RfG Implementation Fault Ride Through

Transcription

1 RfG Implementation Fault Ride Through Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson / Ben Marshall National Grid Network Capability

2 Summary Review of RfG Generic Voltage against time curves Development of Type D Synchronous Power Generating Modules voltage against time curves connected at or above 110kV Development of Type B, C and D Synchronous Power Generating Modules voltage against time curves connected below 110kV Development of Type D Power Park Modules connected at or above 110kV Development of Type B, C and D voltage against time curves connected below 110kV Voltage against time study cases Summary Next steps 2

3 RfG - Fault Ride Through Requirements Voltage Against Time Profile Figure 3 U/p.u. 1.0 U rec2 U rec1 U clear U ret 0 t clear t rec1 t rec2 t rec3 t/sec 3

4 Type D Synchronous Power Generating Modules connected at or above 110kV Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson National Grid Technical Policy

5 RfG - Voltage Against Time Parameters Table 7.1 Type D Synchronous Power Generating Modules 110kV Voltage parameters [pu] Time parameters [seconds] U ret : 0 t clear : (or if system protection and secure operation so require) U clear : 0.25 t rec1 : t clear 0.45 U rec1 : t rec2 : t rec1 0.7 U rec2 : t rec3 : t rec2 1.5 Table 7.1 Fault Ride Through Capability of Synchronous Power Generating Modules 5

6 RfG - Voltage Against Time Profile Type D Synchronous Power Generating Modules Connected 110kV - Table 7.1 Voltage (p.u) NOT TO SCALE RFG Min RFG Max Time (s) 6

7 Derivation of Voltage Against Time Profile Type D Synchronous Power Generating Modules Process summarised in Appendix 2 of GC0062 Grid Code consultation U ret set at zero (consistent with fault on transmission network and GB) t clear set at 0.14s consistent with GB and protection operating times U clear fixed at 0.25 by ENTSO-E t rec1 set at 0.25s to allow for any slow recovery in voltage where high MVAr demands may be connected U rec1 set to 0.5. Only a value of can be selected. 0.5 is considered reasonable based on high MVAr demands and international practice (eg RTE requirements) t rec2 set to This is based on the fact that NGET backup protection would operate would operate within 500ms and large synchronous generators are likely to exhibit pole slipping for these time and voltage deviations U rec2 set to 0.9 the upper limit based on steady state recovery voltages t rec3 set to 1.5 seconds, based on protection having operated within this time, the ability of synchronous plant to withstand longer term high voltage dips (Mode B faults) and international practice eg (RTE requirements) 7

8 Proposed GB Type D Requirement 110kV Voltage Against Time Curve Voltage (p.u) NOT TO SCALE Proposed GB Requirement Time (s) 8

9 Proposed GB Type D Requirement 110kV Voltage Against Time Curve Voltage (p.u) NOT TO SCALE RFG Min RFG Max GB Proposal Time (s) 9

10 GB Suggested Parameters Consistent with Table 7.1 (Type D SPGM connected at or above 110kV) Voltage parameters [pu] Time parameters [seconds] U ret : 0 t clear : 0.14 U clear : 0.25 t rec1 : 0.25 U rec1 : 0.5 t rec2 : 0.45 U rec2 : 0.9 t rec3 : 1.5 Table 7.1 Parameters for Figure 3 for fault ride through capability of synchronous power generating modules. 10

11 Type B and C Synchronous Power Generating Modules and Type D Connected below 110kV Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson / Ben Marshall National Grid Network Capability

12 Fault Ride Through Type B and C and D Synchronous Power Generating Modules connected below 110kV Requirements for Type B, C and D Synchronous Power Generating Modules connected below 110kV The fault ride through requirements for Type B, C and D Synchronous Power Generating Modules connected below 110kV are broadly the same as Type D Synchronous Power Generating Modules connected at or above 110kV other than the voltage against time curve. In summary the voltage against time curve for Type B, C and D Synchronous Power Generating Modules connected below 110kV should be the equivalent voltage seen at the connection point for a Transmission System fault 12

13 Fault Ride Through Interpretation 11kV Requirement for Type B, C and D 132kV 132kV 132kV 132kV A X X 400kV Requirement for Type D 66kV 33kV X X C X Requirement for Type B, C and D X X B X X X X D X Requirement for Type D 13

14 RfG - Voltage Against Time Parameters Table 3.1 Type B & C and D Synchronous Power Generating Modules connected below 110kV Voltage parameters [pu] Time parameters [seconds] U ret : t clear : (or if system protection and secure operation so require) U clear : t rec1 : t clear U rec1 : U clear t rec2 : t rec1 0.7 U rec2 : and t rec3 : t rec2 1.5 > U clear Table 3.1 Fault Ride Through Capability of Synchronous Power Generating Modules 14

15 RfG - Voltage Against Time Profile Type B / C and D Synchronous Power Generating Modules connected below 110kV Voltage (p.u) NOT TO SCALE RFG Min RFG Max Time (s) 15

16 Derivation of Voltage Against Time Profile Type B, C and D Synchronous Power Generating Modules connected below 110kV t clear set at 0.14s consistent with Transmission Protection Operating times U ret set at 0.05 (see studies concern is due to low fault infeed depressing system voltage, especially with low levels of synchronous generation running) U clear fixed to the lower of 0.7 in line with RfG requirements t rec2 set to This is based on the fact that NGET backup protection would operate would operate within 500ms and synchronous generators are likely to exhibit pole slipping for these time and voltage deviations U rec2 set to 0.9 the upper limit based on steady state recovery voltages t rec3 set to 1.5 seconds, based on protection having operated within this time, the ability of synchronous plant to withstand longer term high voltage dips 16

17 Proposed GB Type B / C and (Type D connected below 110kV)* Voltage Against Time Curve Voltage (p.u) NOT TO SCALE Proposed GB Requirement Time (s) 17

18 Proposed GB Type B / C and D* Requirement Voltage Against Time Curve G59 Interaction Voltage (p.u) NOT TO SCALE G59 Stage 2 (0.5s, 0.8p.u) Proposed GB Requirement x x Time (s)

19 RfG - Voltage Against Time Parameters Table 3.1 Type B & C and D Synchronous Power Generating Units connected below 110kV Voltage parameters [pu] Time parameters [seconds] U ret : 0.05 t clear : 0.14 U clear : 0.7 t rec1 : 0.14 U rec1 : 0.7 t rec2 : 0.45 U rec2 : 0.9 t rec3 : 1.5 Table 3.1 Fault Ride Through Capability of Synchronous Power Generating Modules 19

20 Type D Power Park Modules connected at or above 110kV Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson / Ben Marshall National Grid Network Capability

21 RfG - Voltage Against Time Parameters Table 7.2 Type D Power Park Modules connected at or above 110kV Voltage parameters [pu] Time parameters [seconds] U ret : 0 t clear : (or if system protection and secure operation so require) U clear : U ret t rec1 : t clear U rec1 : U clear t rec2 : t rec1 U rec2 : 0.85 t rec3 : Table 7.2 Fault Ride Through Capability of Power Park Modules 21

22 RfG - Voltage Against Time Profile Type D Power Park Modules Table 7.2 connected at or above 110kV Voltage (p.u) NOT TO SCALE RFG Min RFG Max Time (s) 22

23 Derivation of Voltage Against Time Profile Type D Power Park Modules connected at or above 110kV Limited flexibility due to defined parameters t clear set to 140ms for protection operating times (as per synchronous power generating modules) All other parameters are defined other than t rec3. Based on System Studies, the slow voltage recovery that can be observed due to high MVAr demands under minimum demand conditions and low fault infeeds results in the requirement for this value to be set to 2 seconds but recognising an interpolated voltage value of 0.9p.u is required. 23

24 RfG - Voltage Against Time Profile Type D (connected at 110kV) Power Park Modules Voltage (p.u) NOT TO SCALE ? Time (s) 24

25 Type B, C and D Power Park Modules connected below 110kV Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson / Ben Marshall National Grid Network Capability

26 RfG - Voltage Against Time Parameters Table 3.2 Type B & C and D Connected below 110kV Power Park Modules Voltage parameters [pu] Time parameters [seconds] U ret : t clear : (or if system protection and secure operation so require) U clear : U ret 0.15 t rec1 : t clear U rec1 : U clear t rec2 : t rec1 U rec2 : 0.85 t rec3 : Table 3.1 Fault Ride Through Capability of Power Park Modules 26

27 ENTSO-E RfG - Voltage Against Time Profile Type B / C and Type D Connected below 110kV Power Park Modules - Table 3.2 Voltage (p.u) NOT TO SCALE RFG Min RFG Max Time (s) 27

28 Fault Ride Through Type B, C and D Power Park Modules connected below 110kV Requirements for Type B / C and D Power Park Modules connected at or below 110kV Adopt same principles as that for Synchronous Power Generating Modules. The Voltage against time curve seen at the connection point should reflect the equivalent voltage at that point for a Transmission System fault 28

29 Derivation of Voltage Against Time Profile Type B, C and D Power Park Modules connected below 110kV t clear set at 0.14s consistent with Transmission Protection Operating times U ret set at 0.05 (see studies concern is due to low fault infeed depressing system voltage, especially with low levels of synchronous generation running) t rec3 - Based on System Studies, the slow voltage recovery that can be observed due to high MVAr demands under minimum demand conditions and low fault infeeds results in the requirement for this value to be set in the region of 2 seconds but recognising the need for an interpolated voltage of 0.9p.u. 29

30 RfG - Voltage Against Time Profile Type B, C and D Power Park Modules connected below 110kV Voltage (p.u) NOT TO SCALE ? Time (s) 30

31 Voltage against time case study- the South West Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson / Ben Marshall National Grid Network Capability

32 Voltage against time Case Study - South West Area As presented to the industry within SOF 2015 pre-assessment Webinar, National Grid in conjunction with the local DNO (WPD) considered the impact of increasing Non Synchronous Generation at Transmission and Distribution level. Analysis considered the then 2014 level of generation connection, then anticipated 2015 levels of generation connection, and increasing levels across FES scenarios. 32

33 Increase of Generation in the Distribution Networks Future Energy Scenarios predictions for Embeddedd and Micro Generation: Embedded Generation: generation with installed capacity above 1MW Micro Generation: generation with installed capacity below 1MW

34 Example in South West Background: - Two transmission double circuits connecting South West with the rest of the system - Potential for large volumes of Embedded Generation being connected in the DNO networks - Several large synchronous generators in the area - Relatively long transmission circuits (high impedance)

35 00:00 01:30 03:00 04:30 06:00 07:30 09:00 10:30 12:00 13:30 15:00 16:30 18:00 19:30 21:00 22:30 Demand(MW) 00:00 01:30 03:00 04:30 06:00 07:30 09:00 10:30 12:00 13:30 15:00 16:30 18:00 19:30 21:00 22:30 Demand(MW) Embedded Generation and Effect on the Steady State Operation How large volumes of Embedded Generation could affect the operation of the transmission system: Lower the power transfers on the transmission network This may result in difficulties in managing the voltages on the transmission system in steadystate Need for reactive compensation sufficient to maintain the voltages within operation limits Demand in South West - June/July 2009 Time Demand in South West -June/July MW Solar Installed 05/06/ /06/ /06/ /07/ /07/ /07/ /07/ /06/ /06/ /06/ /07/ /07/ /07/ /07/2014 Time

36 Main System Background Assumptions System Background Assumptions Justification Demand Background 1. All system demands are dispatched from DEAF database at 21GW Demand Background 1. Typical summer minimum total system demand Generation Background 1. Summer minimum ranking order 2. Large size generators have voltage/reactive and frequency response capability 3. HVDC is modeled with full PowerFactory models 4. Embedded and Micro generation has been modelled in the DNO networks within the area of study Generation Background 1. Officially released by Energy Strategy and Policy team 2. Grid Code requirement 3. The latest HVDC models available are used 4. This assumption will provide better degree of modeling the system and will allow new opportunities to be explored System and generator outages 1. Typical summer outage pattern is used 2. Summer generator outages are taken in account System and generator outages 1. The typical outage pattern has been provided by Offshore team END (Appendix 1) (as outlined in BP-078) 2. Summer nuclear plant outages are taken into account in the Summer Ranking Order released by ESP team System Dispatch 1. The studies start from Y1 and additional NSG is being added in the region of study 2. In the region of study the all generation is dispatched to their rated capacity System Dispatch 1. This approach has been chosen in order to save study time and manage the project within its timeline 2. Assuming the worst case scenarios (to be consistent with NDP and ETYS process) where all non-synchronous generators inside the area of study are dispatched to 100% of their rated capacity

37 Main Modelling Assumptions Modelling Assumptions Justification System Fault 1. The worst N-D contingency highlighting the stability limit is assessed for every region 2. Fault is selected to be three-phase solid short-circuit on a double-circuit line having zero impedance for 140ms duration System Fault 1. Communication within SMARTER System Performance and Network development Strategy teams regional engineers 2. A conservative fault clearance time has been considered to represent the worst case scenario Generators 1. Embedded generators has the possibility to provide voltage support (considered as a potential solution in some cases) Generators 1. Communication with engineers in Smarter System Performance and Network Design Pre-fault voltages 1. Pre-fault voltages to be between pu Pre-fault voltages 1. Historical data suggests that voltages between pu as expected during summer minimum periods with high levels of wind and solar generation Reinforcements 1. Voltage Stability: Fast reactive compensation, dynamic compensation, synchronous machines operating in SynchComp mode, Reactive support from EG 2. Frequency Stability: additional inertia on the system, synchronous machines operating in SynchComp mode 3. Rotor Angle Stability: Power System Stabilizers Reinforcements 1. Some MSCs have capability to provide fast MVAR support, some current generators can operated in SynchComp mode 2. The studies conducted last year suggest that additional inertia on the system, synchronous machines operating in SynchComp mode improve stability

38 Impact of Embedded Generation on the Transmission System Impact and Potential Opportunities Running NSG output Increased transient over-voltage followed by voltage collapse on the transmission network, options are: - Transmission connected reactive support - Distribution connected generation on having voltage control - Active management of distribution connected generation Increase in non-synchronous generation results post-fault ToV, options to mitigate: - Transmission connected machines operating SynchComp mode - Transmission connected dynamic reactive support (STATCOM) - Distribution connected generation on having voltage control - Active management of distribution connected generation No Identified Stability Issues 3.5 GW 2022 running capacity (GG and CP) In South West area, embedded generation can deliver MVARs to GSPs with average loss of 15-20% due to the impedance of the distribution networks 2.5 GW 2015 running capacity 2014 running capacity 1.5 GW 0.7 GW

39 SW Area Voltage against Time (2014 NSG capacities) s p.u [s] MANN4\MANN4 MC2: Voltage, Magnitude in p.u. ALVE4\ALVE4A: Voltage, Magnitude in p.u. TAUN4\TAUN4 M1: Voltage, Magnitude in p.u. INDQ4\INDQ4 MC2: Voltage, Magnitude in p.u. LAND4\Term420: Voltage, Magnitude in p.u. HINP4\HINP4 M4: Voltage, Magnitude in p.u. LAGA4\LAGA4 R2: Voltage, Magnitude in p.u. MELK4\MELK4 R3: Voltage, Magnitude in p.u. NURS4\NURS4 MC2: Voltage, Magnitude in p.u. AXMI4\AXMI4 MC2: Voltage, Magnitude in p.u. CHIC4\CHIC4 R1/2: Voltage, Magnitude in p.u Section 6 of SOF 2015, casea within figure 67 of SOF describes the performance of the then low estimate of NSG capacity, relating to installed levels Condition INDQ8\INDQ_8A: show s:phi voltage LAGA8\LAGA_8A: Rotor Angle in rad stabilising to 0.99 p.u. HINB8\HINP_87: Rotor Angle in rad LAGA8\LAGA_8B: Rotor Angle in rad LAGA8\LAGA_8S: Rotor Angle in rad following HINB8\HINP_88: the Rotor fault, Angle in rad within 1.4s

40 SW Area Voltage against Time (2015 NSG capacities) [s] MANN4\MANN4 MC2: Voltage, Magnitude in p.u. ALVE4\ALVE4A: Voltage, Magnitude in p.u. TAUN4\TAUN4 M1: Voltage, Magnitude in p.u. INDQ4\INDQ4 MC2: Voltage, Magnitude in p.u. LAND4\Term420: Voltage, Magnitude in p.u. HINP4\HINP4 M4: Voltage, Magnitude in p.u. LAGA4\LAGA4 R2: Voltage, Magnitude in p.u. MELK4\MELK4 R3: Voltage, Magnitude in p.u. NURS4\NURS4 MC2: Voltage, Magnitude in p.u. AXMI4\AXMI4 MC2: Voltage, Magnitude in p.u. CHIC4\CHIC4 R1/2: Voltage, Magnitude in p.u Section 6 of SOF 2015, caseb within figure 67 of SOF describes the performance of the moderate estimate of NSG capacity, relating to 2015 installed levels Condition shows voltage performance- significant recurrent oscillation which stabilises within 4s- meets SQSS INDQ8\INDQ_8A: stability s:phi criterion with LAGA8\LAGA_8A: Rotor Angle in rad voltage HINB8\HINP_87: stabilising Rotor Angle in rad to better than LAGA8\LAGA_8B: Rotor Angle in rad 0.9 p.u. LAGA8\LAGA_8S: (SQSS Rotor Angle requirement) in rad HINB8\HINP_88: Rotor Angle in rad after 2.2s, with voltage better than 0.85 (RfG requirement) at 0.6s. However 0.9 p.u. is the critical recovery point for stabilised response

41 SW Area Voltage against Time (2020 NSG capacities) Section 6 of SOF 2015, case C within figure 67 of SOF describes the performance of the even more estimate of NSG capacity, relating to a 1GW increase beyond 2015 installed levels within the South West. This level occurs in 2020 in Gone Green and Consumer Power Scenarios. This condition highlights that, other than at Melksham and Hinkley Point where voltage stabilises above 0.9 p.u. following 1.45s, voltages are unstable against the SQSS criterion, requiring further mitigation. 41

42 What this means for RfG parameters Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson / Ben Marshall National Grid Network Capability

43 RfG - Voltage Against Time Profile Type D Power Park Modules 110kV - Table 7.2 Voltage (p.u) NOT TO SCALE RFG Min RFG Max SQSS point of SQSS compliant recovery (0.9p.u, 2.2s) RfG point of intercept of that recovery (0.85p.u, 2.086s) We need to confirm that extrapolating RfG requirement back up to 0.9 p.u. recovery as per GB codes does not present an issue Time (s) 43

44 Parameter selection conclusions- Table 7.2 Type D Power Park Modules 110kV Voltage parameters [pu] Time parameters [seconds] U ret : 0 t clear : 0.14 U clear : U ret t rec1 : t clear U rec1 : U clear t rec2 : t rec1 U rec2 : 0.85 t rec3 : Table 7.2 Fault Ride Through Capability of Power Park Modules 44

45 Retained voltage performance within DNO systems Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson / Ben Marshall National Grid Network Capability

46 Voltage Dips Case Study As presented to the industry within SOF 2015 assessment Webinars (August 2015), and within Chapter 4 (section 4.3) of the SOF National Grid considered the impact of 400kV faults and their associated voltage dips as system strength declined. SOF Analysis considered the then current 2015 network performance, and the performance of the network in 2025, corresponding to both Gone Green conditions for case studies of Walpole and Sellindge. 46

47 Voltage Dips Case Studyassumptions 2015 SOF Stakeholder Update Voltage Dips Assumptions Current system and FES forecast Data Studies conducted at Summer minimum transmission demand current or FES informed Generation dispatch ranking order for Summer minimum condition. Embedded ( Wind, Solar and Other ) generation installed capacity in current, and as per FES for future years. Current studies taken at typical 95% confidence of generation outputs at that time, in future years a 95% confidence of forecast load factors and availability taken for Summer minimum conditions. Equivalent assumptions with embedded and transmission generation applied. Consistent with methodology applied to SQSS Main Interconnected system study Consistent with the methodology as applied for H/04 review. Studies Full GB model using time domain simulation and static/dynamic demand based on week 24 information supplied. Embedded Generation modelled as per Week 24 and Statement Of Works submissions according to type and control approach applied (normally constant power factor). Initially start with current year, 2025 and 2035 Sites with low fault level and high local transmission/embedded generation. Comparison with 2014 SOF sites? Based on experience of the REACT project, 20% increase in susceptance applied at DNO level to ensure optimum retained voltage during the fault. 3 phase busbar fault at transmission level; 140ms fault clearance with voltages recorded two levels down plus where retained voltages above 0.85 p.u. 3 phase busbar fualt at DNO level; 500ms fault clearance with voltage recorded at 132kV for the time period plus transmission level voltages to the nearest connected generation (140ms, 250ms and 450ms intervals)

48 Voltage Dips Case Study Walpole As discussed within past SOF and Grid code H/04 review, as system strength declines, voltage dips become more significant in extent and Depth. H/04 consultation document This trend is seen to continue within the 2015 SOF (section 4.3 refers). National Grids System Operability Framework National Grids System Operability Framework

49 Voltage Dips Case Study- Walpole As considered within past Grid code H/04 review, Voltage dips impact the DNO system and terminal voltages seen by generation. However, given the scale of system strength decline now observed, the retained voltage within distribution systems can be seen to have significantly declined in recent SOF analysis- H/04 consultation document National Grids System Operability Framework National Grids System Operability Framework

50 Voltage Dips Case Study- Walpole In the 11 year period between H/04 analysis and SOF 2015, the following changes are apparent:- 132kV local retained voltage is now as low as 400kV voltage, rather than c.10% previously quoted. These levels are available only at remote 132kV sites (e.g Burwell) Local 33kV bus Voltage is not noticeably improved to 30% such scale of retained voltage requires distances as far as Norwich to achieve Profile of voltage recovery is equivalent to 400KV system- there is limited discernable improvement 132kV) National Grids System Operability Framework

51 What this means for embedded fault ridethrough Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson / Ben Marshall National Grid Network Capability

52 ENTSO-E RfG - Voltage Against Time Profile Type B, C Power Park Modules - Table 3.2 Voltage (p.u) NOT TO SCALE RFG Min 1.0 RFG Max Point of compliant recovery (0.9p.u, 2.2s) 0.85 RfG point of intercept of that recovery (0.85p.u, 2.086s) Time (s) RfG does not provide flexibility to replicate the retained voltages observed in study. As such the GNSO, DNOs and TOs going forward will need to further consider approaches which deliver the minimum 0.05p.u retained voltage in order to achieve overall containment to maximum loss of power infeed- this may drive new control strategies or investment. 52

53 ENTSO-E RfG - Voltage Against Time Profile Type B, C and D Synchronous Power Generating Modules connected below 110kV Voltage (p.u) NOT TO SCALE RFG Min RFG Max Point of compliant recovery (0.9p.u, 2.2s) 0.7 RfG point of intercept of that recovery (0.85p.u, 2.086s) Area of potential challenge the RfG required recovery profile for synchronous is potentially not borne out from the voltage/ time traces provided in a non-synchronous dominated recovery. GB recovery examples suggest 0.7 recovery at 0.14s is an issue but no latitude for differing setting exists in the code. Again GBSO, TOs and DNOs will need to evaluate options to provide such levels of recovery should solutions be required in practice Time (s) 53

54 Next Steps Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Antony Johnson National Grid Technical Policy

55 Next Steps Review suggested Voltage against time curve for Large (Type D connected below 110kV or above) SPGM Apply equivalent requirement for Type B / C and D connected below 110kV SPGM Develop requirements for Power Park Modules (Type D connected at or above 110kV) noting choices are quite limited Apply equivalent for Type B / C and Type D connected below 110kV. Fast Fault Current injection requirements for Power Park Modules to be addressed. Ensure correct industry representation Legal drafting 55

56 Discussion 56