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Jyotirmoy Roy, Anjan BoseWashington State University
Jim PriceCalifornia ISO
PSERC SeminarApril 21, 2009
Effects of Ancillary Service Markets on
Control Performanceof Power Systems
2
Order of topics• Existing frequency control markets• Prospective balancing markets• Effect on control performance
• Existing voltage control markets• Secondary voltage control & VAr markets• Feasibility of VAr markets
Frequency control marketsPrimary frequency control Secondary frequency
control Tertiary frequency control
CAISO (no name)
Operating reserve Replacement reserve and supplemental energy
Regulating reserve Contingency reserve
Spinning reserve Non-spinning reserve
PJM Frequency response
Operating reserve
Reserve beyond 30 minutesRegulation
Primary reserveSecondary reserve
Spinning reserve Quick-start reserve
AUContingency Services Regulation reserve &
network loading control
Short-term capacity reserveFast Slow Delayed
FR Primary reserve Secondary reserveTertiary reserve
Rapid 15 minute reserve Complementary 30 minute reserve
Reserve beyond 30 minutes
GB
Operating Reserve
Does not exist
Operating reserve Contingency reserve
High frequency / ResponseRegulating
reserve Standing reserve Fast start Warming and hot standbyPrimary Secondary
Frequency control marketsAustralia PJM
Procurement PaymentMethod
Payment Structure Procurement Payment
MethodPaymentStructure
Primary frequency Control
Bilateral Spot market
Pay-as-bidCCP Availability Compulsory None None
Secondary frequency Control Spot market Pay-as-bid
CCP Availability Spot market Pay-as-bidCCP
Availability +Opportunity
France New Zealand
Procurement Payment Method
PaymentStructure Procurement Payment
Method Payment Structure
Primary frequencyControl Bilateral Pay-as-bid Availability
Bilateral Tendering
Spot market
Regulated Price
Pay-as-bid
Availability +Utilization
frequency
Secondary frequencyControl Bilateral Pay-as-bid
Availability +
UtilizationTendering Pay-as-bid Availability
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Influence of market on performance Each supplier can bid only the amount it can
deliver within dispatch interval More market goal More unit participation More units More effective ramping capacity Better ramp rate Faster frequency response,
lower ACE ACE Control Performance Criteria
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Balancing market – CAISO• Spot market for regulation• Unit must be able to deliver full response in 10 minutes• Unit should be able to receive and respond to AGC• Payment is uniform MCP• Participating units are pre-qualified• Performance should meet qualification criteria (2nd bullet) –
tested regularly without notice• No load following market – imbalance is procured from
supplementary energy marketWe will call this type A market hereafter.
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Second price auction market• Suppliers guess market clearing price, submit bid ahead of market
operating horizon• Bids are tested for uncompetitive behavior and necessary measure is
taken to reduce the effect• Resultant bids are entered into auction pool• Everybody gets the highest market clearing price
• Unsatisfactory for suppliers who contribute more• Fast response (high ramp rate, fast starting)• O&M cost is higher for rapid operation
• Unwillingness of supplier to provide service• Less competition• Higher cost of procurement
8
First price incentive marketOption 1
• Pay incentive to suppliers who contribute more• Pay everyone else at market rate
Option 2• Form separate markets based of performance• Operate each market separately• Pay each supplier at the respective market rate
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Experimental markets for regulation –Type B
• Dispatch interval 10 or 5 minutes
• Full response delivery – 10 or 5 minutes
• Single auction clearing• Units categorized
according to ramp rates• Fast• Slow
• Fast unit payment – MCP• Slow unit payment – Pay-
as-bid
Market clearing price
Market Goal
SingleBid
Incentive
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Experimental markets for regulation –Type C
• Units are categorized according to ramp rate• Fast• Slow
• Separate markets for fast and slow services• Pay-as-MCP for each type of market
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Control strategies• Market decides the set of generators which will
provide regulation and their capacity• AGC decides how each unit will participate through
regulation participation factors• Equal participation factor• Proportional to ramp rate• Proportional to bid capacity• Inversely proportional to marginal cost
Case study – WECC• 225 bus model• 3 balancing
areas• 40 generators in
CAISO balancing area
• 9 generators in neighboring balancing area
• 13 generators in external balancing area
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Case study – WECCSummary of different market settlements
Market TypeNo of awarded
generatorsEquivalent ramp rate (MW/min)
Total payment ($/h)
Clearing price ($/MWh)
Reg. Up Reg. Down
10 Min - Type A 6 61 23226 38.71 22.03
10 Min - Type B 6 61 23113.2 38.71 22.03
5 Min - Type B 15 141 23541 39.7 22.03
5 Min - Type C 4 70 11700.3 39.7 22.03
10 Min - Type C 4 27 11500.2 38.71 22.03
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Frequency response – A & B
Equal regulation participation Participation proportional to ramp rate
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Frequency response – A & B
Participation proportional to bid Participation inversely proportional to marginal cost
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Frequency response – C
a. Only fast generators; b. 50-50 fast and slow; c. Only slow generators
Fast regulation for 1 min then, a. only slow, b. 75-25 fast slow, c. 50-50 fast slow
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Observations• Market does influence performance• More regulating units Better frequency performance• Ramp rate based control Better frequency performance
Recommendation• Market should encourage better performance through
incentive• Control should be performance oriented whenever possible
Voltage control marketsFrance Great Britain
Procurement PaymentMethod
Payment Structure Procurement Payment
MethodPaymentStructure
Primary voltage Control
CompulsoryBilateral Pay-as-bid Fixed +
AvailabilityCompulsory,
TenderingRegulatedpay-as-bid
Fixed +Availability +
Utilization
Enhanced voltage Control Bilateral Pay-as-bid Fixed +
Availability Tendering Pay-as-bidFixed +
Availability +Utilization
Australia PJM
Procurement Payment Method
PaymentStructure Procurement Payment
Method Payment Structure
Primary voltageControl Compulsory None Compulsory Regulated
Price Fixed +
Opportunity
Enhanced voltageControl Tendering Pay-as-bid Availability +
Opportunity None
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Secondary voltage control in VAr• Maintains voltage at load
buses within certain range• Automatic control of VAr
injection at generator bus• ACG-like real time control• Area wise reactive power
management
Voltage control marketFor voltage reference control –
• Market in VAr• Control in voltage to operate within VAr limits of bid
For reactive injection control –• Market in VAr• Control in VAr within bid limits
21
Case study – WECC
• 225 bus model• 24 Voltage control
areas• Test VCA central
California VCA#16• 37 buses, 8
generators• Vmax = 1.08 p.u.• Vmin = 0.985 p.u.
Case study – WECCBus # Type Bus # Type
110 Gen. Bus 204 Load Bus
111 Load Bus 210 Gen. Bus
116 Gen. Bus 211 Load Bus
117 Load Bus 212 Load Bus
118 Gen. Bus 213 Load Bus
119 Load Bus 214 Load Bus
121 Load Bus 215 Load Bus
122 Load Bus 216 Load Bus
132 Load Bus 217 Load Bus
133 Load Bus 218 Gen. Bus
134 Load Bus 219 Gen. Bus
173 Load Bus 220 Load Bus
192 Load Bus 221 Load Bus
193 Load Bus 222 Load Bus
195 Load Bus 223 Load Bus
198 Gen. Bus 224 Load Bus
199 Load Bus 225 Load Bus
202 Load Bus 226 Gen. Bus
Bus No Vref MVAr
110 1.013 36.52
116 1.05 948.64
118 1.035 1504.01
198 1.035 366.87
210 1.035 290.76
218 1 613.35
219 1.007 835.99
226 1.035 129.17
Left: Buses inside test voltage control areared highlights are below minimum limitAbove: Steady state voltage and reactiveinjection at the generator buses
Steady state:Total: 22703.35 MVArVCA#16: 2532 MVAr
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Case study – WECC
Voltage to reactive power injection sensitivity at the generator buses. Highlighted are the generatorswith higher sensitivity than others
Bus #121 Bus #133 Bus #195 Bus #199 Bus #204
Gen #110 0.021 0.017 0.036 0.029 0.028
Gen #116 0.005 0.001 0.024 0.021 0.022
Gen #118 0.005 0.001 0.024 0.021 0.022
Gen #198 0.017 0.012 0.048 0.038 0.037
Gen #210 0.006 0.001 0.04 0.035 0.039
Gen #218 0.014 0.012 0.023 0.018 0.017
Gen #219 0.008 0.003 0.028 0.025 0.026
Gen #226 0.009 0.005 0.027 0.023 0.024
All units Most influential Less influentialBus No Vref MVAr
110 1.073 193.99
116 1.1 831.37
118 1.095 1458.68
198 1.095 489.15
210 1.095 299.42
218 1.06 600.45
219 1.067 826.73
226 1.095 128.99
Bus No Vref MVAr
110 1.074 157.91
116 1.1 813.57
118 1.085 1281.24
198 1.092 470.62
210 1.1 312.53
218 1.066 701.98
219 1.075 969.13
226 1.1 124.46
Bus No Vref MVAr
110 1.073 192.91
116 1.06 833.54
118 1.095 1458.45
198 1.095 488.28
210 1.095 299.15
218 1.06 600.34
219 1.067 825.62
226 1.095 128.99
Bus No Vref MVAr
110 1.088 198.41
116 1.099 887.66
118 1.085 1358.94
198 1.1 487.95
210 1.068 241.56
218 1.083 1054.43
219 1.054 564.97
226 1.088 129.15
Bus No Vref MVAr
110 1.1 212.4
116 1.1 736.03
118 1.065 810.57
198 1.095 457.11
210 1.1 287.85
218 1.1 1056.69
219 1.1 1343.78
226 1.1 76.56
Bus No Vref MVAr
110 1.085 10.28
116 1.1 724.59
118 1.075 931.71
198 1.075 348.36
210 1.1 377.28
218 1.1 1113.66
219 1.1 1389.53
226 1.1 76.54
Total MVAr20102.71VCA#164828.78
Total MVAr20102.12VCA#164831.44
Total MVAr20109.50VCA#164827.28
Total MVAr20107.08VCA#164923.07
Total MVAr20039.69VCA#164980.99
Total MVAr20085.04VCA#164971.95
VOLTAGE
ADJ
INJECTION
ADJ
25
ObservationReactive injection control –
• Reactive power level of controlling units are known beforehand
• Overall less power consumption• More stress on the units inside VCA• Conservative voltage profile• Feasible control structure – potential alternative for
reference voltage controlAutomatic secondary voltage control –
• Fast AGC like control – suitable for real time• Base operating point OPF• Sensitivity – OPF / FDPF
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ObservationVAr market
• OPF based market• Locational influence is high• Risk of market power
Mitigation • Bilateral contract• Price cap
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Conclusion• Market should be structured to reward
performance which helps better service
• Competitive markets may not always be possible to form due to lack of resources with similar capability
• Especially voltage control is prone to market power if number of generators are few
