Transcript Document

Wind in Ireland
Integration and cost
issues
David Milborrow
[email protected]
Author’s previous encounters
in Ireland
• Participated with ESB and other EU utilities in
EC-funded studies of wind impacts c.1988
• Member of Advisory Panel which selected
turbines for Bellacorick, 1990/91
• Invited speaker at IWEA Conference, 1996
• Adviser to developer based in Co Cork on
several windfarms (some now built) since
1994
• No permanent affiliations!
Scope of talk
• Assimilating wind




Issues?
Problems?
Costs?
Limits?
• Extra costs to consumers of adding wind
 Sensitivities?
Very brief economic interlude
• Much interest in “Extra cost of renewables”
• Justified by “External costs” of thermal
sources, esp Global Warming
Wind and the competition
PUBLIC SECTOR
Wind
Offshore
Gas
Coal
Nuclear
PRIVATE SECTOR
Wind
Offshore
Gas
Coal
Nuclear
Minimum
Range
0
20
40
60
80
Generation cost, US$/MWh
Source: Author, Windpower Monthly, January 2004
100
Levelling the playing field
• Generation cost comparisons not the whole
story
• Value of wind = Fuel saving value
+ CAPACITY SAVING value
+ “embedded benefits”
+ “green value”
- costs of backup
• Embedded benefits may be positive or
negative
Who has looked at integration issues?
•
•
•
Ireland
 ESB (1990), CEGB, and other EU utilities, as part of coordinated study
 IWEA, “Geographical dispersion of wind in Ireland”, 1999
 Garrad Hassan “Impacts” study, 2003
 University College, Dublin
UK DTI/Carbon Trust Network Study, Intermittency
Module, has c.40 worldwide refs back to 1980
Grid operators: Eltra, NGT, Nordel, and US utilities
Ireland is different
• Could be first self-contained electricity
system to operate with significant wind input
 Denmark is not isolated, but source of useful
data, as W Denmark system similar in size
 W Denmark currently runs with wind supplying
~20% of consumption
 Ties with neighbours mean that effective wind
supply is about 10% - still respectable!
Integration topics
• Electricity networks
• Behaviour of wind plant
• Assimilating wind into networks
 Storage
 Capacity credit
• Transmission issues
• The future
Electricity systems
Why integrated systems?
•
•
•
•
•
Smoothing
 Demands
 Generation sources
Peak/average
 House: 15
 UK: 1.5
Lower plant margins needed  House: at least 2*peak
Large electricity system: ~1.2* peak
All leads to LEAST COSTS
Benefits of integrated systems
Peak demand/average; plant needs/average
10
8
Plant
6
Peak
4
3
2
1.4
1
1
10
100
1,000
Average demand, MW
10,000
100,000
Lessons from western Denmark
System demand, MW
4,500
EI
4,000
DK
3,500
3,000
2,500
2,000
1,500
0
50
100
150
Time in hours from 1.2.04, 00:00
200
Scheduling errors
Scheduling error, %
4
3
2
1
0
-1
-2
-3
-4
0
5
Source: Electricity Pool
Standard deviation: 1.6%
10
15
20
Day of month (November 1995)
25
30
Coping with demand
variations
• Generator inertia
• Frequency & voltage changes
• Demand management
• Pumped storage
• Spinning reserve
• All can cope with demand increase or
decrease
Wind characteristics
Smoothing makes a difference
Wind output, MW
1,000
Single
farm
800
Distributed
farms
600
400
200
0
0
5
10
15
Time, hours
20
Smoothing of power swings
Time, %
10
1 farm
1
Western
Denmark
0.1
0.01
-100
-50
0
50
Change, % rated capacity
Time interval: 1 hour
100
Impacts of 20% wind
Time, %
30
10
Demand
- wind
3
Demand
1
0.3
0.1
0.03
-400
-200
400
200
0
Intra-hourly load change, MW
600
800
Running electricity systems
• Managing electricity systems is all about
managing risks
• All estimates of uncertainty come with a
range of probabilities, and
• Uncertainty margins do not add
arithmetically – a “sum of squares” law
applies
Estimating the effects of wind
• Establish “demand prediction error” for
electricity system
 UK system, 1 hour ahead, ~ 1.3%, or 400 MW
 Irish system: similar %, ~40 MW
• Estimate “demand prediction” error for wind
 Typically ~3% standard error for distributed
wind, 1 hour ahead, (“persistence” forecast)
• Error with wind, based on “sum of squares”
Costing the effects of wind
• Scheduling error with wind enables extra
reserve capacity needs to be estimated
• Establish cost of extra reserve, based on
 Reduced efficiency of part-loaded plant
 Cost of plant, or,
 Market rates
Extra back-up capacity
Back-up capacity/wind capacity, %
10
Ireland
(Doherty)
8
NREL
Persistence
6
Perfect
4
US (BPA)
Author
Upper
2
0
0
10
20
30
40
Wind capacity/peak demand, %
50
Lower
Extra costs for backup
Cost of extra balancing, $/MWh
5
UK
NGC
4
Ilex
3
PacifiCorp
2
BPA
Max
1
Min
0
EPRI/
Xcel et al
0
2
4
6
Wind Energy penetration, %
8
10
Storage
• "Renewables need storage" ?
 Rather misleading!
• Only the intermittent sources
• "Storage can transform the economics of the
intermittent renewables" ?
• Only if they are very low cost!
• Several studies have concluded that
economics must be studied separately; may
be useful to system, or as reserve
Capacity credits
The “Firm power” issue
+
+
=
?
Capacity credits
• Controversial, despite • Most authoritative studies confirm wind HAS
a capacity credit. Includes Ireland
• Note that definitions a muddle
 Some refer to firm power, some to thermal plant
 Firm power is less than rated capacity –
 For ALL types of plant!!
Evaluating capacity credits
• 2 basic methods:• Establish system LOLP - usually over a year
• Add wind
• Subtract firm power to restore original LOLP
• Or (simplified approach, essentially similar)
• Examine availability of wind at time(s) of
peak demand
Capacity credits depend on:• Amount of wind on system
• Wind speeds
• Wind turbine types
• Winds at time of peak demand
• Utility operating procedures
When “normalised” for differences in wind
speed, good agreement between most
estimates for northern Europe
Capacity credits – EU studies
DE
DK
ES
F
GR
IR
IT
NL
P
UK
Capacity credit/rated power
0.4
0.3
0.2
0.1
0
2
4
6
8
10
12
Energy penetration, %
14
16
Capacity credits for Ireland
Capacity credit/annual capacity factor
1.4
ESB, 1990
4 sites
1.2
1 site
1
UK
0.8
ESB, 2004
0.6
0.4
0
5
10
Wind energy penetration, %
15
Capacity credits: monetary
values
• These depend on:• Alternative thermal plant
• Test discount rates and depreciation times
• CCGT plant now most common thermal
option in EU, costs €500-800/kW
• Capacity valued at €42-83/kW
• No "universal" value
Benefits of distributed
generation
• Reduced losses
• Improved reliability, + technical issues
• Reduced costs if line reinforcements can be
deferred or forgotten
BUT
• Siting is important
• too much DG in remote areas will increase
losses
• or may advance need for line reinforcements
Local issues
• Analysis of Delabole wind farm (UK) by
SWEB showed:-
 No problems with flicker
 Peak demands at local substation coincided with
peak output from wind farm
 Wind farm output "has major influence in
stabilising the 11 kV voltage level"
• Analysis by P G & E also showed benefits
from PV installation
Wind integration – conclusions
• Modest costs for extra reserve
 Most studies yield similar results
• Capacity credits? – Yes, roughly=average
power
• Problem areas?
 May be preferable, once wind input exceeds
~10%, to curtail wind output on a few occasions
• …..but wind will NEVER impose “jolts” on the
system comparable with loss of a circuit of
cross-channel link
Carbon savings from renewables
•
Variety of answers in literature: Due to average emissions from plant mix
 Due to gas plant which will not be built
 Due to emissions from load following (lf) plant
• In daily operations, wind displaces lf plant
• New renewables build forces closure of old thermal
•
•
(usually coal) plant, just as new gas
Gas plant not built? How can you be sure?
So another argument in favour of 600-850g/kWh
from closure of old coal (or oil) plant
Extra costs of renewables
• Increasing interest in “extra costs” as States
define renewable targets
• Estimates of extra costs from various sources
• Author linked to estimate in Power UK, issue
109: ~0.3p/kWh to consumer bills for 20%
wind by 2020
• Key issues: Gas prices by 2020
Wind plant costs
Price of carbon under ETS
Possible future Irish scenarios
System 5000
MW
Wind % 5
5000
5000
6500
6500
6500
10
16
12
20
27
Wind
500
MW
Offshore 25
%
Date
2005
1000
1500
1500
2500
3500
30
40
40
45
50
2008
2010
2010
2017
2025
Source of base data (green): ESBNG; author’s assumptions in red
Future gas prices
Gas price to electricity generators, $/MWh
22
20
18
16
14
12
2000
2005
2010
2015
Year
Source: US DoE, Annual Energy Outlook, 2004
2020
2025
Future wind prices
Installed price, $/kW
1,100
IOWA
Reference
1,000
900
Low
800
700
Trends
continue
600
DEWI
500
400
2000
REPP
2005
2010
Year
2015
2020 EWEA
Possible costs to electricity
consumers of adding wind
Extra cost, €/MWh
1
0.8
0.6
0.4
0.2
0
-0.2
-0.4
-0.6
2005
2010
US DoE gas price trends
No allowance for costs under ETS
2015
Year
2020
2025
Thank you!
The End