Muja Transformer Failure Market Impact Review 9 Oct 2014

Muja Transformer Failure
Market Impact Review – Final Update
Martin Maticka
Group Manager, Operations and Technology
9 October 2014
Background and Timeline
Activities Since February
Market Impact
Summary
2
Timeline – Muja Bus Tie Transformer (BTT) Failures
2012
2014
SEP 2012
BTT1 Failed
Replacement Delayed
March
July
FEB 2014
BTT1 Replacement Delayed
BTT2 Failed - BTT3 Single Contingency
Dispatch of 2 Vinalco Units
May
April
February
June
APR-MAY 2014
JUN 2014
Alinta Pinjarra 1 on Planned Outage
Worsley Cogen on Planned Outage
Worsley Cogen on Planned Outage
3 Vinalco Units Running
August
September
October
JUL 2014
AUG-SEP 2014
28 SEP 2014
Kemerton Line
Commissioned
1 Vinalco Unit Running
Alinta Pinjarra 1 on Planned Outage
Replacement MT-BTTU Commissioned
Vinalco no longer dispatched out of merit
Source: Diagram by IMO
3
Background – Bus Tie Transformer (BTT) Failures at Muja
To Guildford Load Area
To Bunbury and Southern
Terminal Load Area
To Oakley and
Southern Terminal
To Northern
Terminal
To Southern Terminal
Load Area
To East Country
Load Area
Wells Terminal
Boddington
Narrogin
South Terminal
Alinta Wagerup
Landwehr Terminal
Wagerup
To Bunbury
Load Area
Shotts
Narrogin
Collie Power Station
Bluewaters
Worsley
Western Collieries
Wagin
To Bunbury
Load Area
Muja Terminal
KEY EVENTS
• BTT1 failed on 11 September 2012
• BTT1 replacement delayed
• BTT2 failed on 23 February 2014
• BTT3 running as single contingency
Collie
Katanning
Bridgetown
Beenup
Kojonup
Manjimup
Mount Barker
Network Diagram
Source: Diagram by IMO
Albany
Location Area
Source: Diagram by System Management
4
Great Southern Generation – Full Summary
Source: Diagram by IMO
5
Background and Timeline
Activities Since February
Market Impact
Summary
6
Activities – Western Power
7
Activities – Western Power
•
Western Power considered a number of different options to improve the
situation, not just those implemented [Shane Duryea, 14 May 2014]
•
Construction of a new transmission line between Kemerton and the
existing Pinjarra-Busselton line was completed on 21 July. In the IMO
view, this has significantly reduced the cost impact to market
•
Uprate of existing Rockingham-Waikiki transmission line completed on
24 August
•
Relocation of 132kV/220kV transformer from Merredin to Muja completed
on 28 September
8
Network Upgrade 1: New Kemerton Transmission Line (21 July)
PNJ
APJ
CLP
WGP
New Kemerton Line
NGN
NGS
BDP
KEM
WCG
BSI
WAPL
MRR
WAG
WOR
BUH
CO
PIC
CAP
WCL
MUJ
WSD
KAT
BSN
KOJ
BTN
MR
BNP
MJP
MBR
330kV
220kV
132kV
132kV (new)
66kV
ALB
Source: Diagram by IMO
9
Network Upgrade 2: Rockingham-Waikiki Line Uprate (24 August)
This was a “key enabler to allowing a major
South West generator outage to proceed
throughout most of September without the
need to run a second Muja AB unit”
[Cameron Parrotte, 30 September 2014]
Source: Diagram by Western Power/IMO
10
Network Upgrade 3: Merredin Transformer (28 September)
Dispatch Advisory issued at 09:12 on 28 September 2014:
This Dispatch Advisory is to advise that MU-BTT2 has been put on
load and stabilised. The existing Dispatch Advisories relating to the
High Risk Operating State will be withdrawn and the SWIS will return
to a Normal Operating State.
Source: Photo Provided by Cameron Parrotte, Western Power
11
Activities – System Management
12
Challenges for System Management
• System Management has to plan for credible contingencies,
which do occur:
– Worsley, WAPL behind-the-fence generation, Alinta Pinjarra 1 and
Muja 1-4 have all tripped since 23 February
– Muja to Bunbury Harbour and Picton to Marriott Road transmission
lines have tripped
• There is no scheduled generation south of Muja, which impedes
management of load and voltage issues
• Muja 1-4 start-up times varied from 24-72 hours
• Initial lack of regional forecast information
13
System Management Dispatch Improvements
• System Management commenced new daily regional load
forecast process in July. Accuracy of forecasts was generally
very good.
• Detailed systems studies performed on the region allowed
System Management to increase its load thresholds for
dispatching Muja units
• System Management were able to further increase these load
thresholds following commissioning of the new Kemerton line
and uprates of Rockingham-Waikiki line
14
29 Sep
27 Sep
25 Sep
389
23 Sep
412
21 Sep
458
19 Sep
17 Sep
435
15 Sep
13 Sep
11 Sep
9 Sep
7 Sep
5 Sep
3 Sep
1 Sep
30 Aug
28 Aug
26 Aug
24 Aug
22 Aug
20 Aug
18 Aug
16 Aug
14 Aug
12 Aug
10 Aug
450
8 Aug
6 Aug
4 Aug
2 Aug
31 Jul
29 Jul
27 Jul
25 Jul
23 Jul
21 Jul
19 Jul
17 Jul
15 Jul
13 Jul
11 Jul
9 Jul
7 Jul
400
5 Jul
3 Jul
1 Jul
Actual Load (MW)
Great Southern Regional Load vs Muja Dispatch Requirements
500
473
3 Muja Units
2 Muja Units
427
2 Muja Units
458
1 Muja Unit
412
385
350
300
250
200
150
System Managment data issue
100
50
0
1 July - 28 September 2014 - Trading days
Source: Diagram by IMO
15
Impact of System Management Dispatch Improvements
•
Initial System Management dispatch plan (Most Likely Option):
– July: two units on continuously; third cycled on/off weekly
– August: two units on continuously
– September: one unit on continuously; second cycled on/off weekly
•
System Management reacted effectively and responsively to:
– Create regular and accurate load forecast profiles
– Adjust dispatch thresholds following Western Power network improvements
– Consider IMO’s dispatch advice on financial impacts when making dispatch decisions
•
Actual System Management dispatch:
– July: two units on continuously; no third unit cycling
– August: one unit on continuously; no second unit
– September: one unit on continuously; no second unit cycling
16
Activities – IMO
17
Activities – IMO
•
IMO formed a dedicated specialist team, which worked with System Management to
look for opportunities to reduce risks and costs to the market
•
IMO modelled potential options to reduce impact to market by
–
–
–
–
Forming a base case of costs, modelled using SM indicative dispatch plan (Most Likely Case)
Looking for cost effective alternatives to running Muja units using weekly regional forecasts
Analysing accuracy of load forecasts
Looking back at previous week’s forecast and analysing what actually happened
•
IMO provided advice to System Management based on analysis
•
System Management considered this advice in dispatch decision making while
maintaining system security and reliability
18
“Most Likely” Scenario – SM Dispatch Requirements
100
90
80
IMO estimate
60
Muja Unit 3
50
Muja Unit 2
40
Muja Unit 1
30
20
10
30 Sep
23 Sep
16 Sep
9 Sep
2 Sep
26 Aug
19 Aug
12 Aug
5 Aug
29 Jul
22 Jul
15 Jul
8 Jul
0
1 Jul
MW Target
70
Source: Cameron - Information by System Management
19
“Most Likely” Scenario – Total Additional Costs to Market
Total constrained-on payments to Vinalco
$25,000,000
$20,000,000
$15,000,000
Estimate
@ July 2014
from 1st July onwards
$8.83M
$10,000,000
$7.21M
$5,000,000
Price cap
effective 1 July:
$330/MWh
$$100
$120
$140
$160
$180
$200
$220
$240
$260
$280
$300
$320
$340
Vinalco bid price
Most likely - IMO estimate
Most likely - SM plan
Most likely forecast - IMO estimate
Most likely forecast - SM plan
Source: Diagram by IMO
20
Comparison of Forecast and Actual Costs Since 1 July 2014
•
February to June:
– Actual cost = $6.61M
•
July onwards estimates:
– SM ‘Most Likely’ scenario – forecast cost based on forecast Balancing Prices and
Vinalco bid prices at the start of July = $7.21M
– SM ‘Most Likely’ scenario – cost based on actual Balancing Prices and Vinalco bid prices
(impacted by repeal of carbon tax) = $4.95M
21
Dispatch Advice Estimated Costs
•
System Management provided GSR forecasts from the 29 July
•
IMO provided dispatch advice effective 29 July onwards
•
From 29 July to 28 September:
– Estimated cost based upon SM “Most Likely” Dispatch Plan = $2.86M
– Estimated cost of following IMO dispatch advice = $1.18M
– Actual cost (est.) = $1.77M
•
Cost difference between SM “Most Likely” Dispatch Plan and Actual cost
= $1.09M cost avoidance
•
IMO dispatch advice was based on energy requirements only. We did not have sufficient
information to model voltage requirements
•
Further potential savings of $590k had System Management not required Vinalco for
voltage support in September
22
Background and Timeline
Activities Since February
Market Impact
Summary
23
Constrained On and Off Payments since February 2013
Month
February (from 23rd)
Vinalco
Tesla/EnerNOC
Other
$208,340.10
$17,095.69
March
$1,309,937.31
$642,208.05
April
$1,157,141.49
$271,090.03
May
$34,722.44
$632,782.33
June
$3,810,422.41
July
$1,944,094.46
$363,997.23
$789,159.40
$163,707.29
$848,446.39*
TBC*
August
September (to 28th)
Total
$10,102,263.99
$93,674.74
$93,674.74
$378,604.73
$2,469,485.35+
* September settlement has not yet taken place. Vinalco figures are estimated.
24
Background and Timeline
Activities Since February
Market Impact
Summary
25
Contingency Planning
• System Management ensures that no single network failure
leads to overload of another piece of equipment – otherwise, this
could lead to a chain reaction.
• Thresholds for the number of Vinalco Facilities needed are based
on the amount of generation needed at Muja to prevent postcontingency overload.
• This at times may make it seem that dispatch requirements are
conservative when this is not the case – clearer information
around this is needed
26
Energy Support
• Requirement for Muja generation was initially driven by load in Great
Southern region
• Facilities further from region are less effective
• Effectiveness can also be impacted by particular transmission lines at risk
of overload
• System Management calculated effectiveness factors for other facilities
relative to Muja as amount of generation needed for same risk of postcontingent overload as 1MW at Muja
Facility
Effectiveness Factor Relative to Muja
Muja 1-4
1
Tesla Picton
1
Worsley
0.9
Alinta Pinjarra 1
0.4
27
Voltage Support
• Requirement for voltage support depends on both real and
reactive load (inductive or capacitive)
• System Management does not forecast reactive load
• In security studies, System Management uses historical data with
similar real load and weather as forecast
• Security studies indicated that without MU-BTT2 and without
Muja generation there were likely to be over-voltage postcontingent events overnight at Albany at Beenup
• There could also have been under-voltage post-contingent
events at particularly high evening peaks
• System Management ran a Muja unit continuously to cover for
the potential of these events
28
Summer 2014-15 - GSR
• System Management has provided limits to run Vinalco units
with the new transformer:
– 412MW for first unit
– 458MW+ for second unit
• Based on current forecasts, System Management does not
anticipate load reaching 458MW
• Historical summer load not available
• Great Southern Region is winter peaking
• Highest load during July-September was 436MW
29
Next Steps
•
No longer in High Risk Operating State
•
System Management to dispatch the Great Southern Region as per
normal operations
•
IMO and System Management will continue to monitor the situation
in the region, however this is the last planned formal update
30
IMO Contacts
Questions?
Martin Maticka
Group Manager, Operations and Technology
[email protected]
31

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