24-Month Reliability Outlook 2011-2013 Stakeholder Information Session Monday, March 5, 2012

24-Month Reliability Outlook
2011-2013
Stakeholder Information Session
Monday, March 5, 2012
John Kehler, Steve Heidt and Sami Abdulsalam
Agenda
• Introductions
• Reliability
• System Performance
• Criteria and Coordination Plan
• Regional Update
• Summary
• Q&A
2
Role of Alberta Electric System Operator
(AESO)
• System Operations
– Direct the reliable operation of Alberta’s power grid
• Markets
– Develop and operate Alberta’s real-time wholesale energy
market to facilitate fair, efficient and open competition
• Transmission System Development
– Plan and develop Alberta’s transmission system to ensure
continued reliability and facilitate the competitive market and
investment in new supply
• Transmission System Access
– Provide system access for both generation and load customers
3
The Alberta Grid
• 22,322 km transmission
• Single balancing area of
660,000 km²
• B.C. & Sask. Connections
• over 167 generating units
• 10,609 MW system peak
• 164 market participants
• 13,888 MW internal capacity
net to grid
4
Reliability
• “The System”
– is controlled to stay within acceptable limits during normal
conditions
– performs acceptably after credible contingencies
– limits the impact and scope of instability and cascading
outages when they occur
– facilities are protected from unacceptable damage by operating
them within facility ratings
– integrity can be restored promptly if it is lost, and
– has the ability to supply the aggregate electric power and
energy requirements of the electricity consumers at all times,
taking into account scheduled and reasonably expected
unscheduled outages of system components”
5
System Performance
John Kehler
Transmission System Performance
• Transmission Lines
– Reliability, Operational Efficiency and Market Efficiency
Through Availability of the Transmission System
– Transmission line outages (planned or unplanned) can lead
to constraints and curtailment
– Performance can be assessed by statistics and benchmarking
• System Events
– The analysis and investigations of events often leads to
lessons learned and recommendations to improve the
performance of the power system
7
Key System Performance Metrics
Transmission system
frequency and duration of
unplanned outages
Frequency and
Duration to Generation
Customers (Curtailed
Generation)
Frequency, Duration and Restoration to Load Customers (SAIFI and SAIDI)
8
Terminology Used in this Presentation
• Outage - This is when a transmission line is forced out of service
• Interruption - This is when an Outage effects a point of delivery or load customer
• Event – This is when a transmission constraint caused by either; transmission
outages
or normal conditions where transmission overloads have occurred due to generation
and load conditions
• Delivery Point - This is the Point of Delivery from the transmission system to a DTS
customer of the AESO
• Frequency Per 100 km is the [number of outages] divided by the [kilometer years
which
in turn are divided by 100]
• SARI System Average Restoration Index - A measure of the average duration of a
Delivery Point interruption. It represents the average restoration time for each Delivery
Point interruption
• SAIFI System Average Interruption Frequency Index - A measure of the average
number
of momentary plus sustained interruptions that a Delivery Point experiences during a
given year
• SAIDI System Average Interruption Duration Index - A measure of the average total
interruption that a Delivery Point experiences during a given year
9
Number (Frequency) of Unplanned Outages
12
Alberta
Alberta
CEA
CEA
6
138/144 kV Alberta and CEA
Frequency Per 100 km
Frequency / Year
Frequency /Year
69/72 kV Alberta and CEA
Frequency Per 100 km
0
12
6
Alberta
Alberta CEA
0
2005-2009
2006-2010
2005-2009
5 Year Rolling Window
6
Alberta
CEA
CEA
Alberta
0
500 kV Alberta and CEA
Frequency Per 100 km
Frequency / Year
12
2006-2010
5 Year Rolling Window
240 kV Alberta and CEA
Frequency Per 100 km
Frequency / Year
CEA
12
Alberta
Alberta
6
CEA
CEA
0
2005-2009
2006-2010
5 Year Rolling Window
2005-2009
2006-2010
5 Year Rolling Window
10
Average Outage Duration
138/144 kV Alberta and CEA
Average Outage Duration
69/72 kV Alberta and CEA
Average Outage Duration
80
80
CEA
40
Alberta CEA
Hours
Hours
CEA
Alberta
40
Alberta CEA
Alberta
0
0
2005-2009
2005-2009
2006-2010
5 Year Rolling Window
5 Year Rolling Window
240 kV Alberta and CEA
Average Outage Duration
500 kV Alberta and CEA
Average Outage Duration
80
CEA
40
Alberta CEA
Alberta
Hours
80
Hours
2006-2010
40
Alberta
CEA
Alberta
CEA
0
0
2005-2009
2006-2010
5 Year Rolling Window
2005-2009
2006-2010
5 Year Rolling Window
11
Impact to Delivery Points and Load for
Unplanned Outages
69, 72, 138, 144, 240 and 500 kV Systems
5.0
2.5
CEA
Alberta
CEA
Alberta
Duration (Hours)
Frequency
5.0
2.5
Alberta
CEA
Alberta
CEA
0.0
0.0
2005-2009 2006-2010
5 Year Rolling Window
2005-2009 2006-2010
5 Year Rolling Window
Alberta Delivery Point SARI
Restoration Time (Hours)
Alberta Delivery Point SAIDI
Alberta SAIFI
5.0
Alberta
Alberta
2.5
CEA
CEA
0.0
2005-2009
2006-2010
5 Year Rolling Window
12
Grid and Market Operation Performance with
Transmission System Planned and Unplanned Outages
Annual Generation
Curtailment (GWh) Due to
Transmission Constraints
Number of Transmission
Constraint Events (Planned
and Unplanned) Per Year
1000
100
8000
# of Hours
GWhs
200
# of Events
Annual Duration (Hours)
500
0
0
0
2008 2009 2010 2011
4000
2008 2009 2010 2011
2008 2009 2010 2011
• The numbers of transmission constraint events is down from 2011, hours where generation
curtailment occurred are down and curtailed generation volumes (GWhs) are down
• 2010 had major transmission lines out of service due to damage caused by storms
13
System Performance
Constraint History- Fort McMurray Cutplane
Fort McMurray Congestion
Metrics
Hrs Per Year / Events Per
Year
1500
990
1000
500
769
438
3
670
438
2
8
41
7
0
2007
2008
2009
2010
2011
Area Limited due to Planned or Forced Outages
Events where Facilities Constrained
14
System Performance
Constraint History - KEG Area
KEG Congestion Metrics
Hrs Per Year / Events Per
Year
1500
1121
1000
461
500
0 1
0 1
2007
2008
180
2
18
2
0
2009
2010
2011
Area Limited due to Planned or Forced
Outages
Events where Facilities Constrained
15
System Performance
Constraint History – South of KEG (SOK)
Hrs Per Year / Events Per Year
SOK Congestion Metrics
6000
4871
4000
2000
1410
526
613
591
3
1
1
8
0
2007
2008
2009
2010
2011
0
Area Limited due to Planned or Forced Outages
Events where Facilities Constrained
4871 hours of congestion primarily due to 928L outage
16
System Performance
Constraint History - Southwest Area
Hrs Per Year / Events Per Year
Southwest Congestion Metrics
1487
1500
1223
968
1000
800
500
100
24
89
92
105
72
0
2007
2008
2009
2010
2011
Area Limited due to Planned or Forced Outages
Events where Facilities Constrained
17
System Performance
Constraint History - South East Area
South East Congestion Metrics
Hrs Per Year / Events Per Year
1500
1096
1000
500
0 0
0 0
0 0
1
58 6
2007
2008
2009
2010
2011
0
Area Limited due to Planned or Forced Outages
Events where Facilities Constrained
18
Transmission-must-run
Northwest Rainbow Lake Area
TMR expected to reduce with completion of
Northwest transmission upgrades in 2013
Northwest Grande Prairie Area
Operating as a cutplane under new Rule 302.4
with associate ID # 2011-004(R)
Calgary Area
Minimum = 125 MW when SVC out of service
or congestion on SOK path
19
TMR MWh Usage History for Different Areas
of Alberta
Rainbow Lake Area
Calgary Area
Grande Prairie Area
NE Region
1000
GWhr
750
500
250
0
2006
2007
2008
2009
2010
2011
Year
AESO 2011 Market Statistics
20
Performance During Major System
Disturbances
• No major disturbances for Alberta in 2011
• 2010 Major Disturbances
– March 1 - Northwest Outage
– June 1 – Under Frequency Event
– June 30 – Loss of Load
– April 8 – Snow storm
– April 14 - Snow storm
• Disturbance recommendations for the March 1 2010 AIES
Disturbances are finalized in Alberta and are in the process
of being closed off with WECC
21
Criteria and Coordination Plan
Steve Heidt
Preparing for Next Contingency
Normal State
(Prepared
System)
Contingency
Meets
Performance
Criteria
System in normal state
must sustain next
contingency and meet the
performance criteria; not
just operate within limits in
normal state
Prepare system for
Next contingency
System
Ready for
Next
Contingency
Contingency
Meets
Performance
Criteria
23
Outage Coordination (within 7 days)
• Objective is to maintain reliable operation
• TFOs and GFOs are required to submit planned outages to
the AESO which includes construction outages
• AESO Approved transmission outages are published on our
website
• On a week ahead basis, AESO performs operational studies
considering
– Outage schedules for each day
– Short term load forecast and known generation status
• In consultation with TFOs, AESO develops procedures for
the real time operators to manage constraints as required
24
Transmission Planning Regions
Northeast
Northwest
2011 Load
10%
2011 Capacity
7%
2011 Load
23%
2011 Capacity
22%
Edmonton
Central
2011 Load
15%
2011 Capacity
14%
2011 Load
20%
2011 Capacity
36%
South
2011 Load
28%
2011 Capacity
22%
Percentages of:
2011 year-to-date winter season peak – 10,609 MW
Installed capacity as of end of 2011 – 13,659 MW
25
Regional Update
South / Central
Operations planning and Transmission Development
Steve Heidt
Interties Capacity
• AB-BC PATH
• AB-SASK PATH
– One 500 kV and
two 138 kV lines
– Back to back
AC/DC Converter
– Transfer Capability
– Intertie capability
is restored to 150
MW in both
directions
– Export 800 MW
– Import 780 MW
• Implementation of
Load Shed Service
import (LSSi) program
is in progress
• MATL
– 300 MW design capability
– Total Transfer Capability (TTC)
limits for various operating
conditions are being studied
27
South Region
• Thermal and voltage constraints in
the west and east area
• SATR and FATD will address most of
the challenges
• 786L overloads will be mitigated by
the phase shift transformer Q1 2012
• NID for upgrading the North of
Calgary system is in progress
• Four 138 kV cables replaced to
mitigate thermal constraint in the
Calgary Downtown core
• AESO is developing plans in the short
and long term to address reliability
concerns north and south Calgary
and Airdrie areas
28
South Region - Southwest Area
• Thermally limited area
• Flow is out of the area; depends on
wind generation
• Russell phase shift transformer is
being commissioned and will mitigate
786L overloads
• Remaining constraints will be mitigated
by SATR related developments as these
come on line in stages
• As expected, frequency and MWh of wind
generation curtailment are down in 2011
compared to 2010
29
South Region - Southeast Area
• The area is thermally, voltage limited,
and angular stability limited
• The two 240 kV three terminal lines
were converted to 3-2 terminal lines
with Milo Junction upgrade
• Procedure in place to manage reliability
of the south of Anderson (SOA)
cutplane
30
South Region
Calgary and Surrounding Areas
• Calgary system is thermally constrained
• Typically MW flow is into the area
• Area operation managed through
specific limits
– Path 1 limits
– SOK limits
– Dynamic VAr requirements and monitoring
• Under Voltage Load Shedding scheme
• Four 138 kV cables replaced to mitigate
thermal constraint in the Calgary
Downtown
core
• AESO is developing plans in the short
and long term to address area reliability
concerns in south and north Calgary and
Airdrie areas
31
Central Region
• Voltage and thermal constraints in
the central and east areas of the region
• Yellowhead area NID competed that
alleviated voltage and thermal constraints
of the area
• Central East upgrade NID approved in
2011
• Filed NID for the Red Deer area
development plans July 2011 to
address voltage and thermal constraints
in the area
32
Central Region – Yellowhead Area
• Thermal and voltage constraints
• Commissioned 4 capacitor banks
and 138 kV lines upgrades in 2011
to remove thermal and voltage
constraints
33
Central Region
Red Deer and Joffre Areas
• Thermally limited for outflow and
voltage for inflow
• NID filed in July 2011 to mitigate
thermal and voltage constraints
34
Central Region – Central East
• Large geographic area that is has weak
transmission support
• Voltage and thermal limitations during
single element outage
• AUC Approved Central East NID in Q1
2011. Staged completion is expected
from 2012 to 2017
• Includes new 240 kV connections to
Hardisty area and south of Monitor in the
Hanna area to provide area reinforcement
• Cold Lake area reinforcements include
new 240/144kV substation and 240kV lines
connecting to Marguerite Lake and
Bonnyville. Thermal protection RAS to be
removed
• Area operation is currently managed through
the weekly coordination plans
35
Central Region - Hanna Area
• Southeast system is constrained by
voltage and dynamic stability
• Hanna Region NID developments
are expected to be complete by
Q2 2013 that will remove most of
the constraints and allow wind
connections
36
Regional Update
Northwest, Northeast and Edmonton
Operations Planning and Transmission Development
Sami Abdulsalam
North Region
• NW
– Voltage stability, angular stability and thermally
constrained area
– Region is dependent on local generation (TMR)
to supply load
• NE
– Ft Mac operates to a cutplane
– Significant industrial load and base loaded
co-generation
– Expect over 500 MW growth in load over the
two (2) years
– 250-500MWs of Generation growth expected in
the region by end of 2014
• Edmonton Area
– Limits are based on thermal, angular and voltage
stability
– Bulk system is approaching capacity limit
– Sundance 1 and 2 off-line since Jan 2011
38
Edmonton Region – Wabamun Area
• Transmission system operating at its
limit
• Current limits are based on thermal,
angular and voltage stability
• One transmission facility outage requires
significant generation curtailment
• 4,035 MW of base loaded coal generation
in KEG
– Keephills Plant 1,230 MW (9.2%)
– Genesee Plant 1,230 MW (9.2%)
– Sundance plant 1,575 MW (11.7%)
• Keephills 3 Energized
39
Edmonton Area Debottlenecking Project &
KH3 Interconnection Update
• Upgrades
– Protection upgrades are complete
– KH phase shifter energized
– Livock PST to be energized in Dec-2012
– 500 kV and 240 kV upgrades and line configurations are in
progress and will be complete in 2013
• Completion of the 240 kV line re-configurations and
upgrades by 2012/2013 will result in
– Mitigation of dynamic stability concerns in the area
– Alleviation of congestion in the KEG loop and system between
Sundance Plant and Edmonton area
40
North - South Bulk Transmission
(Edmonton to Calgary)
• Transfer limits (Operational Definition):
– Summer = 2,050 MW
– Winter = 2,150 MW
– Limitation angular stability and thermal (138 kV
overloads)
• Maximum north to south flow range 1,601 to
2,202 MWs over the last three years
41
Northeast Region - Fort McMurray area
• Constraints are a result of both generation
and load
• Current FMM cutplane limits are
575 MW out and 300 MW in
• Transmission upgrades by 2012
– 260 MVAr capacitor banks
• Will increase inflow and outflow limits
• AESO studies will determine operating
limits
– 144kV System Reinforcement
• ~ 630MWs out and ~ 440 MWs in after
planned developments completion
42
Northeast Region - Cold Lake Area
• Constraints are a result of both
generation and load
• Increase in the area generation and
load relating to oil sands and pipeline
facilities
• Central East Transmission Development
will help alleviate constraints in this area
– New 240/144kV substation close to
existing Mahihkan substation.
– New 240kV lines (operated at 144kV)
connecting the new 240kV sub to
existing Marguerite Lake and
Bonnyville Substations
– Remove existing thermal RAS
43
Northeast Region - Fort Saskatchewan Area
• Heartland Transmission Development
– Support local demand
– Accommodate growing demand in
northeastern Alberta including
Fort McMurray from oilsands
development and pipelines
– Support the backbone of the province’s
transmission system
– Facility application Approved by the
commission 2011
44
Northwest Region Updates
• Voltage stability, angular stability and
thermally constrained area
• Region is dependant on local
generation (TMR) to supply load
• NW Transmission Development
project in progress
– Completed developments in 2011-2012
• Three 144 kV lines in Rainbow Lake area
• One SVC & one capacitor bank at a new
substation
– To be energized in 2013
• One synchronous condenser at Arcenciel
• TMR Reduction in the Rainbow lake
area in 2012 which will further reduce
after energization of the Synch
Condenser
45
Summary and Conclusions
John Kehler
Completed Transmission Upgrades and
Development
• South
– Calgary area: 138 kV downtown cables
– The two 240 kV three terminal lines were
converted to 3-2 terminal lines with Milo
Junction upgrade
– New capacitor banks in the central east
• North
– Yellowhead: 4 capacitor banks, 138 kV
line upgrades
– Northwest: 144 kV line upgrades,
2-SVCs, Capacitor bank
– Capacitor Bank in the Athabaska area
– Keephills 3
– Keephills: Phase Shift Transformer
• Intertie Restoration – LSSi
47
Transmission Upgrades and Development in
Progress
• NW: Synchronous Condenser
• Ft McMurray: Capacitor bank,
144kV line upgrades
• Russell Phase Shift Transformer
• MATL
• KEG Debottlenecking
• System NIDs
– Approved
• Central East
• Heartland
• Hanna
– Filed
•
•
•
•
Red Deer
South of Calgary
Christina Lake System Development
Northeast Fort MacMurray
Transmission Development
48
Conclusions
• System upgrades some are in and more are coming
• Reduced curtailment in 2011
• System will continue to be reliable and well managed
over the next 24 months
49
QUESTIONS
Thank you