TECHNICAL OVERVIEW OF IMPACTING REQUIREMENTS FOR THE CATEGORIZATION OF THE POWER GENERATING MODULES

Transcription

1 TECHNICAL OVERVIEW OF IMPACTING REQUIREMENTS FOR THE CATEGORIZATION OF THE POWER GENERATING MODULES Task Force Implementation Network Codes 27/01/2017

2 Contents 1 Introduction Proposal for determination of significance [Art 5] Type A Frequency stability& Active Power management Frequency withstand capability [Art (a)] Rate Of Change Of Frequency (ROCOF) withstand capability [Art 13.1(b)] Limited frequency sensitive mode over frequency [Art (a)] Admissible maximum power reduction with falling frequency [Art. 13-4] Logical interface to cease active power injection [Art 13-6] Automatic reconnection [Art 13-7] Type B Frequency stability and active power management Remote control of active power [Art 14-2] Fault-ride through for symmetrical and asymmetrical faults[art 14-3] Information exchange [Art 14-5 (d)] Structural data Scheduled data Real-time measurements Type B - SPGM Reactive power capabilities - SPGM [Art 17-2] Voltage Control SPGM type B[Art 17-2 (b)] Type B PPM Fault-ride through for symmetrical and asymmetrical faults - PPM [Art 20-3] Reactive capabilities - PPM [Art 20-2(a)] Fault Current & dynamic voltage support [Art 20-2 (b)] Post-fault active power recovery [Art 20-3] Type C Frequency stability& Active Power management Limited frequency sensitive mode under frequency [Art (c)] Frequency Sensitive Mode [Art d] Frequency restoration control [Art 15-2.e] Real-time monitoring of FSM [Art 15-2.g] Rates of change of active power output [Art 15-6.e] System restoration [Art 15-5] Information exchange Voltage control mode (for SPGM and PPM) [Art 19-2(a) and Art 21.3(d)] Type C SPGM Reactive power capability SPGMs [Art 18-2] Voltage control requirements for SPGM type C Type C PPM Synthetic inertia for PPM [Art 21-2] Reactive capabilities - PPM [Art 21-3(a-c)] Voltage control - PPM [Art 21-3(d)] Type D Voltage Control Voltage withstand capability [Art 16-2] Information Exchange Type D -SPGM Fault-ride through for symmetrical and asymmetrical faults SPGM [Art 16-3] Voltage stability SPGM (Art 19-2) Type D -PPM Version Task Force Implementation Network Codes Date 27/01/2017 Page 2 of 24

3 6.4.1 Fault-ride through for symmetrical and asymmetrical faults PPM [Art 22] Impact of the categorization of the SGUs on the Network Code Emergency and Restoration Acronyms References Version Task Force Implementation Network Codes Date 27/01/2017 Page 3 of 24

4 1 Introduction The aim of this document is to synthetize the most critical and cost-driving requirements related to the classification of the different Significant Grid Users (SGU) to support the discussions with the stakeholders for the second iteration of the Topic Significant Grid Users. Please note that only some of the specifications/requirements are here presented, the document is not exhaustive. Furthermore, it represents the most recent position of Elia in the ongoing discussions with the stakeholder in each of the relevant topics. It is therefore a working document and is not binding. Finally, there is no roadmap to further complete the document to make it exhaustive as it would then duplicate the content on the NCs and its national implementation. The document is organized per user type (A, B, C & D) and for each user per technical topic. For each proposed category, the current proposal is included. If not otherwise specified, in line with the RfG [1], each higher category has to fulfil the requirement for a lower one. As example the LFSM-O is specified for type A, but it is also valid for category B-C- D. In general all frequency related parameters are being coordinated between TSOs in the CE synchronous area to guaranty fair contribution among all control areas power generation units and overall resilience of the system. Further studies to assess the adequacy of the coordinated requirements might be executed by ENTSO/e SPD inter-tso coordination groups. This document focusses on the technical requirements. It does not discuss how to legally enforce these requirements in the Belgian framework (e.g. via derogations, contracts, grid codes, etc.). It is important to read this document taking into account a disclaimer on finding appropriate legal solutions. In case such solution could not be found or, for instance, necessary derogations would not be accepted by the competent authorities, this may impact the actual technical requirements. The document takes as working hypothesis for the generator type A, B, C and D limits, the proposal made by Elia (and Synergrid) in the so-called first iteration on significant grid users which took place early However, Elia recognizes that stakeholders have made alternative proposals for these limits. This document should be considered as an input to the 2 nd iteration on significant grid users and thereby contributes to the assessment of the working hypothesis and inherently also the alternative solutions. The scope of this document is determined by the requirements coming from the European Network Codes. It is important to be aware that more requirements can exist at national level as long as they do not act against network codes stipulations. Listing such complementary national requirements goes beyond the scope of this document. Version Task Force Implementation Network Codes Date 27/01/2017 Page 4 of 24

5 2 Proposal for determination of significance [Art 5] The current proposal for determination of significance is defined taking into account the arguments received from the Stakeholders as follow: Type A o Power Generating Modules (PGMs) with an installed power lower than 0.25 MW Type B o PGMs with an installed power lower than 25MW and higher or equal than 0.25 MW Type C o PGMs with an installed power higher or equal than 25MW and connected to voltage levels lower than 110kV Type D o o PGMs with an installed power higher than 75MW PGMs with an installed power higher or equal t 25MW and connected to voltage levels higher or equal than 110kV The proposal is represented graphically in the figure below. kv D 110 A B D C MW Figure 1: Graphical representation of the current proposal for SGU categorization It must be noted that the Power Park Modules (PPM), for which the connection point is located offshore should follow the same prescriptions as type D PPM units. A proposal by the relevant TSO to change the thresholds could be made not sooner than three years after the previous proposal [Art 5.3]. Version Task Force Implementation Network Codes Date 27/01/2017 Page 5 of 24

6 3 Type A 3.1 Frequency stability& Active Power management In general all frequency related parameters are being coordinated between TSOs in the CE synchronous area to guaranty fair contribution among all control areas power generation units and overall resilience of the system. Further studies to assess the adequacy of the coordinated requirements might be executed by ENTSO/e SPD inter-tso coordination groups Frequency withstand capability [Art (a)] The frequency withstand capability is defined in line with the RfG and presented in the table below. Frequency Range Duration 47,5 Hz 48,5 Hz 30 minutes 48,5 Hz 49,0 Hz Minimum 60 minutes 49,0 Hz 51,0 Hz Unlimited 51,0 Hz 51,5 Hz To be agreed 51,5 Hz 52,0 Hz To be agreed For frequency range between 48.5Hz and 49.0Hz, power generating module shall be cable to remain connected to the network and operate for a minimum period of 60 minutes unless a reasonable technical justification is provided. The duration between 51.0Hz and 51.5Hz are to be agreed site specifically in coordination with the system operator and the power generation facility owner. The duration between 51.5Hz and 52.0Hz are to be agreed site specifically in coordination with the system operator and the power generating facility owner as per the provision of the RfG art 13.1a(ii), in coherence with the reconstruction schemes in place in Belgium as stated in the FGC, Article 62 1 [2] Rate Of Change Of Frequency (ROCOF) withstand capability [Art 13.1(b)] A maximum value of ROCOF for which the units has to remain connected is being coordinated with other TSOs. ELIA s current proposal is 2Hz/s, as per the last investigations of ENTSO/e SPD inter- TSO coordination [3]. The ROCOF for the loss of main is as well being coordinated with other TSO Limited frequency sensitive mode over frequency [Art (a)] In case of positive frequency deviations (LFSM-O) above 200mHz (Δf1) from the nominal frequency fn, the active power output of the PGM shall be reduced as shown in the Figure 2, where the power in pu shall be able to decrease following a droop (S1) that is adaptable between 2% and 12% (fixed initially at 9 %). The transient power variation shall be at least 1 % of of Pnom per second with an initial activation delay as short as technically possible and in any case lower than 2 seconds (unless reasonable technical justification is provided). Version Task Force Implementation Network Codes Date 27/01/2017 Page 6 of 24

7 ΔP/P nom Δf 1 f n Δf f n S 1 Figure 2: Active Power Frequency Response capability of a PGM (LFSM-O). The use of automatic disconnection and reconnection, applicable only to type A PGMs [Art (b)] is site specific and is to be agreed with ELIA on a case by case level. Once the PGM has reached its minimum regulating level, it should remain at this level Admissible maximum power reduction with falling frequency [Art. 13-4] For a frequency reduction a generating unit shall reduce its maximum output proportionally to frequency reduction in a way that at 47,5 Hz maximum power shall not be lower than 95% of the maximum capacity defined in the design characteristics. For CCGT units the above requirement shall be retained for a time period of 5 min at least subsequently to 49 Hz corresponding to the first stage of Automatic Low Frequency Demand disconnection in Belgium. Technical justification shall be provided if the power generation unit cannot achieve the current requirements Logical interface to cease active power injection [Art 13-6] This specification is site specific and is to be agreed with the system operator (DNBs or Elia) on a case by case level Automatic reconnection [Art 13-7] Site specific requirement. For generation connected to Elia grid the automatic reconnection shall not be allowed. During network reconstruction, scenario problems can arise if generators reconnect automatically to an islanded power system without coordination with the Elia s National Control Center (NCC). For generation connected to distribution networks automatic reconnection is acceptable under the following conditions: - Frequency remain between 47.5 and a delay of one minute is applicable (providing the frequency remain within the defined range); - Voltage level is higher than 0.95 p.u ; - The maximum admissible power increase gradient is set to 10 % of Pmax per minute. Version Task Force Implementation Network Codes Date 27/01/2017 Page 7 of 24

8 Voltage [pu] Technical overview of impacting requirements for the categorization of the Power Generating Modules 4 Type B In addition to the specifications for type A, the following is requested. 4.1 Frequency stability and active power management Remote control of active power [Art 14-2] The requirement for the control of active power is defined as site specific. It has to be agreed with ELIA on a case to case basis. 4.2 Fault-ride through for symmetrical and asymmetrical faults[art 14-3] This requirement should be met at the point of common coupling (POCC). The SPGM should be able to support the network during fast transient voltages and network shortcircuits for which the profile of the voltage versus time is referred as Fault-Ride-Through (FRT). SPGM shall fulfil the requirements in the figure below, where the SPGM shall remain connected to the grid as long as the voltage of the phase having the lower voltage is above the profile. It is recommended however to remain connected as long as the technical capability of the SPGM would allow. The same profile applies for asymmetrical faults. Proposal LVRT vs NC PGM Type B&C 1 0,9 0,8 0,7 0,6 0,5 0,4 0,3 0,2 0,1 0-0,5 0,5 1,5 2,5 Time [s] Current LVRT NC less stringent NC most stringent Proposal Figure 3: LVRT requirement for PGM type B and C According to the feedback received from stakeholders on this topic these requirements may be difficult to meet for several installations. Elia has taken note of this feedback, will study it further and take it into consideration when making updated proposals during the second iteration on significant grid users. 4.3 Information exchange [Art 14-5 (d)] The discussion on the precise list of data/measures to exchange in real-time is still ongoing. According to the feedback received from stakeholders on this topic some requirements may be difficult to meet for several installations. Elia has taken note of this feedback, will study it further and take it into the second iteration on significant grid users Structural data See Excel file communicated during Experts group. So far, no blocking points have been identified. Version Task Force Implementation Network Codes Date 27/01/2017 Page 8 of 24

9 4.3.2 Scheduled data Type B connected to TSO (legal obligation general application) - active power output and active power reserves amount and availability, on a dayahead and intra-day basis; - without any delay, any scheduled unavailability or active power capability restriction; - any forecasted restriction in the reactive power control capability; and Type B connected to DSO (only when specific contract is signed (i.e. CIPU) size specific) - its scheduled unavailability, active power restriction and its forecasted scheduled active power output at the connection point; - any forecasted restriction in the reactive power control capability; and Real-time measurements Type B connected to TSO - position of the circuit breakers at the connection point or another point of interaction agreed with the TSO; - active and reactive power at the connection point or another point of interaction agreed with the TSO; and - in the case of power generating facility with consumption other than auxiliary consumption net active and reactive power. Type B connected to DSO - active and reactive power flows at the connection point. 4.4 Type B - SPGM Reactive power capabilities - SPGM [Art 17-2] This requirement should be met at the point of common coupling (POCC). All SPGM of type B should be compliant with the requested reactive power capabilities shown in the P/Q diagram in Figure 4. For U < Un (LV) or U < 95% U (HV), the required extremities of the reactive capability curve (factor 0,484) are softened to avoid I > Imax and instability. The requirements in those case are shown in Figure 5. For every connection demand, it should be proven that the SPGM is limited to those figures. Figure 4: Capability curve for SPGM typeb Version Task Force Implementation Network Codes Date 27/01/2017 Page 9 of 24

10 Figure 5: adapted requirement for U < Un (LV) or U < 95% U (HV) According to the feedback received from stakeholders on this topic these requirements may be difficult to meet for several installations. Elia has taken note of this feedback, will study it further and take it into consideration when making updated proposals during the second iteration on significant grid users Voltage Control SPGM type B[Art 17-2 (b)] With regard to the voltage control system, a synchronous power-generating module of type B shall be capable to control voltage with 6 control modi: Qfix: maintain a constant reactive power within the P/Q capabilities of Figure 5 Q(U): maintain a constant alternator voltage within the P/Q capabilities of Figure 5 Q(P): maintain a certain slope of the reactive power in function of the active power, within the P/Q capabilities of Figure 5 cosj fix: maintain a constant cos phi voltage within the P/Q capabilities offigure 5 cosj (U): maintain a certain slope of cos phi in function of the voltage, within the P/Q capabilities of Figure 5 cosj (P): maintain a certain slope of cos phi in function of the active power, within the P/Q capabilities of Figure 5 For all those control modi the setpoint should be remotely selectable. According to the feedback received from stakeholders on this topic these requirements may be difficult to meet for several installations. Elia has taken note of this feedback, will study it further and take it into consideration when making updated proposals during the second iteration on significant grid users. 4.5 Type B PPM Fault-ride through for symmetrical and asymmetrical faults - PPM [Art 20-3] This requirement should be met at the point of common coupling (POCC). The PPM should be able to support the network during fast transient voltages and network shortcircuits for which the profile of the voltage versus time is referred as Fault-Ride-Through (FRT). PPM shall fulfil the requirements in Figure 6: LVRT requirement for PPM type B and C (the evolution of the minimum voltage at the Connection Point), where the PPM shall remain connected to the grid as long as the voltage of the phase having the lower voltage is above the profile of Figure 6. It is recommended however to remain connected as long as the technical capability of the PPM would allow. The same profile applies for asymmetrical faults. Version Task Force Implementation Network Codes Date 27/01/2017 Page 10 of 24

11 Voltage [pu] Technical overview of impacting requirements for the categorization of the Power Generating Modules Proposal LVRT vs NC PPM Type B&C 1 0,9 0,8 0,7 0,6 Current LVRT 0,5 NC less stringent 0,4 0,3 NC most stringent 0,2 Proposal 0,1 0-0,5 0,5 1,5 2,5 Time [s] Figure 6: LVRT requirement for PPM type B and C Reactive capabilities - PPM [Art 20-2(a)] This requirement should be met at the point of common coupling (POCC). All PPM of type B with an installed power lower than 2MW should be compliant with the requested reactive power capabilities shown in the P/Q diagram in Figure 4. For PPM of type B with a installed power higher than 2MW, which are invertor connected, the requirements are more stringent as is shown in the P/Q diagram in Figure 7. For U < Un (LV) or U < 95% U (HV), the required extremities of the reactive capability curve (factor 0,484) are softened to avoid I > Imax and instability. The requirements in those case are shown in Figure 5. For every connection demand, it should be proven that the SPGM is limited to those figures. With regard to the voltage control system, a power park module of type B shall be capable to control voltage with 6 control modi (within the P/Q capabilities as presented in Figure 4 or Figure 7 respectively): Qfix: maintain a constant reactive power within the P/Q capabilities Q(U): maintain a constant alternator voltage within the P/Q capabilities Q(P): maintain a certain slope of the reactive power in function of the active power, within the P/Q capabilities cosj fix: maintain a constant cos phi voltage within the P/Q capabilities cosj (U): maintain a certain slope of cos phi in function of the voltage, within the P/Q capabilities cosj (P): maintain a certain slope of cos phi in function of the active power, within the P/Q capabilities For all those control modi the setpoint should be remotely selectable. According to the feedback received from stakeholders on this topic these requirements may be difficult to meet for several installations. Elia has taken note of this feedback, will study it further and take it into consideration when making updated proposals during the second iteration on significant grid users. Version Task Force Implementation Network Codes Date 27/01/2017 Page 11 of 24

12 Figure 7: Capability curve for PPM type B with installed capacity bigger than 2MW and invertor connected Fault Current & dynamic voltage support [Art 20-2 (b)] This requirement should be met at the point of common coupling (POCC). The PPM shall be able to inject/absorb additional reactive current compared to the pre-fault state during low and high voltage conditions up to the maximum of its capability. The additional injected/absorbed reactive current shall be function of the positive sequence voltage at the Connection Point. The requested additional reactive current behavior injection is illustrated in Figure 8 For voltages within the deadband [ V act, V + act ] the PPM should follow the normal voltage control mode. The injection or absorption of additional reactive current shall be delivered by the PPM with a minimal delay from the detection of the over/undervoltage, t Iq act.the functionality should remain active for a minimum time of t Iq on and can be deactivated if the voltage returns and remains within [ V act, V + act ] for a time longer than t Iq off. The parameters of this functionality lying within the normal operational range of the installation as well as the delays of activation and duration of the activation are to be agreed on a case by case with the TSO. I I I q pre fault q q pre fault Iq MAX I q V ACT V MAX MAX V ACT V V V V V pre fault pre fault min I q Figure 8: Injection of additional reactive current Post-fault active power recovery [Art 20-3] The parameters of this functionality and its activation should be agreed with the relevant TSO. Version Task Force Implementation Network Codes Date 27/01/2017 Page 12 of 24

13 5 Type C In addition to the specifications for type B, the following is requested. 5.1 Frequency stability& Active Power management Limited frequency sensitive mode under frequency [Art (c)] In case of negative frequency deviations beyond 200mHz (LFSM-U), and if the active power output of the PGM is lower than the maximum available, the active power output of the PGM shall be increased as shown in Figure 9. Above this 200 mhz deadband, the power modulation shall follow a droop (S2) that is adaptable between 2% and 12% (fixed initially at 9%). Similarly to the provisions for LFSM-O, the transient reaction shall be at least 1 % of Pnom per second with an initial activation delay as short as technically possible and in any case lower than 2 seconds (unless reasonable technical justification is provided). ΔP/P nom S 2 - Δf 1 f n Figure 9: Active Power Frequency Response capability of a PGM (LFSM-U). Unless the LFSM-U functionality is explicitly deactivated by the Transmission System Operator, this requirement has a higher priority than active power limitation. This means that if a frequency drop below 49.8 Hz occurs during a period of limitation of the active power output of the PGM(Pref), this limitation shall be bypassed (P>Pref). An activation/deactivation signal of this functionality shall be foreseen between the Transmission System Operator s dispatching centre and the PGM operator. Pref is to be considered Pmax for SPGM. Pref is the aggregated Pmax for PPM. Δf f n Version Task Force Implementation Network Codes Date 27/01/2017 Page 13 of 24

14 5.1.2 Frequency Sensitive Mode [Art d] Figure 10: Active power frequency response capability of power generating modules in FSM FSM related parameters are being coordinated between TSOs in the CE synchronous area to guaranty fair contribution among all control areas power generation units and overall resilience of the system. Current proposal of Elia for regional coordination is as following : Frequency response insensitivity (maximum acceptable) o deltaf1 maximum is 10 mhz & deltaf1 /fn maximum 0,02% Frequency response deadband and Frequency response insensitivity o Droop o 10mHz (e.g. Insensitivity 10 mhz and deadband 0 mhz) in coherence with the Annex V of the System Operation Guidelines [4] Available in a range between 2 and 12 % to be decided specifically by site to comply with full reserve deployment for 200 mhz deviation. Maximum admissible full activation time o 30 seconds Maximum admissible initial delay for power generating modules with FREQUENCY RANGES inertia o 2 seconds, if the power-generating facility owner cannot meet this requirement they shall provide technical evidence demonstrating why a longer time is needed for the initial activation of active power frequency response" Maximum admissible initial delay for power generating modules without inertia o Less than 2 seconds, if the power-generating facility owner cannot meet this requirement they shall provide technical evidence demonstrating why a longer time is needed for the initial activation of active power frequency response" Time period for the provision of full active power frequency response o Minimum 15 minutes. Version Task Force Implementation Network Codes Date 27/01/2017 Page 14 of 24

15 5.1.3 Frequency restoration control [Art 15-2.e] Specifications aligned with synchronous area TSOs in compliance with the System operation guidelines (Articles 154, 158, 161, 165) [4] Real-time monitoring of FSM [Art 15-2.g] Defined coherently as per the System Operation Guidelines (Article 47) [4] and currently applicable requirement of Elia Rates of change of active power output [Art 15-6.e] Minimum and maximum active power ramping limits (upward and downward) are to be defined site specifically taking into consideration the prime mover technology in compliance the system operation guidelines [4]. 5.2 System restoration [Art 15-5] Different from the current Federal Grid code [2], the NC asks for more strict behaviour for system restoration. More specifically with regard to quick re-synchronisation capability: In case of disconnection of the power-generating module from the network, the powergenerating module shall be capable of quick re-synchronisation in line with the protection strategy agreed between the relevant system operator in coordination with the relevant TSO and the power-generating facility; a power-generating module with a minimum resynchronisation time greater than 15 minutes after its disconnection from any external power supply must be designed to trip to houseload from any operating point in its P-Q-capability diagram. In this case, the identification of houseload operation must not be based solely on the system operator's switchgear position signals; power-generating modules shall be capable of continuing operation following tripping to houseload, irrespective of any auxiliary connection to the external network. The minimum operation time shall be specified by the relevant system operator in coordination with the relevant TSO, taking into consideration the specific characteristics of prime mover technology. 5.3 Information exchange See Excel file communicated during Experts group. So far, we don t identify any blocking point. Current practice is already almost 100% in line with Network Codes. 5.4 Voltage control mode (for SPGM and PPM) [Art 19-2(a) and Art 21.3(d)] This requirement should be met at the point of common coupling (POCC). These specifications are given in accord with the FGC Article 69. The PMG of type C and D are considered regulating units. They must be able to adapt their reactive power injected at the Connection Point: Automatically in case of slow or fast variations of the grid voltage. This has to happen according to a reactive droop (FGC Article 73); Through change of the controller setpoint on request of the Transmission System Operator. This request is quantified in MVAr measured at the Connection Point. The change of setpoint shall be initiated immediately after reception of the request; Reactive power exchange with the Network to control the voltage covering at least the 0.90 to 1.10 pu voltage range should be in steps not greater than 0.01 pu; The Reactive Power output shall be zero when the grid Voltage value at the Connection Point equals the Voltage Setpoint. Version Task Force Implementation Network Codes Date 27/01/2017 Page 15 of 24

16 Upcc (p.u.) 1pu Reactive droop Qmin 0 Qmax Figure 11 Principle of the voltage and reactive power control Automatic voltage control has to fulfil a reactive droop requirement (Figure 11). On request of the Transmission System Operator, the setpoint of the controller can be modified in real-time, and the operating point is to be shifted to a parallel line (dashed) with the same slope (illustrated in Figure 11). The control loop gain will be agreed between the Transmission System Operator and the PGM operator (before first energization) so that α_eq lies between 18 and 25, as expressed in the following: Qnet 0,45 Pnom _ eq Unet Unorm, exp Where U net is the voltage measured at the Connection Point U norm,exp is the normal exploitation voltage at the Connection Point Q net is the injected reactive power measured at the Connection Point 5.5 Type C SPGM Reactive power capability SPGMs [Art 18-2] This requirement should be met at the point of common coupling (POCC). All SPGMs of type C (but also type D) should be compliant with the requested reactive power capabilities shown in the U-Q/Pmax diagram, shown in Figure 12. For every connection demand, it should be proven that the SPGM is limited to this figure. According to the feedback received from stakeholders on this topic these requirements may be difficult to meet for several installations. Elia has taken note of this feedback, will study it further and take it into consideration when making updated proposals during the second iteration on significant grid users. Version Task Force Implementation Network Codes Date 27/01/2017 Page 16 of 24

17 Figure 12: Capability curve for SPGM type C and D Voltage control requirements for SPGM type C In line with the current federal grid code (art 75) [2]for which regards the functionalities and parameter settings of the voltage control system, the following functionality of voltage control are required: bandwidth limitation of the output signal to ensure that the highest frequency of response cannot excite torsional oscillations on other power-generating modules connected to the network; an underexcitation limiter to prevent the AVR from reducing the alternator excitation to a level which would endanger synchronous stability; an overexcitation limiter to ensure that the alternator excitation is not limited to less than the maximum value that can be achieved whilst ensuring that the synchronous power-generating module is operating within its design limits; a stator current limiter; a PSS function to attenuate power oscillations, if the synchronous power-generating module size is above value of maximum capacity specified by the relevant TSO. 5.6 Type C PPM Synthetic inertia for PPM [Art 21-2] Synthetic inertia functionality will not be required for the current Grid Code implementation due low maturity of the available technology and limitations in term of minimum time response which could result in adverse effects. Such functionality might be required for subsequent Grid Code amendment (3 year based periodic amendment) Reactive capabilities - PPM [Art 21-3(a-c)] This requirement should be met at the point of common coupling (POCC). In the area of continuous voltage operation as is mentionned in paragraph and for any value of the active power output between P min (20 % of P nom ) and P nom, the PPM of type C (but also type D) shall be able to produce or consume - at least - any reactive power at the Connection Point within the area limited by Q1,Q2,Q3 and Q4 (Figure 11). For voltage values outside the continuous voltage operation as is mentionned in paragraph 6.1.1, it is requested that the PPM could participate in voltage regulation to the maximum of the technical capabilities of the installation. For every voltage value, at the Connection Point, in the area of continuous voltage operation as is mentionned in paragraph 6.1.1and for any value of active power output between P 0 (equal to 2.63 % of P nom ) and P min, the minimum range of operating point for which reactive power shall be controlled is defined by the two values of the power factor computed by the points (Q1,0.2*P nom ) and (Q2, 0.2*P nom ). For every voltage, at the Connection Point, in the area of continuous voltage operation as is mentionned in paragraph 6.1.1and for any value of active power output below P 0, the reactive power can be Version Task Force Implementation Network Codes Date 27/01/2017 Page 17 of 24

18 uncontrolled, however, injected/absorbed values must be limited within a range of Q = [-3,29 ;+3,29] % Pnom 1 that is represented by the shaded area in the Figure 13. (See next paragraph: in case of small shifts this area will be adapted/shifted proportionally). For every connection demand, it should be proven that the PPM is limited to this figure. According to the feedback received from stakeholders on this topic these requirements may be difficult to meet for several installations. Elia has taken note of this feedback, will study it further and take it into consideration when making updated proposals during the second iteration on significant grid users. 1 p.u (Pnom) Q3 Q4 Underexcited operation Overexcited operation Q2 0,2 p.u Q1 Pmin P0 Q/Pnom -0,25 0-0,0329 0,0329 0,25 Figure 13: Reactive power capability for a Type C and D PPM Voltage control - PPM [Art 21-3(d)] This requirement should be met at the point of common coupling (POCC). The PPM shall be capable of providing reactive power automatically by either voltage control mode, reactive power control mode or power factor control mode. 1 FGC Article 209 3: 3,29 % = 10 % of the reactive range at cos(phi) = Version Task Force Implementation Network Codes Date 27/01/2017 Page 18 of 24

19 6 Type D In addition to the specifications for type C, the following is requested. 6.1 Voltage Control Voltage withstand capability [Art 16-2] This requirement should be met at the point of common coupling (POCC). The following voltage withstand capability are proposed in line with the RfG. Voltage ranges below 300kV Voltage ranges above 300kV Voltage Range Time period for operation 0.85 pu 0.90 pu 60 minutes 0.90 pu pu Unlimited pu 1.15 pu 20 minutes 0.85 pu 0.90 pu 60 minutes 0.90 pu 1.05 pu Unlimited 1.05 pu pu 20 minutes The following base values are to be considered: 400kV 220kV 150kV 110kV 70kV 36kV 6.2 Information Exchange See Excel file communicated during Experts group. No specific question anymore from stakeholders. See Excel file communicated during Experts group. So far, we don t identify any blocking point. Current practice is already almost 100% in line with Network Codes. 6.3 Type D -SPGM Fault-ride through for symmetrical and asymmetrical faults SPGM [Art 16-3] This requirement should be met at the point of common coupling (POCC). The SPGM should be able to support the network during fast transient voltages and network shortcircuits for which the profile of the voltage versus time is referred as Fault-Ride-Through (FRT). SPGM shall fulfil the requirements in the Figure below (the evolution of the minimum voltage at the Connection Point), where the SPGM shall remain connected to the grid as long as the voltage of the phase having the lower voltage is above the profile of Figure 14. It is recommended however to remain connected as long as the technical capability of the SPGM would allow. Version Task Force Implementation Network Codes Date 27/01/2017 Page 19 of 24

20 Voltage [pu] Technical overview of impacting requirements for the categorization of the Power Generating Modules Proposal FRT vs NC SPGM Type D 1,1 1 0,9 0,8 0,7 0,6 0,5 0,4 0,3 0,2 0,1 0-0,5 0,5 1,5 2,5 Time [s] Current FRT Current LVRT NC most stringent NC less stringent Proposal Figure 14: LVRT requirement for SPGM type D Voltage stability SPGM (Art 19-2) In line with the current federal grid code (art 75) for which regards the functionalities and parameter settings of the voltage control system, the following functionality of voltage control are required: bandwidth limitation of the output signal to ensure that the highest frequency of response cannot excite torsional oscillations on other power-generating modules connected to the network; an underexcitation limiter to prevent the AVR from reducing the alternator excitation to a level which would endanger synchronous stability; an overexcitation limiter to ensure that the alternator excitation is not limited to less than the maximum value that can be achieved whilst ensuring that the synchronous power-generating module is operating within its design limits; a stator current limiter; a PSS function to attenuate power oscillations, if the synchronous power-generating module size is above value of maximum capacity specified by the relevant TSO. 6.4 Type D -PPM Fault-ride through for symmetrical and asymmetrical faults PPM [Art 22] This requirement should be met at the point of common coupling (POCC). The PPM should be able to support the network during fast transient voltages and network shortcircuits for which the profile of the voltage versus time is referred as Fault-Ride-Through (FRT). PPM shall fulfil the requirements in Figure 15, where the PPM shall remain connected to the grid as long as the voltage of the phase having the lower voltage is above the profile of Figure 7 It is recommended however to remain connected as long as the technical capability of the PPM would allow. The same profile applies for asymmetrical faults. Version Task Force Implementation Network Codes Date 27/01/2017 Page 20 of 24

21 Voltage [pu] Technical overview of impacting requirements for the categorization of the Power Generating Modules Proposal FRT vs NC PPM Type D 1 0,9 0,8 0,7 0,6 0,5 0,4 0,3 0,2 0,1 0-0,5 0,5 1,5 2,5 Time [s] Current FRT Current LVRT NC most stringent NC less stringent Proposal Figure 15:LVRT requirement for PPM type D. Version Task Force Implementation Network Codes Date 27/01/2017 Page 21 of 24

22 7 Impact of the categorization of the SGUs on the Network Code Emergency and Restoration The Network Code Emergency & Restoration shall apply to TSOs, DSOs, SGUs, defence service providers, restoration service providers, balance responsible parties, balancing service providers and nominated electricity market operators ( NEMO ). In particular, the Regulation shall apply to the following SGUs: existing and new power generating modules classified as type C and D existing and new power generating modules classified as type B, where they are identified as SGUs by the System Defence Plan and/or Restoration Plan; existing and new transmission-connected demand facilities existing and new transmission connected closed distribution systems providers of redispatching of power generating modules or demand facilities by means of aggregation and providers of active power reserve existing and new high voltage direct current ('HVDC') systems and direct current-connected power park modules existing and new type A & type B power generating modules, as well as to existing and new demand facilities, closed distribution systems and third parties providing demand response where they qualify as defence service providers or restoration service providers. However, not all SGUs have to implement all measures and execute instructions defined by this Network Code. The SGUs which have to implement and maintain measures of the system defence plan or restoration plan will be identified by the TSO. Below, a non-exhaustive list of the requirements for SGUs which are identified by the System Defence Plan and/or Restoration Plan, Defence Service Providers & Restoration Service Providers. The identification of SGUs, Defence Service Providers & Restoration Service Providers will be executed during the design phase of the System Defence and Restoration Plan. All SGUs identified by the System Defence Plan and Defence Service Providers, shall: implement and maintain measures of the System Defence Plan on their installations. execute, without undue delay, the instructions of the TSO in case of activation of the System Defence Plan maintain an active power set-point, provided that the set-point fulfils the technical constraints of the SGU or Defence Service Provider, as defined by the TSO in case of activation of the System Defence Plan [Only SGUs] maintain a reactive power range or voltage range, provided that the set-point fulfils the technical constraints of the SGU, as defined by the TSO in case of activation of the System Defence Plan [Only relevant Defence Service Providers] prior to the activation of the automatic low frequency demand disconnection scheme, on request of the TSO, activate demand response: o switch energy storage units acting as load to generation mode at an active power setpoint established by the TSO in the system defence plan; or o when the energy storage unit is not capable of switching fast enough to stabilize frequency, manually disconnect the energy storage unit. All SGUs identified by the Restoration plan and Restoration Service Providers, shall; implement and maintain measures of the Restoration plan on their installations. execute, without undue delay, the instructions of the TSO in case of activation of the Restoration plan maintain an active power set-point, provided that the set-point fulfils the technical constraints of the SGU or Restoration Service Provider, as defined by the TSO in case of activation of the Restoration plan Version Task Force Implementation Network Codes Date 27/01/2017 Page 22 of 24

23 have a voice communication system in place with sufficient equipment redundancy and backup power supply sources to allow the exchange of the information needed for the restoration plan for at least 24 hours, in case of total absence of external electrical energy supply or in case of failure of any individual voice communication system equipment. Member States may require a minimum backup power capacity higher than 24 hours. make available critical tools and facilities referred to in Article 24 of Regulation (EU) 2017/XXX [4] and used in the restoration plan for at least 24 hours in case of loss of primary power supply, as defined by the TSO test the communication systems, at least every year test the backup power supply of their communication systems at least every five years Version Task Force Implementation Network Codes Date 27/01/2017 Page 23 of 24

24 8 Acronyms SGU PGM LFSM LVRT PPM SPGM RfG NCC Significant Grid User Power Generating Module Limited Frequency Sensitive Mode Low Voltage Ride Through Power Park Module Synchronous Power-Generating Modules Requirement for Grid connection of generators Elia National Control Center 9 References [1] Network Code on Requirements for Grid Connection Applicable to all Generators (RfG) [2] Federal Technical Reglement- 19 DECEMBER Koninklijk besluit houdende een technisch reglement voor het beheer van het transmissienet van elektriciteit en de toegang ertoe [3] Frequency Stability Evaluation Criteria for the Synchronous Zone of Continental Europe, SPD WG, March 2016 [4] ENTSO/e System operation guidelines, May Version Task Force Implementation Network Codes Date 27/01/2017 Page 24 of 24