Nordic System Operation Workshop 13 April 2010, Arlanda, Sweden. Reima Päivinen, Fingrid

Transcription

1 Nordic System Operation Workshop 13 April 2010, Arlanda, Sweden Reima Päivinen, Fingrid

2 ENTSO-E: a pan-european TSO platform, fully operational since 1 July 2009 Represents 42 TSOs from 34 countries, responsible for bulk transmission of electric power on main high voltage electricity networks ~500 million citizens served 650 GW generation km V-HV lines km MV-LV lines Demand: TWh/year Exchanges: 300 TWh/year Investments by 2030 for T&D: ~500G Replaces former TSO organisations: ATSOI, BALTSO, ETSO, NORDEL, UCTE, UKTSOA 2

3 Assembly Board Secretariat Legal & Regulatory Group Expert Groups System Development Committee Working Groups Regional Groups System Operations Committee Market Committee European Planning Standards Network Modeling and Data 10 Year Network Develop. Plan Research and Development S. Adequacy & Market Develop. Asset Implem. & Management EWIS Project European Operational Standards Critical Systems Protection Functional Model Incident Classification Scale Operational Reserves Frequency Deviations Electronic Highway Market Integration Ancillary Services Market Information Economic Framework RES EDI Voluntary Regional Groups Northern Europe Isolated Systems North Sea Baltic Sea Continental CE Continental CS Continental SE Continental SW Continental Europe Nordic Baltic Great Britain Ireland - N. Ireland Baltic Sea North West Europe South East Europe 3

4 N O S E F I E E LV I S System Operation is based on synchronous areas more cooperation between areas is needed in the future Regional Group Nordic Regional Group Northern Europe H U D E P L I E N I G B F R E S P T C H IT A U S I A L G R MK R O C Z S K B E N L DK LT B G H R M E B A L U R S C Y 4

5 Electricity Regulation EC/714/2009 Technical & Operational Rules Market Rules Investment & Tariff Rules System Operation Framework Guideline Connection Framework Guideline Balancing Framework Guideline Load-frequency control and reserve power code System operation code Data exchange code Emergency code Connection code Generation and load fault behaviour code... Capacity allocation code Balancing market code... 5

6 Main areas of interest in the Nordic System Operation 'Keep the lights on' Stop the weakening trend of quality of frequency Ensure security of supply in the Nordic grid aug.95 feb.96 aug.96 feb.97 aug.97 feb.98 aug.98 feb.99 aug.99 feb.00 aug feb 01.aug 02.feb 02.aug 03.feb 03.aug 04.feb 04.aug 05.feb 05.aug 06.feb 06.aug 07.feb 07.aug 08.feb 08.aug 09.feb 09.aug 10.feb Number of incidents per month Nordic Frequency Quality 1995 to

7 Programme 9.30 Coffee Welcome speech Reima Päivinen, Fingrid, Chairman of RGN Part 1 Nordic balance and frequency control Current balancing and frequency control practises Christer Bäck, Svenska Kraftnät Future challenges of power system operation Ole Jan Olesen, Energinet.dk Questions & debate Part 2 Planned actions to improve frequency control Quarterly planning and Gate Closure for production plans and balancing bids Gunnar Nilssen, Statnett Questions & debate Lunch hosted by ENTSO-E 7

8 Programme Part 2 Planned actions to improve frequency control Use of ramping on HVDC links Jyrki Uusitalo, Fingrid Questions & debate Coffee break Secondary reserve - Nordic LFC David Whitley, Statnett Questions & debate Part 3 Stakeholders views Panel discussion of future actions Moderator Øivind Rue, Statnett Panellists will discuss of balancing and frequency control with a specific view on: - Market player's experiences of today's practices - Expectations for future balancing and frequency control measures - Market player's possibilities to support improved balancing and frequency control Concluding remarks by Moderator End of the workshop 8

9 The Nordic System Operation workshop presentations will be available 9

10 Current balancing method's in Nordel area Christer Bäck, Svenska Kraftnät REF - DW SR RGN

11 Balance responsibility Balance responsible parties (BRP s) Company balance on a hourly basis Submit plans to TSO with a 45 min gate closure Energinet.dk Statnett Fingrid Svenska Kraftnät Momentary Nordic balance handled by TSO in co-operation. - Planning on a quarterly basis - Automatic regulation - Manually regulations - Exchange of balanspower Nordel synchronous system in balance? April 14, REF - DW SR RGN

12 Balancing the system MWh/h Consumtion + export / - import Generation Regulating Power Market Hour Fig. Example of generation/consumtion balance

13 Planning table

14 Automatic reserve Primary respons divided into two products Frequency controlled normal operation reserve (FNR) Frequency controlled disturbance reserve (FDR)

15 FNR Nordic requirement is 600 MW (6000 MW/Hz) Has to be activated within 3 min if frequency deviates with +- 0,1 Hz from Hz. Devided between the Nordic TSO s due to last year annual load Sweden 233 MW, Norway 207 MW, Finland 136 MW and Denmark (Zeeland) 24 MW.

16 FDR Nordic requirement depended on N-1m,normally 1000 MW Has to be activated with 50% within 5 sek and in total after 30 sec if frequency drops to 49,5 Hz. Decided on a weekly basis due to current N-1. Normally a nucler power plant (Forsmark 3 or Oskarshamn 3 or a tieline) Devided between the Nordic TSO depended on internal N-1.

17 Manual reserve (secondary respons) Manual reserve, has to be activated with in 15 minutes BRP s submit bids to lokal TSO TSO s forward bids to common Nordic bidladder. Requirements for bids are: minimum 10 MW, marked with price and grid area Restore primary

18 Nordic MOL 18

19 Activation of secondary respons Frequency deviation SN 2.Checking NOIS 1.Telephone call MW up, 100 MW N 50 MW F 50 MW S 50 MW D SvK 2.Checking NOIS Fingrid Energinet.dk MW N MW S MW F 50 MW D Frequency ok

20 The gradient is incresed System stability is simply the balance between changes in load and changes in production. The Nordic TSO have set an operational boundary of 50Hz +/- 0,1 Hz (set before 1970) The technical definition of reserves requirements has not been changed since the large scale studies Requirements for system operation ar not up to date Number of incidents per month Nordic Frequency Quality 1995 to 2010 Trend aug.95 feb.96 aug.96 feb.97 aug.97 feb.98 aug.98 feb.99 aug.99 feb.00 aug feb 01.aug 02.feb 02.aug 03.feb 03.aug 04.feb 04.aug 05.feb 05.aug 06.feb 06.aug 07.feb 07.aug 08.feb 08.aug 09.feb 09.aug 10.feb 20 REF - DW SR project Exec #2

21 Scatter diagram over aggregated deviation for April 2009 (where during the day does deviation occur) Frekvens (Hz) Frekvensavvikelse, april 2009 En punkt för varje mätvärde som är över 50.1 Hz respektive under 49.9 Hz Frekvensen är mätt 1 gång per minut. 50,3 50,25 50,2 50,15 50,1 50, ,95 49,9 49,85 49,8 00:0 0 01:0 0 02:0 0 03:0 0 04:0 0 05:0 0 06:0 0 07:0 0 08:0 0 09:0 0 10:0 0 11:0 0 12:0 0 13:0 0 14:0 0 15:0 0 16:0 0 17:0 0 18:0 0 19:0 0 20:0 0 21:0 0 22:0 0 23:0 0 00:0 0 Tid under dygnet

22 Future challenges of power system operation Nordic System Operation Workshop 13 April 2010, Arlanda, Sweden Ole Jan Olesen, Energinet.dk 22

23 Historic development of the Nordic frequency quality => The operational security has to be improved Introduction of markets and new patterns of productions More HVDC connections and more ramping Number of incidents per month aug.95 feb.96 aug.96 feb.97 aug.97 feb.98 Nordic Frequency Quality 1995 to 2010 Nordic region aug.98 feb.99 aug.99 feb.00 aug feb 01.aug 02.feb 02.aug 03.feb 03.aug 04.feb 04.aug 05.feb 05.aug 06.feb 06.aug 07.feb 07.aug 08.feb 08.aug 09.feb 09.aug 10.feb More complex balancing of the Nordic synchronous area Outdated requirements for frequency controlled reserves Continental European region 23

24 Future development of the conditions for the Nordic balance and frequency control => Challenges to be taken into account More market integration More HVDC connections More renewable production plants More harmonization of rules within and between European regions with different prerequisites 24

25 Planned actions to improve the Nordic balance and frequency control => Principles to be implemented Better operations planning Physical production plans to detail the fulfilment of the hourly energy market schedules within the operating hour Adjustments to smooth out the physical productions within the operating hour Running forecast and adjustment of balances to minimise the need for fast reserves to handle the balancing in the operating hour Better and new balancing tools Automatic secondary reserves to smooth out the frequency within the operating hour 25

26 Planned actions to improve the Nordic balance and frequency control => Functions to be implemented Quarterly planning Better operations planning Gate closure Better operations planning Ramping restriction Smoothing of production plans Secondary reserves Better an new balancing tools The Package 26

27 Q u a r t e r ly p la n n in g a n d G a t e C lo s u r e f o r production plans and balancing bids NORDIC SYSTEM OPERATION WORKSHOP 13 April 2010 Arlanda Sweden Gunnar Nilssen, Statnett

28 Statement The better operations planning, the less reserves (costs) needed to handle the real time operation! Planning: BRPs and TSOs 28

29 Content Balancing models BRP and TSO responsibility Quarterly production plans Alternative models Closing time for Elbas and Gate Closure for production plans and bids to the Regulating Power Market BRP and TSO needs Expected development and consequences More wind production More HVDC-cables More market integration April 14,

30 Models for balancing A varying mixture of emphasize on BRP and TSO responsibilities in different countries in Europe The current Nordic model A general prerequisite that BRPs balance the hourly production plans according obligations A general prerequisite that balancing after Gate Closure is handled by the TSOs. BRP plans are firm. More renewable production (wind), more small scale reserve providers (production, consumption) or other reasons may change the Nordic model in the future 30

31 Some prerequisites for the Nordic region Hourly resolution in the energy market in all countries but the requirements for production plans within the hour are different in all countries Hourly plans Quarterly plans (4 equal values are allowed) Quarterly plans (requirement for different quarterly values) 5-min set-point plan Common gate closure for production plans and bids to the Regulating Power Market but different gate closures in the Elbas market Balancing after gate closures is partly planned actions and partly real time actions Quarterly adjustment of production plans, planned activations in the Regulating Power Market Real time activations in the Regulating Power Market 31

32 Balancing within the hour MW Physical consumption + exchange Quarterly production plan from BRPs Market result production (= consumption + exchange) Hour (n-1) Hour (n) Hour (n+1) 32

33 Requirement for quarterly production plan alt. 1 MW Gate closure for hour (n) P > x MW Hour (n-1) Hour (n) Hour (n+1) 33

34 Requirements for quarterly production plan alt. 2 MW P > x MW P > x MW 100 Hour (n-1) Hour (n) Hour (n+1) 34

35 Model 2 in practice - options MW Thermal production, a large hydro generator or AGC on several generators (minute resolution of plans) smaller generators or 1 large generator with minimum production level Hour (n-1) Hour (n) Hour (n+1) 35

36 Quarterly plans some examples for comparison (1) Model 1 Model 2 36

37 Quarterly plans some examples for comparison (2) Model 1 Model 2 37

38 Evaluation of model 1 and 2 Alternative 1: Does not lead to hourly imbalances for the producers Corresponds better to the variation in the consumption The quarterly plans in hour (n) must be determined before production plans in hour (n+1) are firm Alternative 2: The method will lead to imbalances for the producers (contracts with TSOs) Corresponds better to the ramping on HVDC-connections Can be used also for hourly production plans with only one step Easy to use for both producers and TSOs (?) Feed back indicates that model 2 is preferred. 38

39 Current gate closures Communication to BRPs Communication to TSOs Collocation of national plans/bids Communication to BRPs Rescheduling of plans by BRPs Communication to Scada BRPs Closing time Elbas (Except Norway) GCT plans/bids Hour N-2 Planned production Hour N-1 Quarterly adjustment production 39 Hour N

40 Identified critical issues Too little time available to do needed considerations for BRPs and TSOs after closing time for Elbas partly due to: Too slow communication systems between NPS and BRPs (Elbas) Too slow communication systems between BRPs and TSOs (production plans) Unsatisfactory/time consuming IT-solutions to handle rescheduling at some BRPs Too much manual work with production control at some BRPs 40

41 Intra-day implications on Gate Closure for production plans Objective: Intra-day should be open as close to real-time as possible, limited by time needed by TSOs to assess system security Design must be compatible with system security Do Nordic TSOs need more time to assess system security than continental TSOs? (Answer on next sheet) 41

42 Nordic TSOs need time to assess system security because: A lot of bottlenecks in the Nordic grid on interconnectors and within countries A challenging ramping problem on HVDC-connections for the Nordic area (small system and unfavourable direction of ramping) Hourly settlement period. This means that quarterly imbalances partly is handled by manually activated TSO adjustments before real time. Manual activations for balancing. Slow and too unreliable reserve activations due to a lot of manual actions. An economically efficient but time consuming arrangement for balancing where several TSOs are involved (common bid ladder). Yes (See question on previous sheet) 42

43 Alternative possibilities for gate closures - 1 Harmonize closing time for Elbas to 1 hour before operating hour and keep gate closure time for plans/bids at 45 min before operating hour Pros A compromise between BRP and TSO needs for time to do assessments given 1 hour closing time for Elbas Cons Very short time for assessments for both BRPs and TSOs Some potential bids to the RPM may be lost 43

44 Alternative possibilities for gate closures - 2 Harmonize closing time for Elbas to 1 hour before operating hour and change gate closer for plans/bids to 30 minutes before operating hour Pros The BRP imbalance may be reduced The BRPs will have more time to assess plans and bids Cons Too short time remaining for TSOs to do assessments and planned actions Will lead to increased imbalances due to ramping on HVDC connections and/or need for more automatic reserves The risk for overload in the grid will raise 44

45 Alternative possibilities for gate closures - 3 Harmonize an earlier closing time for Elbas Pros The stress for BRPs will be reduced and consequently the quality of the production plans and bids to the RPM will be raised The stress on TSOs to plan and execute needed actions before real time will be reduced Cons The BRP imbalance will increase (how much?) 45

46 Expected development Substantial increase in trade volumes for BRPs close to operating hour Increased wind production Increased market integration Stronger grid connections (more capacity) including more HVDC-cables More complex planning for BRPs due to shorter time resolutions in markets and plans Quarterly markets and quarterly or maybe even minute based plans Substantial increase in imbalance volumes and need for detailed TSO planning before operating hour More automatic balancing which needs to be scheduled (HVDC, LFC-product) Better and faster IT-solutions will have to be developed 46

47 Concluding remark There will be more time critical planning for both BRPs and TSOs in the future! The sencitivity for market closing time on imbalances must be studied further. Difficult to satisfy both the market and operational needs. 47

48 Use of ramping on HVDC links NORDIC SYSTEM OPERATION WORKSHOP 13 April 2010 Arlanda Sweden Jyrki Uusitalo, Fingrid

49 Change of power flow Small differences in prices create large changes in power flow between synchronous areas Transmission capacity today over 4000 MW to both directions NordPool Spot 50 /MWh NordPool Spot 50 /MWh EEX 49 /MWh EEX 51 /MWh 49

50 System operation challenges Frequency large changes in generation and exchange flow while consumption changes continuously Congestion management - flow changes in fully loaded network corridors Voltage control - changes in flow patterns and reactive power sources Physical and market restrictions needed 50

51 Ramping Change of power flow is restricted Maximum 600 MW change in flow from one hour to the next is applied separately on all HVDC connections Ramping speed 30 MW/minute per cable 6 connections together 180 MW/minute Start and stop 10 minutes before and after hour shift Continental requirement even tighter, 5 minutes before/after 51

52 Ramping restrictions today Ramping restriction is applied between Nordic and Continental synchronous systems Ramping restriction was first implemented 2007 in the Elspot market, Exchange information No. 53/2007 Extended use of ramping on HVDC links NorNed (Netherland-Norway) Skagerrak (Denmark-Norway) & KontiSkan (Denmark-Sweden) Kontek (Denmark-Germany) Baltic Cable (Germany-Sweden) Swepol Link (Poland-Sweden) May 2009 the restriction was implemented also for the Elbas market, Exchange information No. 53/2009 Ramping rules in the Elbas market 52

53 Influence to the market Analysis based on NPS data Kontek Skagerrak KontiSkan Nov Sep 2008 and Jan May Data collection stopped during market coupling Cases without restriction and with ramping 600/800 MW Impact Congestion income Bottleneck hours Area Prices What is the socioeconomic cost? 53

54 Increase of bottleneck hours with different ramping restrictions Kontek Skagerrak Kontiskan 600 MW 2,8 % 3,2 % 3,7 % 800 MW 1,1 % 1,5 % 1,4 % Kontek Skagerrak Kontiskan 600 MW 7,4 % 12,8 % 12,3 % 800 MW 3,2 % 6,9 % 6,0 % 54

55 Impact of ramping restriction to area prices Impact to average area prices (absolute values) 1-9/ /2009 DK1 NO1 SE DK2 0,094 0,007 0,009 0,001 0,190 0,015 0,003 0,001 Average difference during those hours when ramping has influenced 1-9/ /2009 DK1 NO1 SE DK2 1,16 0,10 0,14 0,21 1,09 0,14 0,15 0,24 55

56 Impact to congestion incomes Increase with 600 MW restriction 1283 k Share of total congestion incomes 0,8% Increase with 600 MW restriction k Share of total congestion incomes 8,2% Includes Kontek, Skagerrak and Kontiskan 56

57 Alternative methods Counter trade Counter trade is well suited for the elimination of temporary transmission restrictions or ones with limited size. However, it is not a technically and commercially sensible solution in all circumstances Rules have to agreed with Continental TSOs According to earlier Nordic studies counter trade has an impact on the bidding behaviour and undermines the credibility of the Elspot price. On the other hand there is too low liquidity in the intra-day and balancing markets Counter trade is not an optimal solution and currently not relevant as an alternative 57

58 Alternative methods - Increased automatic reserves Increased volume of reserve automatic reserves (LFC) will make it possible to reduce the current restriction Costs for reserves seems to be higher than the current market costs associated to ramping restriction Capacity out of the energy market 58

59 Long term alternative methods Longer timeframes for changes Start and stop 15 minutes before/after hour shift Better compatibility with consumption changes Increases imbalance energy compared to market schedules Quarterly settlement. Physical imbalances between consumption and production/exchange will be reduced Requires more comprehensive settlement procedures, new metering and IT-systems 59

60 Conclusion Way Forward Today's practise most feasible Counter trade is not an optimal solution Impact of the new cables has to be analysed This may change in the future More automatic reserves (LFC) Quarterly production plans, development of control systems, development of exchange rules and quarterly settlement, will make it possible to reduce the restrictions in the future. Further evaluation needed, if an optimisation procedure could be introduced in the Elspot algorithms 60

61 Secondary reserves Nordic LFC NORDIC SYSTEM OPERATION WORKSHOP 13 April 2010 Arlanda Sweden Author : D.Whitley - Statnett

62 Contents Current philosophy and reserve toolbox 3 Why is secondary reserve better than primary 4 Load Frequency Control 5 Overall design 6 Common needs 7 Common problem 8 Secondary Reserve simulation 9 Pilot progress 10 Timeline for introduction 11 Summary 12 April 14, REF - DW ETSOE SR workshop

63 Current philosophy and reserves toolbox Nordic - now Frequency (Hz) Continental UCTE Europe Frequency (Hz) MW Imbalance TR manual activation MW Imbalance TR manual activation PR SR Tertiary Reserve (TR) PR SR Tertiary Reserve (TR) Sec Sec April 14, 2010 REF - DW ETSOE SR workshop 63

64 Why is SR better than more PR Secondary reserve (SR) returns the frequency back to 50Hz Secondary reserves handles time correction Secondary reserves handles congestions in the grid but selecting the optimal activation location Secondary reserves can have non-symetrical bids- > 50 Hz -ve P 50 Hz +ve P Revised SR set-point Plan set-point Primary regulation < 50 Hz April 14, REF - DW ETSOE SR workshop

65 LFC introduction Manual activation is not fast enough to maintain frequency quality! LFC enables automatic activation of reserves via a communication link to the GENCO LFC calculates a delta MW required to bring the system back to 50Hz F LFC MW (setpoint) AGC ~ Frequency sampling and smoothing 2 Conversion to MW and PI 3 Set-point added to plan 4 Delta MW delivered to return F to 50Hz April 14, REF - DW SR RGN

66 Overall design Additional Secondary reserves will strengthen frequency stability If 600MW of SR then... NORDIC - PROPOSAL Continental UCTE Europe Freq. 200 MW 400 MW 600 MW 800 MW 1000 MW 1200 MW 1400 MW Freq. 200 MW 400 MW 600 MW 800 MW 1000 MW 1200 MW 1400 MW 1600 MW ,98 SUM = (SR+FNR) 49,98 49,97 49,97 49,96 49,96 49,95 49,95 49,94 49,93 49,92 49,91 Normal Reserves (FNR) Secondary reserves (SR) 49,94 49,93 49,92 49,91 49,90 49,90 April 14, 2010 REF - DW ETSOE SR workshop 66

67 Common problems Technology enables rapid changes in production levels, whilst load changes remain as before. This result is a larger frequency offset from 50 Hz due to poor production load matching Ca Frequency (Hz) 50 Frequency (Hz) MW ~ MW ~ Hour shift T Hour shift T April 14, 2010 REF - DW ETSOE SR workshop 67 * See page 15

68 Common needs Poor frequency quality is a symptom! Increases risk of an major incident when frequency is outside the operating band We need LFC and more automatic reserves Frequency (Hz) MW ~ Hour shift T April 14, 2010 REF - DW ETSOE SR workshop 68 * See page 15

69 System stability with Secondary reserves A typical day with measured frequency and a simulated result with unlimited LFC. Current performance is in grey and with LFC result is in blue*. F in Hz Operating Level HVDC ramping effect * Utilised max +980 and -580 MW 06:00 12:00 18:00 Time (Hours) April 14, 2010 REF - DW ETSOE SR workshop 69

70 Pilot progress LFC functionality implemented in the TSO SCADA system Simulation is completed Two pilot partners have been identified one in Norway and one in Sweden Communication tests complete in Norway Pilot test in Norway will be complete by May Pilot test in Sweden will follow in Q3 April 14, 2010 REF - DW ETSOE SR workshop 70

71 Time-line for introduction A proposal for volume is +/- 600MW (under discussion in ENTSO-E) Product will be a automatically activated reserve from a Load Frequency Control application Implementation planned from autumn 2010 onwards Includes a pre-qualification of providers Experiences from pilot project will be taken into account April 14, 2010 REF - DW ETSOE SR workshop 71

72 Summary The reserve toolkit is no longer enough to stabilize Nordic frequency! LFC is a new type reserves with automatic activation A proposed volume for the Nordic area is +/- 600MW Implementation planned from autumn 2010 onwards April 14, 2010 REF - DW ETSOE SR workshop 72