Nordic System Operation Workshop
13 April 2010, Arlanda, Sweden
Reima Päivinen, Fingrid
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
230.000 km V-HV lines
1.500.000 km MV-LV lines
Demand: 3.000 TWh/year
Exchanges: 300 TWh/year
Investments by 2030
for T&D: ~500G€
Replaces former TSO organisations:
ATSOI, BALTSO, ETSO, NORDEL,
UCTE, UKTSOA
2
Assembly
System Development
Committee
System Operations
Committee
Market
Committee
Board
Secretariat
Legal & Regulatory
Group
Expert Groups
Working Groups
Regional Groups
• European Planning Standards
• Network Modeling and Data
• 10 Year Network Develop. Plan
• Research and Development
• S. Adequacy & Market Develop.
• Asset Implem. & Management
• EWIS Project
• North Sea
• Baltic Sea
• Continental CE
• Continental CS
• Continental SE
• Continental SW
• 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
• Continental Europe
• Nordic
• Baltic
• Great Britain
• Ireland - N. Ireland
• Baltic Sea
• North West Europe
• South East Europe
3
System Operation is
based on synchronous
areas – more cooperation
between areas is needed
in the future
Regional Group
Nordic
I
S
F
I
N
O
I
E
S
E
LT
DK
N
I
G
B
N
B L
E
F
R
P
L
D
E
C
Z
L
U
A
US
I
C
H
IT
P
T
E
S
Regional Group
Northern Europe
E
E
LV
H
R
S
K
H
U
B
A
R
O
R
S
M
E
B
G
MK
A
L
G
R
4
C
Y
...
Connection Framework Guideline
Balancing market code
Market Rules
Capacity allocation code
...
System Operation Framework Guideline
Generation and load
fault behaviour code
Technical & Operational Rules
Connection code
Emergency code
Data exchange code
System operation code
Load-frequency control
and reserve power code
Electricity Regulation EC/714/2009
Investment & Tariff Rules
Balancing Framework Guideline
5
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
Number of incidents
per month
Nordic Frequency Quality 1995 to 2010
1000
900
800
700
600
500
400
300
200
100
10.feb
09.aug
09.feb
08.aug
08.feb
07.aug
07.feb
06.aug
06.feb
05.aug
05.feb
04.aug
04.feb
03.aug
03.feb
02.aug
02.feb
01.aug
01.feb
aug.00
feb.00
aug.99
feb.99
aug.98
feb.98
aug.97
feb.97
aug.96
feb.96
0
aug.95
•
•
•
6
Programme
9.30
Coffee
10.00
Welcome speech
Reima Päivinen, Fingrid, Chairman of RGN
Part 1
10.15
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
11.00
Planned actions to improve frequency control
Quarterly planning and Gate Closure for production plans and
balancing bids
Gunnar Nilssen, Statnett
Questions & debate
12.00
Lunch hosted by ENTSO-E
7
Programme
Part 2
13.00
Planned actions to improve frequency control
Use of ramping on HVDC links
Jyrki Uusitalo, Fingrid
Questions & debate
14.00
Coffee break
14.20
Secondary reserve - Nordic LFC
David Whitley, Statnett
Questions & debate
Part 3
Stakeholders views
15.00
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
16.00
End of the workshop
8
The Nordic System Operation workshop presentations will be
available
http://www.entsoe.eu/index.php?id=63
www.entsoe.eu
9
Current balancing method's in Nordel area
Christer Bäck, Svenska Kraftnät
REF - DW 20100308 SR RGN
Balance responsibility
Balance responsible parties (BRP´s)
Company balance on a hourly basis
Submit plans to TSO with a 45 min gate
closure
Momentary Nordic balance
handled by TSO in co-operation.
- Planning on a quarterly basis
Energinet.dk
Statnett
Fingrid
Svenska Kraftnät - Automatic regulation
- Manually regulations
- Exchange of balanspower
Nordel synchronous system in
balance ?
April 14, 2010
REF - DW 20100303 SR RGN
11
Balancing the system
MWh/h
20 500
20 000
19 500
19 000
18 500
18 000
17 500
17 000
16 500
16 000
15 500
Consumtion + export / - import
Generation
Regulating Power Market
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour
Fig. Example of generation/consumtion balance
Planning table
Automatic reserve
Primary respons divided into two products
• Frequency controlled normal operation reserve (FNR)
• Frequency controlled disturbance reserve (FDR)
FNR
• Nordic requirement is 600 MW (6000 MW/Hz)
• Has to be activated within 3 min if frequency deviates
with +- 0,1 Hz from 50.00 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.
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.
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
Nordic MOL
18
Activation of secondary respons
Frequency
deviation
SN
1.Telephone call
2.Checking
NOIS
SvK
2.Checking
NOIS
Fingrid
Energinet.dk
3. 250 MW up,
100 MW N
50 MW F
50 MW S
50 MW D
4. 100 MW N
4. 50 MW S
Frequency ok
4. 50 MW F
50 MW D
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 1982-5.
Requirements for system operation ar not up to date
Number of incidents
per month
Nordic Frequency Quality 1995 to 2010
1000
Trend
900
800
700
600
500
400
300
200
100
20
10.feb
09.aug
09.feb
08.aug
08.feb
07.aug
07.feb
06.aug
06.feb
05.aug
05.feb
04.aug
04.feb
03.aug
03.feb
02.aug
02.feb
01.aug
01.feb
aug.00
feb.00
aug.99
feb.99
aug.98
feb.98
aug.97
feb.97
aug.96
feb.96
aug.95
0
REF - DW 20100308 SR project Exec #2
Scatter diagram over aggregated deviation for April 2009
(where during the day does deviation occur)
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.
Frekvens (Hz)
50,3
50,25
50,2
50,15
50,1
50,05
50
49,95
49,9
49,85
49,8
00:0 01:0 02:0 03:0 04:0 05:0 06:0 07:0 08:0 09:0 10:0 11:0 12:0 13:0 14:0 15:0 16:0 17:0 18:0 19:0 20:0 21:0 22:0 23:0 00:0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Tid under dygnet
Future challenges of power system operation
Nordic System Operation Workshop
13 April 2010, Arlanda, Sweden
Ole Jan Olesen, Energinet.dk
22
Historic development of the Nordic frequency quality
=> The operational security has to be improved
Nordic region
Number of incidents
per month
• Introduction of markets and new
patterns of productions
Nordic Frequency Quality 1995 to 2010
1000
900
800
700
600
500
400
300
200
100
10.f eb
09.f eb
09.aug
08.f eb
08.aug
07.f eb
07.aug
06.f eb
06.aug
05.f eb
05.aug
04.f eb
04.aug
03.f eb
03.aug
02.f eb
02.aug
01.f eb
01.aug
f eb.00
aug.00
f eb.99
aug.99
f eb.98
aug.98
f eb.97
aug.97
f eb.96
aug.96
0
aug.95
• More HVDC connections and
more ramping
• More complex balancing of the
Nordic synchronous area
• Outdated requirements for
frequency controlled reserves
Continental European region
23
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
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
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
Q u a r te r ly p la n n in g a n d G a te C lo s u r e fo r
production plans and balancing bids
NORDIC SYSTEM OPERATION WORKSHOP
13 April 2010 – Arlanda Sweden
Gunnar Nilssen, Statnett
Statement
The better operations planning, the less reserves (costs) needed
to handle the real time operation!
Planning: BRPs and TSOs
28
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, 2010
29
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
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
Balancing within the hour
MW
Physical
consumption +
exchange
40500
40000
Market result
production
(= consumption + exchange)
30500
30000
Quarterly
production plan
from BRPs
20500
20000
Hour (n-1)
Hour (n)
Hour (n+1)
32
Requirement for quarterly production plan – alt. 1
MW
600
500
Gate closure
for hour (n)
∆P > x MW
400
300
200
100
Hour (n-1)
Hour (n)
Hour (n+1)
33
Requirements for quarterly production plan – alt. 2
MW
600
∆P > x MW
500
400
300
∆P > x MW
200
100
Hour (n-1)
Hour (n)
Hour (n+1)
34
Model 2 in practice - options
MW
350
Thermal production,
a large hydro generator or
AGC on several generators
(minute resolution of plans)
300
250
200
2 smaller generators
or 1 large generator
with minimum production
level
150
100
Hour (n-1)
Hour (n)
Hour (n+1)
35
Quarterly plans – some examples for comparison (1)
Model 1
Model 2
36
Quarterly plans – some examples for comparison (2)
Model 1
Model 2
37
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
Closing time
Elbas
(Except
Norway)
Hour
N-2
Planned production
GCT plans/bids
Communication to Scada BRPs
Rescheduling of plans by BRPs
Communication to BRPs
Collocation of national plans/bids
Communication to TSOs
Communication to BRPs
Current gate closures
Quarterly
adjustment
production
Hour
N-1
Hour
N
39
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
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
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
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
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
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
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
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
Use of ramping on HVDC links
NORDIC SYSTEM OPERATION WORKSHOP
13 April 2010 – Arlanda Sweden
Jyrki Uusitalo, Fingrid
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
EEX 49 €/MWh
NordPool Spot 50 €/MWh
EEX 51 €/MWh
49
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
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
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
Influence to the market
• Analysis based on NPS data
•
•
•
Kontek
Skagerrak
KontiSkan
• Nov 2007- Sep 2008 and Jan – May 2009. 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
Increase of bottleneck hours with different ramping
restrictions
1.11.2007 – 29.9.2008
Kontek
Skagerrak
Kontiskan
600 MW
2,8 %
3,2 %
3,7 %
800 MW
1,1 %
1,5 %
1,4 %
1.1.2009 - 31.5.2009
Kontek
Skagerrak
Kontiskan
600 MW
7,4 %
12,8 %
12,3 %
800 MW
3,2 %
6,9 %
6,0 %
54
Impact of ramping restriction to area prices
Impact to average area prices (absolute values)
1-9/2008
1-5/2009
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
1-9/2008
1-5/2009
DK1
NO1
SE
DK2
1,16 €
0,10 €
0,14 €
0,21 €
1,09 €
0,14 €
0,15 €
0,24 €
55
Impact to congestion incomes
1.11.2007 – 29.9.2008
Increase with 600 MW restriction
1283 k€
Share of total congestion incomes
0,8%
1.1.2009 - 31.5.2009
Increase with 600 MW restriction
1 517 k€
Share of total congestion incomes
8,2%
Includes Kontek, Skagerrak and Kontiskan
56
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
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
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
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
Secondary reserves – Nordic LFC
NORDIC SYSTEM OPERATION WORKSHOP
13 April 2010 – Arlanda Sweden
Author : D.Whitley - Statnett
Contents
•
•
•
•
•
•
•
•
•
•
Current philosophy and reserve toolbox
Why is secondary reserve better than primary
Load Frequency Control
Overall design
Common needs
Common problem
Secondary Reserve simulation
Pilot progress
Timeline for introduction
Summary
April 14, 2010
3
4
5
6
7
8
9
10
11
12
REF - DW 20100413 ETSOE SR workshop
62
Current philosophy and reserves toolbox
Nordic - now
Continental
Europe
UCTE
Frequency (Hz)
Frequency (Hz)
60
April 14, 2010
TR manual
activation
Imbalance
Imbalance
SR
PR
0
MW
TR manual
activation
MW
Tertiary Reserve
(TR)
900
PR
Sec
0
SR
60
Tertiary Reserve
(TR)
900
Sec
REF - DW 20100413 ETSOE SR workshop
63
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
Revised SR
set-point
+ve ∆ P
50 Hz
Plan set-point
Primary regulation
< 50 Hz
April 14, 2010
REF - DW 20100413 ETSOE SR workshop
64
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 -
50
1
49.99
2
3
4
49.98
∆ MW (setpoint)
49.97
49.96
∆F
49.95
LFC
AGC
~
49.94
49.93
1 – 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
49.92
49.91
49.9
1400
1500
April 14, 2010
1600
1700
1800
1900
2000
REF - DW 20100303 SR RGN
65
Overall design
Additional Secondary reserves will strengthen frequency stability
If 600MW of SR then…....
50.00
50.00
49.99
49.99
SUM = (SR+FNR)
49,98
49,97
49,96
49,96
49,95
49,95
Secondary
reserves
(SR)
49,93
49,92
49,91
Normal
Reserves
(FNR)
49,90
April 14, 2010
1600 MW
1400 MW
1200 MW
1000 MW
800 MW
49,98
49,97
49,94
600 MW
Freq.
400 MW
1400 MW
1200 MW
Continental
Europe
UCTE
1000 MW
800 MW
600 MW
400 MW
Freq.
200 MW
NORDIC - PROPOSAL
200 MW
49,94
49,93
49,92
49,91
49,90
REF - DW 20100413 ETSOE SR workshop
66
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. 1990
2010
Frequency (Hz)
Frequency (Hz)
50
50
MW
MW
~
Hour shift
April 14, 2010
* See page 15
~
T
Hour shift
REF - DW 20100413 ETSOE SR workshop
T
67
Common needs
Poor frequency quality is a symptom!
Increases risk of an major incident when
frequency is outside the operating band
2010
We need LFC and more automatic reserves
Frequency (Hz)
50
MW
~
Hour shift
April 14, 2010
* See page 15
REF - DW 20100413 ETSOE SR workshop
T
68
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
50.1
50.05
Operating
Level
50
49.95
49.9
HVDC ramping
effect
49.85
49.8
0
1
* Utilised max +980 and -580 MW
April 14, 2010
2
06:00
3
4
5
12:00
6
7
18:00
8
Time (Hours)
REF - DW 20100413 ETSOE SR workshop
69
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 20100413 ETSOE SR workshop
70
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 20100413 ETSOE SR workshop
71
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 20100413 ETSOE SR workshop
72