection Point expressed in MVA. iv) The Undervoltage protection on the Generating Unit should be set to the widest possible range by 30 – 10 MW 1 – 10 MW at the Connection Point and Voltage at the Connection Point and conditions for the calculation of the post fault minimum short circuit capacity at the Connection Point iv) Each Network Operator (pursuant to Article 4(3) shall define the pre and post fault parameters for fault ride through capability as an outcome of the calculations at the Connection Point regarding the prefault minimum short circuit capacity at each Connection Point expressed in MVA, the pre fault operating point of the generating unit expressed in Active Power output and Reactive Power Output at the Connection Point and voltage at the Connection Point, the Post fault minimum short circuit capacity at each Connection Point expressed in MVA. iv) The Undervoltage protection on the Generating Unit (as A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Fault Ride Through for short term faults up to 140ms. (CC.6.3.15(a) and Appendix 4A of the Connection Conditions ENTSO-E Article 15 – 3(a) (b) and Article 17-1(a) Asynchronous As per GB Synchronous Fault Ride Through requirements for short term faults up to 140ms 50 – 100MW N/A (SPT / SHETL) As per Large < 50MW < 30MW (SPT) < 10 MW (SHETL) N/A > 30MW or connected at 110kV or above theGenerator 30 – 10 MW Under the ENTSOE RfG a substantial section on Reactive Current injection has been included (Article 15 - 2 . These requirements are captured below,. As per Type B Under the ENTSOE RfG Power Park Modules are required(as per Article 171(a)(pursuant to Article 4(3)) to:i) The TSO (pursuant to Article 4(3)) will define a voltage against time 33 1 – 10 MW A 400W – 1 MW set by the Generator) should be set to the widest possible range v) The Relevant TSO (pursuant to Article 4(3)) will specify the requirements for 90% of the Active Power to be restored on fault clearance measured from the time the voltage has recovered above 85% of the pre-fault nominal voltage value. The maximum recovery period shall be greater than 0.5 seconds and less than 15 seconds. Under the ENTSOE RfG a substantial section on Reactive Current injection has been included (Article 15 - 2 . These requirements are captured below, . Under the ENTSOE RfG Power Park Modules are required(as per Article 15-3(a) and (b) (pursuant to Article 4(3)) to:i) The TSO (pursuant to Article 4(3)) will define a N/S Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) 34 > 30MW or connected at 110kV or above profile at the Connection Point (within the boundaries defined by Figure 12 – minimum voltage at the connection point being between 0 p.u voltage for between 150ms up to 250ms) under which the Power Park Module shall stay connected and stable after the power system has been disturbed by secured faults (balanced and unbalanced faults) on the network unless the protection scheme requires the disconnection of the Power Park Module from the Network. ii) The voltage against time profile shall be expressed as the lower limit of the lowest phase voltage (in the case of asymmetrical faults the lowest phase voltage shall be used irrespective of the voltage drop on the other two phases) as a function of time both during and after the fault. iii) Each TSO(pursuant to Article 4(3)) will 30 – 10 MW 1 – 10 MW voltage against time profile at the Connection Point (within the boundaries defined by Figure 9 – minimum voltage at the connection point being between 0.15 p.u - 0.05 p.u for up to 400ms) under which the Power Park Module shall stay connected and stable after the power system has been disturbed by secured faults (balanced and unbalanced faults) on the network unless the protection scheme requires the disconnection of the Power Park Module from the Network. ii) The voltage against time profile shall be expressed as the lower limit of the lowest phase voltage (in the case of asymmetrical faults the lowest phase voltage shall be used irrespective of the voltage drop on the other two phases) as a function of time both during and after the fault. iii) Each TSO (pursuant to Article 4(3)) will define the A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) 35 > 30MW or connected at 110kV or above define the pre-fault and post fault conditions for fault ride through in terms of the pre fault minimum short circuit capacity at the Connection Point, the conditions for pre fault active and Reactive Power operating point of the Power Park Module at the Connection Point and Voltage at the Connection Point and conditions for the calculation of the post fault minimum short circuit capacity at the Connection Point iv) Each Network Operator (pursuant to Article 4(3)) shall define the pre and post fault parameters for fault ride through as an outcome of the calculations at the Connection Point regarding the prefault minimum short circuit capacity at each Connection Point expressed in MVA, the pre fault operating point of the Power Park Module expressed in Active Power output and Reactive Power Output at the 30 – 10 MW 1 – 10 MW pre-fault and post fault conditions for fault ride through in terms of the pre fault minimum short circuit capacity at the Connection Point, the conditions for pre fault active and Reactive Power operating point of the Power Park Module at the Connection Point and Voltage at the Connection Point and conditions for the calculation of the post fault minimum short circuit capacity at the Connection Point iv) Each Network Operator (pursuant to Article 4(3)) shall define the pre and post fault parameters for fault ride through as an outcome of the calculations at the Connection Point regarding the prefault minimum short circuit capacity at each Connection Point expressed in MVA, the pre fault operating point of the Power Park Module expressed in Active Power output and Reactive Power Output at the Connection Point A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Fault Ride Through for long term faults greater than 140ms. (CC.6.3.15(b) and Appendix 4A of the Connection Conditions ENTSO-E Article 11-3I(a)(b), Article Synchronous and Asynchronous 50 – 100MW N/A (SPT / SHETL) As per Large < 50MW < 30MW (SPT) < 10 MW (SHETL) N/A In addition to the fault ride through requirements for short duration faults (CC.6.3.15(a) each Generating Unit and Power Park Module is required to:- 36 > 30MW or connected at 110kV or above Connection Point and voltage at the Connection Point, the Post fault minimum short circuit capacity at each Connection Point expressed in MVA. iv) The Undervoltage protection on the Power Park Module should be set to the widest possible range by the Generator. 30 – 10 MW Under the ENTSOE RfG no distinction is made between short and long duration faults see Article 11 – 3(a)(b), Article 13-3(a) Article 17-1(a) and Article 15-3(a) (b). As per Type B 1 – 10 MW A 400W – 1 MW and voltage at the Connection Point, the Post fault minimum short circuit capacity at each Connection Point expressed in MVA. iv) The Undervoltage protection on the Power Park Module should be set to the widest possible range by the Generator. v) The Relevant TSO (pursuant to Article 4(3)) will specify the requirements for 90% of the Active Power to be restored on fault clearance measured from the time the voltage has recovered above 85% of the pre-fault nominal voltage value. The maximum recovery period shall be greater than 0.5 seconds and less than 10 seconds. Under the ENTSOE RfG no distinction is made between short and long duration faults See Article 11-3(a)(b) and Article 15-3(a) (b). The Reactive injection during N/S Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 13-3(a), Article 15 – 3(a) (b) and Article 17-1(a) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) i) Remain transiently stable and connected to the System without tripping for any Balanced Supergrid Voltage dips anywhere on or above the heavy black line of Figure 5 defined under CC.6.3.15(b). ii) Provide Active Power output at least in proportion to the retained balanced voltage at the Connection Point allowing for a reduction in the power output of a Power Park Module where the primary energy source has reduced iii) Generate maximum reactive current without exceeding the transient rating of the Generating Unit or Power Park Module during the period of the voltage dip iv) Restore Active Power output to at least 90% of its pre fault output (unless there has been a reduction in the 37 > 30MW or connected at 110kV or above The Reactive injection during system faults and disturbances for Power Park Modules is covered under Article 15 -2. 30 – 10 MW 1 – 10 MW system faults and disturbances for Power Park Modules is covered under Article 15 -2. A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) primary energy source to the Power Park Module) within 1 second of restoration of the voltage at the Connection Point. Fault Ride Through – Other Requirements Operation under high wind speed or emergency shutdown conditions (GB CC.6.3.15.3(i) ENTSO-E – Article 17-1(a) or Article 15-(3) Asynchronous Fault Ride Through – Other Requirements Negative Phase sequence loading CC.6.3.15.3(ii) ENTSO-E – Article 17-1(a) or Article 15-3). Asynchronous Reactive Current Injection during System faults and Disturbances Synchronous A 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW 1 – 10 MW 400W – 1 MW As per Large N/A Not explicitly specified but could be within the framework of Article 17-1(a) by being specified by the Relevant TSO pursuant to Article 4(3). As per Type C Not explicitly specified but could be within the framework of Article 15-(3) by being specified by the Relevant TSO pursuant to Article 4(3). N/S As per Large N/A Specified by the Relevant Network Operator (pursuant to Article 4(3)) in accordance with Article 17 – 1(a) As per Type C Specified by the Relevant Network Operator (pursuant to Article 4(3)) in accordance with Article 15 – 3. N/S As per Large N/A N/S N/S N/S N/S For Power Park Modules comprising of wind turbine generating units the fault ride through requirements do not apply when the wind farm is operating at less than 5% of Rated MW output or when 50 % or more of the wind turbines have been shut down due to emergency shut down sequence. Each Power Park Module must be able 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 Transmission System operating at Supergrid Voltage. Maximum Reactive Current to be injected during the 38 Requirement Plant Type Large CC.6.3.15 Article 15-2 TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) period of the fault without exceeding the Transient Rating of the Generating Unit as specified in CC.6.3.15. 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) As per Large N/A Maximum Reactive Current to be injected during the period of the fault without exceeding the Transient Rating of the Generating Unit as specified in CC.6.3.15. > 30MW or connected at 110kV or above 30 – 10 MW 400W – 1 MW Under the ENSO-E Code a specific new section has been included for Power Park Modules relating to reactive current injection during system faults. These are specified under Article 15 – 2. The requirements include:- N/S For a symmetrical three phase fault a Type B Power Park Module is required to i) Inject fast acting reactive current into the network at the Connection Point at no less than the red line shown in Figure 8 of Article 152(a)(1). ii) As a minimum the reactive current supplied at the Power Park Module terminals shall contribute at least 2% of the rated current per percent of voltage deviation. iii) The Power Park Module shall be capable of feeding 39 A 1 – 10 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW 1 – 10 MW the required reactive current no later than 40ms after fault inception allowing the voltage to be measured at each Power Park Units terminals. iv) The relevant Network Operator (pursuant to Article 4(3)) shall define in co-ordination with relevant TSO the parameter settings for the fast acting reactive current injection. v) If required the reactive current supply during the fault duration shall not be less than 1p.u of the short term dynamic rating of the equipment (>=1.0p.u) between 50% and 40% retained voltage (respectively in the case of a voltage drop between 50% and 60%) at the Connection Point. Below 40% retained voltage reactive current shall be supplied as far as technically feasible. vi) In the case of unbalanced faults the Relevant Network Operator in co-ordination with the Relevant TSO will specify the 40 A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Operational Intertripping (GB CC.6.3.17) ENTSO-E – Article 7 – 1(d) Synchronous and Asynchronous 50 – 100MW N/A (SPT / SHETL) As per Large < 50MW < 30MW (SPT) < 10 MW (SHETL) Not applicable Specified by NGET in the Bilateral Agreement depending upon whether this is required for thermal, voltage or stability reasons. 41 > 30MW or connected at 110kV or above As per Type A 30 – 10 MW 1 – 10 MW As per Type A Reactive Current injection requirements pursuant to Article 4(3) vii) If a Power Park Module fails to provide the reactive support necessary then if required by the Relevant TSO the Power Park Module causing the Network Disturbance shall be disconnected from the Network after 0.5 seconds if the positive phase sequence voltage at the connection point falls and remains at a value of 85% or below the reference voltage (based on the highest phase voltage) and a resetting ratio of 0.98 and at the same time the direction of the Reactive Power at the connection point is reversed (ie into the Power Park Module). As per Type A A 400W – 1 MW Defined by Relevant Network Operator As per Article 7 – 1d) pursuant to Article 4(3). Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Control Telephony and System Telephony GB CC.6.5.2 ENTSO-E Article 8 4(b), Article 9 – 2(a) and Article 9 – 5(2). Synchronous and Asynchronous Control Telephony is a dedicated telephony service with a high level of redundancy and resilience and System Telephony is based on the standard Public Telephone Provider (BT) Control Telephony is required for all Large Power Stations. If NGET consider Control telephony is not practicable then NGET will specify the use of System Telephony in the Bilateral Agreement Operational Metering (GB CC.6.5.6 and CC.6.4.4 ENTSO-E Article 8 – 4(b). Synchronous and Asynchronous Instructor Facilities including Fax Machines CC.6.5.7, CC.6.5.8 and CC.6.5.9 Synchronous and Asynchronous Generator to provide signals required by NGET in accordance with the terms of the Bilateral Agreement and NGET will then provide the communications routes to access the signals at the Transmission Interface Point as specified in the Bilateral Agreement All BM Participants must have appropriate electronic data 50 – 100MW N/A (SPT / SHETL) A 1 – 10 MW 400W – 1 MW Control telephony is not specifically defined but is required in the context of instructions and communications facilities (Article 8 – 4(b)) and in respect of frequency stability and Black Start as defined in Article 9 – 2(a) and Article 9 – 5(2) pursuant to Article 4(3). N/S N/S Only required for directly connected Medium Power Stations. For those Medium Power Stations which are Embedded and SVA registered there is no requirement for Control or System Telephony For those Small Power Stations which are Embedded and SVA registered there is no requirement for Control or System Telephony For those Medium Power Stations which are CVA Registered and BM Participants there is a requirement for Control or System Telephony For those Small Power Stations which are CVA Registered and BM Participants there is a requirement for Control or System Telephony As specified by NGET in accordance with CC.6.5.6 and CC.6.4.4 N/A As per Type B As per Type B Specified by the Relevant Network Operator and Relevant TSO in accordance with Article 8 – 4(b) N/S As per Large- Note the reference to BM Participants which has implications as to whether the plant N/A As per type C Instructor Facilities are not specifically defined but equivalent facilities are required under N/S N/S 42 > 30MW or connected at 110kV or above 30 – 10 MW < 50MW < 30MW (SPT) < 10 MW (SHETL) Only required for directly connected Small Power Stations. Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) communication facilities to permit the submission of data as required by the Grid Code (EDT). In addition any Party that provides all Type 1 Ancillary Services and is a BM Participant shall be required to automatic logging facilities if they have a completion date after 1 January 2013. ENTSO-E Article 84(b), Article 9 – 2(a) and Article 9 – 5(2) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW A 1 – 10 MW 400W – 1 MW N/S N/S Article 8 – 4(b)) and in the context of instructions and communications facilities in respect of frequency stability and Black Start are required as defined in Article 9 – 2(a) and Article 9 – 5(2). is SVA or CVA registered. Each Generator is required to install a Fax Machine Dynamic System Monitoring, Quality of Supply Monitoring and Ancillary Services Monitoring GB CC.6.5.6, CC.6.1.6 and OC 5.4.1 (c) ENTSO-E Article 9 – 6) (e), Article 9 – (6)(j) and Article 9 – 2(g). Synchronous and Asynchronous The requirements for Dynamic System Monitoring are specified by NGET in the Bilateral Agreement As per Large – Note however some of these requirements vary depending on whether the Plant is SVA or CVA Registered. Not specified Note requirements for Ancillary Services Monitoring and Quality of Supply Monitoring are also defined by NGET in the Bilateral Agreement 43 As per Type C For Dynamic System monitoring, Fault Recording and Quality of Supply Monitoring the requirements are defined Article 9 – 6)(e) and Article 96)(j). The signals required shall include Voltage, Active Power, Reactive Power, Frequency and Harmonics. The Relevant Network Operator (pursuant to Article 4(3)) shall have the right to add other quality of supply parameters provided reasonable notice is given. The settings, triggering parameters, Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW interfacing arrangements and data submission of the monitoring / fault recording equipment shall be agreed with the Relevant Network Operator and TSO pursuant to Article 4(3)). For Frequency Response monitoring (Ie Ancillary Services Modelling in GB terms) the requirements are defined under Article 9 – 2)(g) The Network Operator and TSO can request the following signals Status signal of frequency sensitive mode Scheduled Active Power output Actual value of Active Power output Actual set point value fro frequency response Droop and deadband and for Power Park Modules available power reflecting maximum unrestricted power taking into account variable source of primary power – ie 44 1 – 10 MW A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW A 1 – 10 MW 400W – 1 MW wind or solar. Safety Related Conditions CC.7 Synchronous and Asynchronous Ancillary Services CC.8 Synchronous and Asynchronous As per Large As per Large N/S N/S N/S N/S As per Large except in the case of Licence Exempt Embedded Medium Power Stations where they are not applicable N/A Specified through the obligations on Type D Units (including the specific requirements for Synchronous Generating Units and Power Park Modules Specified through the obligations on Type C Units (including the specific requirements for Synchronous Generating Units and Power Park Modules Specified through the obligations on Type B Units (including the specific requirements for Synchronous Generating Units and Power Park Modules Specified through the obligations on Type A Units (including the specific requirements for Synchronous Generating Units and Power Park Modules Captured under CC.7 and applies to directly Connected Plant Defines the Mandatory Ancillary Services (Part I) and (Part II) that Generators are required to provide. For Part 1 Ancillary Services (Frequency response – in general required from Large Power Stations except those which are less than 50MW and comprise Power Park Modules and Reactive Capability required from Large and Medium Power Stations. In terms of Part II Ancillary Services such as Frequency Control, Black Start and Operational intertripping these are defined by NGET in the Bilateral Agreement. Commercial Ancillary Services are those over and 45 Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) above the minimum requirements which are agreed by NGET and the User and dealt with under the terms of the Ancillary Services Agreement Performance when operating in Frequency Sensitive Mode for Over Frequencies (BC.3.7.1 Performance when operating in Limited Frequency Sensitive Mode for Over frequencies (BC.3.7.2 and Article 7 - 1(c). Synchronous and Asynchronous Synchronous and Asynchronous Requires all Large Generating units that are obliged to meet the requirements of the Balancing Codes to automatically deload at a rate of at least 2 percent of output per 0.1 Hz deviation of System Frequencies above 50.5 Hz. Requires all Large Generating units that are obliged to meet the requirements of the Balancing Codes to automatically deload at a rate of at least 2 percent of output per 0.1 Hz deviation of System Frequencies above 50.4 Hz. A 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW 1 – 10 MW 400W – 1 MW Required only if the Medium Power Station is required to meet the requirements of the Balancing Codes N/A As per Type C The Generating Unit shall be capable of providing Active Power Frequency Response with respect to Figure 3 of Article 9 – 2(d). N/S N/S As per Type A Each Generating Unit shall be capable of activating Active Power Frequency Response at according to Figure 1 defined in Article 7 – 1(c). The Generating unit shall in Limited frequency Sensitive Mode overfrequency be capable of activating Active Power Frequency Response at a The Frequency Performance requirements when the Plant is operating in Frequency Sensitive Mode for under frequencies are detailed in Article 9 – 2 (d) as defined above. Required if the Medium Power Station is only required to meet the requirements of the Balancing Codes Not applicable 46 As per Type A As per Type A Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Performance when operating in Limited Frequency Sensitive Mode for under frequencies ENTSO-E Article 9 – 2)(c) Synchronous and Asynchronous 50 – 100MW N/A (SPT / SHETL) Not required < 50MW < 30MW (SPT) < 10 MW (SHETL) Not required Not required 47 > 30MW or connected at 110kV or above As per Type C 30 – 10 MW Each Generating Unit shall be capable of providing Active Power Frequency Sensitive Mode – Under Frequency (LFSMU) in accordance with Figure 2 as defined in Article 9 – 2)(c)(1). The Generating Unit shall in the LFSM-U A 1 – 10 MW 400W – 1 MW N/S frequency threshold between and including 50.2Hz and 50.5Hz with a droop in a range of 2 – 12 %. The actual Frequency threshold and droop settings shall be determined by the Relevant TSO. The Active Power Frequency Response shall be activated as fast as technically feasible with an initial delay that shall be as short as possible and reasonably justified if greater than 2 seconds. Stable operation of the Generating Unit during LFSM-O shall be ensured. Any contradiction between LFSM-O speed Control and Power Control during LFSM-O operation shall be avoided. N/S Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW mode be capable of activating Active Power Frequency Response at a frequency threshold between 49.8Hz and 49.5 Hz with a droop in a range of 2 – 12% by providing a power increase up to its maximum capacity taking account of limitations for some generation technologies from operation near maximum capacity at low frequencies. The Active Power Frequency Response shall be as fast as technically feasible with an initial delay that shall be as short as possible and reasonably justified if greater than 2 seconds. Stable operation of the Generating Unit during LFSM – U operation shall be ensured. Any contraction between power and speed control during Limited Frequency Sensitive Mode (underfrequency) shall be prohibited. When in LFSM-U operation the Generating Unit will also simultaneously 48 1 – 10 MW A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Compliance ENTSO-E – Articles 24 - 51 Synchronous 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above A 30 – 10 MW 1 – 10 MW 400W – 1 MW Covered under Articles 24 – 51 as applicable Covered under Articles 24 – 51 as applicable As per Large N/A Covered under Articles 24 – 51 as applicable be in LFSM-O Mode. Covered under Articles 24 – 51 as applicable As per Large N/A Covered under Articles 24 – 51 as applicable Covered under Articles 24 – 51 as applicable Covered under Articles 24 – 51 as applicable Covered under Articles 24 – 51 as applicable As per Large As per Large As per Type C Each Network Operator in coordination with the relevant TSO (pursuant to Article 4(3) shall have the right to require simulation models N/S N/S Work is currently underway to include Compliance issues in the Grid Code. At the present time the requirements are defined in Guidance notes for Synchronous Generators, issue 11 which is available from NGET’s website. Re testing is captured under OC 5 Compliance ENTSO-E – Articles 24 - 51 Asynchronous Work is currently underway to include Compliance issues in the Grid Code. At the present time the requirements are defined in Guidance notes for Power Park Developers, issue 2 which is available from NGET’s website. Re testing is captured under OC 5 Data / Models GB Planning Code Article 9 – 6(f). Synchronous and Asynchronous Detailed Modelling Data is required under different time phases under the Grid Code Planning Code depending 49 Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) upon the type of plant and whether or not it is a Large Medium or Small Generator. There is no requirement for model data to be submitted under the Connection Conditions 50 – 100MW N/A (SPT / SHETL) < 50MW < 30MW (SPT) < 10 MW (SHETL) > 30MW or connected at 110kV or above 30 – 10 MW that shall reflect the behaviour of the Generating Unit in both steady state and dynamic simulations and where appropriate and justified electromagnetic transient simulations. The requirement for simulation models shall include the format in which they shall be provided and the documentation of structure and block diagrams for the purpose of verification of the requirements of this Network Code and for the use in all studies for continuous evaluation in system planning and operation. For the purpose of dynamic simulations the model provided shall contain the following submodels Alternator and prime mover Speed and power control Voltage control including PSS and excitation system and limiters 50 1 – 10 MW A 400W – 1 MW Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Synchronisation In GB covered under the site specific Bilateral Agreement under Appendix F3 and Relevant Electrical Standards). (ENTSO-E – Article 9 – 6(a)) Synchronous and Asynchronous 50 – 100MW N/A (SPT / SHETL) As per Large < 50MW < 30MW (SPT) < 10 MW (SHETL) As per Large For directly connected plant specified in the site specific Bilateral Agreement and referenced in the Relevant Electrical Standards N/A for Embedded Plant 51 > 30MW or connected at 110kV or above As per Type C 30 – 10 MW Generating Unit protection models as agreed with the relevant Network Operator and Power Generating Facility (pursuant to Article 4(3)) Converter Models for Power Park Modules The Relevant Network Operator or Relevant TSO (pursuant to Article 4(3)) shall have the right to require Generating Unit recordings in order to compare the response of the model with these recordings. Generating Unit synchronisation shall be performed by the Power Generating facility owner equipped with the necessary synchronisation facilities. The Generating Unit shall be equipped with the necessary synchronisation facilities. Synchronisation of Generating Units shall be possible for frequencies within the ranges specified in Table 2. The Network Operator and the Power Generating Facility A 1 – 10 MW 400W – 1 MW N/S N/S Requirement Plant Type Large TABLE 2 – GB Grid Code Comparison to ENTSO-E RfG GB Power Station Type ENTSO-E RfG– Generating Unit Type Medium Small D C B > 100 MW (E&W) > 30 MW (SPT) > 10 MW (SHETL) Auto Reclosure GB – Not specified ENTSO-E Article 9 – 4(c) Synchronous and Asynchronous 50 – 100MW N/A (SPT / SHETL) Not specified < 50MW < 30MW (SPT) < 10 MW (SHETL) Not specified Not specified 52 > 30MW or connected at 110kV or above As per Type C 30 – 10 MW Owner shall agree on the settings of synchronisation devices to be concluded prior to operation of the Generating Unit. This agreement shall cover the following matters: voltage, frequency, phase angle range, phase sequence, deviation of voltage and frequency as specified in Article 9 – 6(a) pursuant to Article 4(3). Relevant Network Operators have the right (Pursuant to Article 4(3)) to request single phase autoreclosure on Generating Unit supply lines (radial connection of one or more Generating Units to the public network) and single phase or three phase auto reclosures on meshed Network lines to be withstood by Generating Units without tripping. If the first autoreclosure attempt is not successful, a subsequent attempt will be delayed by at least 3 seconds. 1 – 10 MW A 400W – 1 MW COMPARISION OF OFFSHORE REQUIREMENTS (Comparison based on GB Grid Code Issue 4 Revision 9 only and ENSTO - E RFG Internal Version dated 24 January 2012) (Note – Does not include other Industry Codes such as the STC) Key to Table Symbol N/A N/S Article 4(3) Offshore Power Park Modules TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE Definition Not specified in GB Grid Code but other requirements may apply in other industry Codes such as the System Operator Transmission Owner Code (STC) Distribution Code or Engineering Recommendations such as G59, ETR 113 and G83. Not specified in ENTSO-E RfG Code often because not deemed to be a cross border issue but other National requirements may apply. Where reference in the Table is given to Article 4(3) this means that any decision made by a Relevant Network Operator, or Relevant TSO and a Relevant Network Operator or Power Generator may require agreement with the National Regulating Authority. NOTE:- The same grading thresholds applies to Offshore Power Park Modules as Onshore Generating Units and Onshore Power Park Modules. To simplify the Offshore Table and reduce complexity the Type has been explicitly defined. Offshore Power Park Modules are required to meet those requirements applicable to Offshore Power Park Modules but the following should be noted:Type A Offshore Power Park Module:- 400W – 1MW Type B Offshore Power Park Module:- 1MW – 10MW Type C Offshore Power Park Module:- 10MW – 30MW Type D Offshore Power Park Module:- 30 MW or Greater or Connected at 110kV or more Type D units are required to meet the full requirements of Type A, B and C Units, Type C units are required to meet the requirements of Type A and B and Type B units are required to meet the requirements of Type A except where the following Exclusions noted below apply. Exculsions Type C Offshore Power Park Modules are required to meet the requirements applicable to Type A and B Units defined in Articles 7 and 8 except for Article 7(1)(d)(facilitation of a logic interface signal to permit disconnection from the network or additional facilities pursuant to Article 4(3)), Article 8(2)(a) (Capability to reduce Active Power in steps not bigger than 20% of Maximum Capacity through an interface and the requirements applicable to Type A Onshore Power Park Modules). For Type C Units, more stringent requirements are specified. Type D Units are required to meet the requirements of types A, B and C Units defined in Articles 7, 8 and 9 except Article 7(1)(d) (facilitation of a logic interface signal to permit disconnection from the network or additional facilities pursuant to Article 4(3)), Article 8(2)(a) (Capability to reduce Active Power in steps not bigger than 20% of Maximum Capacity through an interface), Article 9(3)(a) (Generating Units to be capable of automatic disconnection at specified voltages if required by the Network Operator with the settings pursuant to Article 4(3)) and the requirements applicable to Type A Onshore Power Park Modules. 53 Requirement Large Definitions and Scope TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW Any Generating Plant which is connected to an Offshore Transmission System at an Offshore Grid Entry Point is required to satisfy the Offshore Grid Code requirements. In general the Offshore Grid Code requirements are the same as the Onshore Grid Code requirements unless otherwise stated in this table below. An Offshore Transmission System is one which is owned under Licence by an appointed Offshore Transmission Licensee and comprises high voltage electric lines or cables of 132 kV or above between an Offshore Platform and the Shore. The Offshore Transmission System is classified as part of the National Electricity Transmission System being Controlled by National Grid as System Operator but the actual Offshore Transmission Network is owned and maintained by an appointed Offshore Transmission Licensee. < 10MW As per Large except, the connection requirements as detailed under CC.6.3 of the GB Grid Code connection conditions such as reactive capability(CC.6.3.2), output power with falling frequency (CC.6.3.3), active power output and voltage range(CC.6.3.4), black start (CC.6.3.5), frequency control (CC.6.3.6, CC.6.3.7), voltage control (CC.6.3.6, CC.6.3.8), steady state load inaccuracies (CC.6.3.9), negative phase sequence loadings (CC.3.10), neutral earthing (CC.6.3.11), frequency sensitive relays (CC.6.3.12 – CC.6.3.13), fast start (CC.6.3.14) and fault ride through (CC.6.3.15) are not required. The ENTSO-E RfG applies only to Offshore Power Park Modules only. A Power Park Module located Offshore which does not have an Offshore Connection Point shall be considered as an Onshore Power Park Module and shall thus be compliant with the requirements defined above for Onshore Power Park Modules. The Offshore Connection Point of an Offshore Power Park Module shall be defined pursuant to Article 4(3). An Offshore Power Park Module may comprise of one or more Generating Units. All associated auxiliary system and secondary equipments shall be considered as parts of the Offshore Power Park Module. Under the ENTSO-E RfG the Offshore Power Park Modules are categorised in accordance with the following Offshore Grid Connection System Configurations. 1) Configuration 1 – AC connection to single onshore point - One or more Offshore Power Park Modules are interconnected offshore to form an Offshore AC System. The Offshore AC System is connected to the Onshore System with one or more AC connection(s) to the same Onshore Grid Interconnection Point. The Offshore Generator will be required to satisfy technical connection requirements under the Grid Code where as the Offshore Transmission Licensee will be required to satisfy connection requirements under the System Operator Transmission Owner Code (STC). 2) Configuration 2 - Meshed AC connection - A number of Offshore Power Park Modules are interconnected offshore to form an Offshore AC System. The Offshore AC System is connected to the Onshore System at two or more Onshore Grid Interconnection Point locations. 3) Configuration 3 - DC connection to single onshore point with AC collection One or more Offshore Power Park Modules are interconnected offshore to form an Offshore AC System. The Offshore AC System is connected to the Onshore System with one or more DC connections at one Onshore Grid Interconnection Point location. The point of connection between an Offshore Generator and Offshore Transmission Licensee is defined as the Offshore Grid Entry Point whereas the point of Connection between an Offshore Transmission Licensee and Onshore Transmission Licensee is defined as the Interface Point. When the Offshore Transmission Grid Code was prepared in 2008/2009, it generally assumed the Offshore Transmission System to comprise of radial HVAC or HVDC connections of 132kV or above. There have been some applications in the last few years where there has been interconnection between Offshore Platforms and Offshore Transmission Interface Points. However, as Offshore Transmission Systems start to evolve and 54 4) Configuration 4 - Meshed Hybrid AC and DC connections with AC collection A number of Offshore Power Park Modules are interconnected offshore to form an Offshore AC System. The Offshore AC System is connected to the Onshore System with AC and DC connections at two or more Onshore Grid Interconnection Point locations. 5) Configuration 5 - Meshed Multiterminal DC connection with AC Collection - A number of Offshore Power Park Modules are interconnected offshore to form an Offshore AC System. The Offshore AC System is connected to the Onshore System with multiple DC connections at two or more Onshore Grid Interconnection Point locations. The DC connections may be combined in a multi-terminal system and may also have a connection to an offshore system of another country. Requirement Large TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW become increasingly integrated, there will be an increasing requirement to update and amend the Offshore Grid Code and STC requirements < 10MW 6) The Offshore Grid Code requirements will apply to all types of plant which connect to an Offshore Grid Entry Point irrespective of whether they are Synchronous or Asynchronous. The requirements applicable to asynchronous plant not only apply to wind generation but other technologies such as wave and tidal generation. Configuration 6 - Meshed DC connection with DC Collection - An Offshore Power Park Module consisting of DC Generating Units and DC collection network. The Offshore Power Park Module connected by DC to an Offshore DC System. The Offshore DC connection is connected to the Onshore system with one or more DC link(s). NOTE:- A further Connection Procedures Code (ie detailing the Connection Process) is planned at a later stage. The Florence forum has decided that the Connection Procedures Code is of lower priority and will be implemented post 2015. The connection process under the Offshore Transmission regime can progress in two ways. 1) The Enduring process in which an Offshore Generator will apply to the System Operator (National Grid) for a connection. National Grid will then prepare an indicative offer to the generator based on a number of assumptions including the Interface Point and Onshore Network reinforcements. A Tender process will then take place which seeks to encourage a number of potential Offshore Transmission Licensee’s (OFTO) to design an Offshore Transmission System. The Regulator (Ofgem), will then select the preferred OFTO based on their ability to design, build and construct an Offshore Transmission Network to appropriate standards and provide value for money. The OFTO is then appointed, agreements between the OFTO and National Grid are prepared and the initial connection offer to the Offshore Generator is revised based on the requirements of the OFTO and the design of the Offshore Transmission network. Construction can then commence but it should be noted that a draw back of this option is the potential delays to the Offshore Generator whilst the Offshore Transmission Tender process is proceeding. 55 Requirement Large TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW 2) An alternative to this process is the Generator Build option. Under this arrangement the Offshore Generator will design and build the Offshore Transmission System as well as the Offshore Generation. Once the Offshore Transmission System has been constructed the Offshore Transmission element will be sold to an appointed Offshore Transmission License. The advantage to the Offshore Generator over the above option is that there is no delay to the Offshore Generator whilst Tender process is taking place. < 10MW Where a Generator is not connected to an Offshore Transmission Network (ie the Offshore Transmission Network contains undersea cables or overhead lines of no greater than 132 kV) then the Offshore network is considered to comprise solely of Generator assets and the Generator is treated in the same way as an Onshore Power Park Module. Frequency Stability GB CC.6.1.3, CC.6.3.6(a), CC.6.3.7, CC.6.3.9, CC.6.3.12, CC.6.3.13, BC.3.7.1 and BC.3.7.2 (ENTSO-E – Article 19 The requirements for Offshore Power Park Modules are the same as Onshore Power Park Modules in respect of frequency range (CC.6.1.3), Frequency Control (both in Frequency Sensitive and Limited Frequency Sensitive Mode) (CC.6.3.6(a)/CC.6.3.7, Steady State load inaccuracies (CC.6.3.9) frequency sensitive relays (CC.6.3.12 and CC.6.3.13) and frequency performance under high frequencies when operating above 50.5Hz (Frequency Sensitive Mode BC.3.7.1) and when operating above 50.4Hz (Limited Frequency Sensitive Mode BC.3.7.2) Not applicable Frequency Stability Type B Offshore Power Park Modules The frequency stability requirements defined in Article 8(2)(a) (Reduction of Active Power in steps not greater than 20%) shall apply to any Offshore Power Park Module irrespective of its configuration. Type C and D Offshore Power Park Modules In addition to the requirements of Type B Offshore Power Park Modules, Type C and D Offshore Power Park Modules are also required to satisfy the Frequency stability requirements defined in Article 9(2) (a) (Active Power Set Point control / Steady State Load inaccuracies) Article 9(2)(b), (Synthetic Inertia), Article 9(2)(e) (frequency restoration), Article 9(2)(g) (real time frequency monitoring) irrespective of the Offshore Power Park Module configuration. Frequency Ranges Type A, B, C and D Offshore Power Park Modules The Frequency ranges as defined in Article 7(1) (a) (as per onshore) shall apply to Offshore Power Park Modules of Configurations 1, 2 and 4. For Configuration 3 and 5 in anticipation to temporarily extreme system disturbances, such as transient oscillations or HVDC Controller failures, wider frequency ranges may apply in the range 46.5Hz to 53Hz for at most 10 seconds. The precise frequency ranges are to be decided by the TSO pursuant to Article 4(3). 56 Requirement Large TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW < 10MW Rate of Change of Frequency Type A, B, C and D Offshore Power Park Modules The rate of change of frequency withstand capability requirement as defined in Article 7(1) (b) (of 2Hz/s) shall apply to Offshore Power Park Modules of configurations 1,2,3,4 and 5. Frequency Stability Type A and B Offshore Power Park Modules The Frequency stability requirements as defined in Article 7(1)(c) (operation to high frequencies in Limited Frequency Sensitive Mode) shall apply to any Offshore Power Park Module irrespective of its configuration. Nevertheless, for configurations 3, 5, and 6 offshore frequency or alternatively onshore frequency signals shall be used as reference. Type C and D Offshore Power Park Modules In addition to the requirements of Type B Offshore Power Park Modules, Type C and D Offshore Power Park Modules are also required to satisfy the Frequency stability requirements as defined in Article 9(2)(c) (operation to low frequencies in Limited Frequency Sensitive Mode), Article 9(2)(d) (Response to frequency changes in Frequency Sensitive Mode) and Article 16(2)(a) (synthetic inertia). These requirements shall apply to any Offshore Power Park Module irrespective of its configuration. Nevertheless, for configurations 3, 5, and 6 offshore frequency or alternatively onshore frequency signals shall be used as reference. Voltage Stability Requirements Voltage Range GB CC.6.1.4, CC.6.3.15, CC.6.3.2(e) CC.6.3.8 (b) (ENTSO-E – Article 20) Voltage Range (CC.6.1.4) - Large Offshore Generators are required to satisfy the same voltage range requirements as Large Onshore Generators as defined in CC.6.1.4 (ie at 400kV 5% with operation unless abnormal conditions prevail. The minimum voltage is 10% and the maximum is +10% but voltages of +5 to +10% will not last longer than 15 minutes. For voltages of 275kV and 132kV the system voltage variation shall be 10%. Not applicable Voltage Stability Requirements (Article 20) Voltage Range (Article 20(1)) All Offshore Power Park Modules – Irrespective of Type The Voltage ranges defined in Table 8 apply to all Offshore Power Park Modules of configurations 1, 2, 3, 4 and 5 within the time periods specified by Table 8 of Article 20(1). For configuration 6, the voltage range shall be defined individually. In GB (for voltages of 110kV and upwards) the ranges defined are 0.9 – 1.05 p.u continuous operation required and 1.05 – 1.10 operation is required for 15 minutes. (NOTE – Reference to Table 5.2 (which is applicable to voltages in the range of 110kV to 300KV) appears to be missing ). Reactive Power Injection (CC.6.3.15) – The requirements for reactive Power injection for an Offshore Power Park Module are defined in the Fault Ride Through requirements defined under CC.6.3.15.1 or CC.6.3.15.2. In summary the Offshore Power Park Module is required to generate maximum reactive current without exceeding the transient rating of the Offshore Generating Unit or Offshore Power Park Module. Voltage Stability Requirements (Article 20(2)) Type B Offshore Power Park Modules The voltage stability requirements defined in Article 15(2) (a) and (b) (Reactive Current Injection) shall apply to Offshore Power Park Modules of configurations 1, 2, 3, 4 and 5 Type C and D Offshore Power Park Modules In addition to the requirements of Type B Offshore Power Park Modules, Type C and D Offshore Power Park Modules are required to meet Article 16 (3) (c) (Reactive Power below maximum capacity) and Article 16(3)(d) (the priority of Active Power over Reactive Power) Reactive Capability (CC.6.3.2(e)) – Offshore Generators have the option of one of the 57 Requirement Large TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW following requirements. i) < 10MW Reactive Capability (Article 20(3)) Type C and D Offshore Power Park Modules The Reactive Power Capability at maximum Active Power as defined in Article 16(3) (b) (Reactive Power Capability (P/Q Profile at maximum capacity) shall apply to Offshore Power Park Modules of configurations 1, 2, 3, 4 and 5 except for Table 7 of Article 16(3)(b) which shall be replaced by Table 9 of Article 20(3). Under the ENTSO-E RfG within Great Britain the Q/PMax range for Configurations 1 and 6 shall be 0 (equivalent to Unity Power Factor at 1.0 p.u voltage) and for Configurations 2,3,4 within Great Britain the Q/PMax range shall be 0.33 (equivalent to a Power Factor Range of 0.95 or 0.975 lead to 0.975 lag) at 1.0 p.u voltage. (NOTE:- Figure 11 should be read in the context of Table 9 instead of Table 7)). Maintenance of zero transfer of Reactive Power at all Active Power output levels (ie unity power factor) at the Offshore Grid Entry Point where the Offshore Grid Entry Point is at the LV side of the Offshore Platform. The steady state tolerance on Reactive Power Transfer to and from an Offshore Transmission System expressed in MVAr shall be no greater than 5% of the Rated MW (CC.6.2.3(e)(i)) Reactive Power Control Modes (Article 20 (4)) Type C and D Offshore Power Park Modules The Reactive Power Control Modes as defined in Article 16(3) (e) (ie Power Factor Control, Reactive Power Control or Voltage Control) shall apply to Offshore Power Park Modules of Configurations 1, 2, 3, 4 and 5. For Configuration 6 only the Voltage Control option shall apply. ii) Maintain a transfer of Reactive Power at the Offshore Grid Entry Point at a value specified in the Bilateral Agreement that is equivalent to zero transfer (ie unity Power Factor) at the LV Side of the Offshore Platform. The steady state tolerance on Reactive Power to and from an Offshore Transmission System expressed in MVAr shall be no greater than 5% of the rated MW. In other words this requirement is the same as i) above except allowing for the fact that the Offshore Grid Entry Point may not be at the LV Side of the Offshore Platform (CC.6.3.2(e)(ii)) iii) The Reactive Power Capability (including any tolerance) will be specified in the Bilateral Agreement providing agreement has been reached between the Generator, Offshore Transmission Licensee and NGET (CC.6.3.2(e)(iii)). iv) For Offshore Synchronous Generators, the Short Circuit Ration should be not less than 0.5. Voltage Control (CC.6.3.8(b)) – A continuously acting control system is required to provide control of reactive power (as detailed in CC.6.3.2(e)(i)(ii)) at the Offshore Grid Entry Point without instability over the entire operating range. The performance requirements of this automatic control system will be specified in the Bilateral Agreement. 58 Requirement Large TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW Where an alternative reactive capability has been specified in the Bilateral Agreement in accordance with CC.6.3.2(e)(iii) the Offshore Generator will be required to control voltage and / or reactive power without instability over the entire operating range. The performance requirements of the control system will be specified in the Bilateral Agreement. Robustness of Generating Units applicable to Offshore Power Park Modules (GB CC.6.3.7(b), CC.6.3.8(b), CC.6.3.15 and ENTSO-E Article 21(4) In addition the requirements for excitation control facilities including Power System Stabilisers where in NGET’s view these are necessary for system reasons they will be specified in the Bilateral Agreement. In Great Britain the same requirements for Onshore Generators applies to Offshore Generator unless otherwise specified. < 10MW Not applicable Steady State Stability – captured under Governor / Frequency Control Stability covered under CC.6.3.7(b), Voltage / Reactive Power Controllers covered under CC.6.3.8(b) and Stability during faults is covered under the fault ride through requirements defined under CC.6.3.15. Steady State Stability (Article 21(1) Type C and D Offshore Power Park Modules The requirements defined in Article 9(4)(a) (maintenance of steady state stability for any point within the PQ diagram in the case of power oscillations and prohibition of tripping or power reduction) shall apply to Offshore Power Park Modules of configurations 1, 2, 4 and 6. Torsional Stress (Article 21(2)) Type C and D Offshore Power Park Modules The requirements defined in Article 9(4)(b) (ability of Generating units to be designed in a way that shaft torsional stress which may be excited by transient Active Power steps up to 50% of its maximum capacity are considered a routine part of normal operation and shall be taken into account when specifying the shaft characteristics) withstand torsional stress and the ability of generating units to withstand auto re-closure (including fast single phase auto re-closure) shall apply to Offshore Power Park Modules of configurations 1, 2 and 4. Torsional Stress – Not explicitly defined. The requirements for subsynchronous resonance are however applicable to HVDC Converters. Power Oscillation Damping Control – Captured under Voltage / Reactive Power Control under CC.6.3.8(b) with the specific requirement for power oscillation damping being specified in the Bilateral Agreement. Power Oscillation Damping Control (Article 21(3)) Type C and D Offshore Power Park Modules The requirements as defined in Article 16(3)(f) (requirements for power oscillations damping control as specified by the TSO pursuant to Article 4(3)) shall apply to Offshore Power Park Modules of configurations 1, 2, 4 and 5. Fault Ride Through – Offshore Power Park Modules are required to have a fault ride through capability and have the option of satisfying one of two options. Fault Ride Through Capability (Article 21(4)) Type D Offshore Power Park Modules The fault ride through requirements of Power Park Modules as defined as in Article 17(1)(a) (Fault Ride Through for Type D Power Park Modules) shall apply to any Offshore Power Park Module, irrespective of its configuration. (Note – This reference (Article 17(1)(a)) may require review as it only applies to Type D Offshore Power Park Modules) Option 1 – is the same requirement as required from Onshore Power Park Modules with compliance being measured at the Interface Point as defined under CC.6.3.15.1 as outlined above. Option 2 - Fault Ride Through requirements 59 Requirement Large TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW are defined at the LV side if the Offshore Platform. < 10MW Faults up to 140ms in duration:For faults up to 140ms in duration each offshore Generating Unit or Power Park Module is required to remain transiently stable and connected to the System without tripping for any balanced or unbalanced voltage dips on the LV Side of the Offshore Platform whose voltage profile is anywhere on or above the heavy black line shown in Figure 6. Under worst case conditions this requires the Offshore Generator or Offshore Power Park Module to remain connected to the system for voltage dips of 15% retained voltage or above. During the period of the fault each Offshore Generating Unit or Offshore Power Park Module is required to provide Active Power at least in proportion to the retained voltage at the LV Side of the Offshore Platform except in the case of an Offshore Power Park Module where there has been a reduction in the intermittent power source in the time range in Figure 6 that restricts the Active Power below this level. In addition, each Offshore Generating Unit or Offshore Power Park Module shall generate maximum reactive current without exceeding the transient rating limits of the Offshore Generating Unit or Offshore Power Park Modules. Faults greater than 140ms in duration: In addition to the requirements for faults lasting up to 140ms, each Offshore Power Park Module and Offshore Generating Unit is required to remain transiently stable and connected to the System without tripping for any balanced voltage dip on the LV Side of the Offshore Platform and associated durations anywhere on or above the heavy black line shown in Figure 7. In addition each Offshore Generating Unit or Offshore Power Park Module shall provide Active Power output during voltage dips on the LV Side of the Offshore Platform as described in Figure 7 at least in proportion to the retained balanced or unbalanced or unbalanced voltage at the LV 60 Requirement Large TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW Side of the Offshore Platform except in the case of an Offshore Power Park Module where there has been a reduction in the intermittent Power Source that restricts the active power below this level and in addition shall generate maximum reactive current (where the voltage at the Offshore Grid Entry Point is outside the limits specified in CC.6.1.4) without exceeding the transient rating limits of the Offshore Generating Unit or Offshore Power Park Module. In addition within 1 second of the restoration of the voltage at the LV Side of the Offshore Platform (to the minimum levels specified in CC.6.1.4) restore Active Power to at least 90% of the Offshore Generating Units or Offshore Power Park Modules immediate pre-disturbed value unless there has been a reduction in the intermittent Power Source in the time range in Figure 7 that restricts the Active Power below this level. System Restoration Requirements applicable to Offshore Power Park Modules (GB CC.6.3.5, CC.6.3.7(c) ENTSO-E – Article 22) General System Management Requirements Applicable to Offshore Power Park Modules (GB CC.6.2.2.2, CC.6.5.6, PC, CC.6.6, BC.1.A.1.1, CC.6.3.11, CC.6.1.5, C.6.1.6 and CC.6.1.8 In addition, Offshore Generators (which includes Offshore Generating Units and Offshore Power Park Modules) are required to also meet the requirements of CC.6.3.15.3 which are the same as the Onshore requirements. Blank Start (CC.6.3.5) – Specified by NGET in the Bilateral Agreement. Island Operation (CC.6.3.7(c) – onshore requirement in CC.6.3.7(c). As < 10MW Black Start and Island Operation – Not applicable Resynchronisation – Specified in Bilateral Agreement between NGET and the User. System Restoration (Article 22) Type C and D Offshore Power Park Modules The System Restoration requirements defined respectively in Article 9(5) (a) (Black Start Capability), Article 9(5)(b) (Island Operation) and Article 9(5)(d) (resynchronisation) shall apply to any Offshore Power Park Modules irrespective of its configuration. As per Large except for:Neutral Earthing (CC.6.3.11) General System Management Requirements (Article 23(1)) Type B Offshore Power Park Modules The general system management requirements defined respectively in Article 8 (General Requirements to Type B Units) shall apply to any Offshore Power Park Module irrespective of its configuration. per Resynchronisation – Specified in the Bilateral Agreement between NGET and the User. General Type B Requirements (Controllability of Active Power, Reconnection requirements, Control Schemes and Settings and information exchange) are captured above in the Onshore Table. Protection Schemes and Settings (CC.6.2.2.2) The applicable protection requirements for Offshore Generators are the same as for Onshore Generators in accordance with CC.6.2.2.2. These are covered in detail in the above Onshore Table. Type C and D Offshore Power Park Modules In addition to the requirements applicable to Type B Offshore Power Park Modules, Type C and D Offshore Power Park Modules shall also be required to satisfy the requirements of Article 9(6)(b) (Protection schemes and Settings), Article 9(6)(c) Priority ranking of Protection and Control), Article 9(6)(d) (disconnection/tripping in the event of loss of stability), Article 9(6)(e) 61 Requirement Large TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW ENTSO-E Article 23(1) < 10MW (Instrumentation, Dynamic System Monitoring, fault recording, Article 9(6)(f) (submission of simulation models including electromagnetic transient simulations), Article 9(6)(g) (requirements to install additional devices to preserve and restore system operation or security pursuant to the requirements of Article 4(3)), Article 9(6)(h) (maximum and minimum limits on rates of change of Active Power), Article 9(6)(i) (Earthing requirements for the neutral point of a step up transformer), Article 9(6)(j)(Power Quality requirements), Article 9(6)(k)(Requirements for modernised or replaced plant and equipment) Instrumentation and Monitoring (CC.6.5.6 and CC.6.6). The requirements for Operational Metering (CC.6.5.6) and Dynamic System Monitoring (CC.6.6) are the same as the Onshore requirements although the Offshore Transmission Licensee will have responsibility for transfer of this data to the Onshore Transmission Licensee. Synchronisation Requirements (Article 23(2)) Type C and D Offshore Power Park Modules The synchronisation requirement as defined in Article 9(6)(a) (Synchronisation requirements) shall apply to Offshore Power Park Modules of Configurations 1,2,3, 4 and 5. Submission of Models and Data (PC) The full data requirements including models are captured under the Grid Code Planning Code. There is no significant difference between the Offshore Data requirements and Offshore Data requirements. The European Grid Code requires electromagnetic transient simulations which the GB Grid Code does not. Installation of additional devices to install additional devices to preserve and restore system operation or security Defined in the Bilateral Agreement pursuant to the requirements of the Grid Code Limits on Maximum Rates of Change of Active Power (BC.1.A.1.1) Defined in Grid Code BC.1.A.1.1 for each BM Participant at the Grid Entry Point For a change up to 300MW - No Limit For a change greater than 300MW and less than 1000MW – 50MW/min For a change of 1000MW or more 40MW /min This requirement equally applies to Onshore and Offshore Connections. Earthing Points for the Neutral Point of a Step up transformer (CC.6.3.11) As per an Onshore Generator – At nominal system voltages of 132kV or above the higher voltage windings of a transformer of a Generating Unit, DC Converter or Power Park Module must be star connected with the star point suitable for connection to earth. Power Quality (CC.6.1.5, CC.6.1.6 and CC.6.1.8) The same power quality requirements onshore 62 Requirement Large TABLE 3 – OFFSHORE ENTSO-E RfG to GB GRID CODE GB Power Station Type ENTSO-E – RfG -Generating Unit Type Small Offshore Power Park Modules > 10 MW apply offshore other than in respect of Phase unbalance and Voltage fluctuations where such requirements are specified in the Bilateral Agreement. < 10MW Requirements for modernisation of plant (Classified as a Modification under the Grid Code Glossary and Definitions) Where plant is modernised or replaced, the requirements applicable to the new plant will fall under a “Modification” which is defined under the Grid Code Glossary and Definitions. A Modification is defined as any proposed replacement, renovation, modification alteration or construction which may have a material effect on NGET or a User. In general the Bilateral Agreement would be updated and the new item of plant or equipment would be required to meet the latest Grid Code requirements where applicable. The requirement is equally applicable to both Onshore Generators. Synchronisation Requirements Specified under the Bilateral Agreement and as detailed in the Relevant Electrical Standards 63