Simulating Power System Operations G RID S CHOOL 2010 M ARCH 8-12, 2010 R ICHMOND, V IRGINIA I...
Transcript of Simulating Power System Operations G RID S CHOOL 2010 M ARCH 8-12, 2010 R ICHMOND, V IRGINIA I...
Simulating Power System Operations
GRIDSCHOOL 2010MARCH 8-12, 2010 RICHMOND, VIRGINIA
INSTITUTE OF PUBLIC UTILITIESARGONNE NATIONAL LABORATORY
Thomas D. VeselkaCenter for Energy, Economic, and Environmental Systems Analysis
Decision and Information Sciences DivisionARGONNE NATIONAL LABORATORY
[email protected] 630.252.6711
Do not cite or distribute without permission
MICHIGAN STATE UNIVERSITY
Veselka - 02
GridSchool 2010
Power System OperatorsBalance Supply and Demand
GenerationSupply
TransmissionDistribution Consumer
Demand
Real Time DispatchH1H1 H5H5 H10H10 H15H15 H20H20 H25H25
Day Ahead Planning
D1D1 D8D8
Week Ahead Planning
W1W1 W5W5 W9W9 W13W13
Long-Term Planning
Multi-Year Planning
Year Ahead Planning
Yr1Yr1 Yr2Yr2 Yr3Yr3 Yr4Yr4 Yr5Yr5 Yr6Yr6
Month Ahead Planning
M1M1 M3M3 M5M5 M7M7 M9M9 M11M11 M13M13 M15M15
Real Time DispatchH1H1 H5H5 H10H10 H15H15 H20H20 H25H25
Day Ahead Planning
D1D1 D8D8
Week Ahead Planning
W1W1 W5W5 W9W9 W13W13
Long-Term Planning
Multi-Year Planning
Year Ahead Planning
Yr1Yr1 Yr2Yr2 Yr3Yr3 Yr4Yr4 Yr5Yr5 Yr6Yr6
Month Ahead Planning
M1M1 M3M3 M5M5 M7M7 M9M9 M11M11 M13M13 M15M15
Supply Demand
Veselka - 03
GridSchool 2010
Operations Are Balanced Over Time and Space
Time
Lo
ad
Time
Lo
ad
Time
Lo
ad
Veselka - 04
GridSchool 2010
Resource Stack and Least Cost DispatchUnits Are Loaded into the Grid Based on Electricity Production Cost
Nuclear8 $/MWh
Coal Steam
25 $/MWh
NG Steam40 $/MWh
Diesel120 $/MWh
Gas Turbines80 $/MWh
Oil Steam60 $/MWh
MarginalCost
1,200 MW
40$/MWh800 MW
25$/MWh
1,600 MW
80$/MWh
2,000 MW
120$/MWh
2,400 MW
Cost ???Energy
Not Served
Nuclear500 MW
8 $/MWh
Diesel150 MW120 $/MWh
Coal Steam500 MW25 $/MWh
NG Steam250 MW40 $/MWh
Oil Steam250 MW60 $/MWh
Gas Turbine250 MW80 $/MWh
0
250
500
750
1,000
1,250
1,500
1,750
2,500
2,250
2,000
Supply
Cu
mu
lati
ve S
up
ply
an
d L
oa
d (
MW
)
Minimum
Demand
Maximum Load
FutureGrowth
Minimum Load
Veselka - 05
GridSchool 2010
Production Costs ($/MWh) Are a Function of Fuel CostsUnit Conversion Efficiency and Variable O&M Costs
0 10 20 30 40 50 60 70 80 90
Fossil Steam
Hydroelectric
Combined Cycle
Gas Turbine
Diesel Generator
Nuclear Steam
Efficiency (%)
0 2 4 6 8 10 12 14
Fossil Steam
Hydroelectric
Combined Cycle
Gas Turbine
Diesel Generator
Nuclear Steam
Variable O&M ($/MWh)
Very Low Fuel Cost
High Fuel Cost
Range: Low to High Fuel Cost
High Fuel CostVery High Fuel Cost
No Fuel Cost
Veselka - 06
GridSchool 2010
0 5 10 15 20 25 30 35 40
Fossil Steam
Hydroelectric
Combined Cycle
Gas Turbine
Diesel Generator
Nuclear Steam
Fixed O&M Costs ($/kW-yr)
Capital Expenses and Fixed O&M Costs Do not Factor into the Least-Cost Dispatch (Sunk Investments)
0 200 400 600 800 1000 1200 1400 1600 1800
Fossil Steam
Hydroelectric
Combined Cycle
Gas Turbine
Diesel Generator
Nuclear Steam
Construction Cost ($/kW)
Veselka - 07
GridSchool 2010
Nuclear8 $/MWh
Steam Coal
25 $/MWh
NG Steam40 $/MWh
Diesel120 $/MWh
Gas Turbines80 $/MWh
Oil Steam60 $/MWh
0
250
500
750
1,000
1,250
1,500
1,750
> 2,500
2,250
2,000
Supply
Su
pp
ly (
MW
)
Not Supplied500 $/MWh
0
50
100
150
200
250
300
350
500
450
400P
rod
uc
tio
n C
os
t ($
/MW
h)
0 250 500 750 1,000 1,250 1,500 1,750 2,500 2,2502,000
Cumulative Supply (MW)
NGCCNG
Steam
DieselGas TurbineOil
SteamNuclear
The Least-Cost Resource Stack Can Be Used to Create a Supply Curve
40 $/MWh
1,200 MW Demand
Veselka - 08
GridSchool 2010
0 5 10 15 20 25 30
Fossil Steam
Hydroelectric
Combined Cycle
Gas Turbine
Diesel Generator
Nuclear Steam
Scheduled Maintenance (days)
Real Time DispatchH1H1 H5H5 H10H10 H15H15 H20H20 H25H25
Day Ahead Planning
D1D1 D8D8
Week Ahead Planning
W1W1 W5W5 W9W9 W13W13
Long-Term Planning
Multi-Year Planning
Year Ahead Planning
Yr1Yr1 Yr2Yr2 Yr3Yr3 Yr4Yr4 Yr5Yr5 Yr6Yr6
Month Ahead Planning
M1M1 M3M3 M5M5 M7M7 M9M9 M11M11 M13M13 M15M15
Real Time DispatchH1H1 H5H5 H10H10 H15H15 H20H20 H25H25
Day Ahead Planning
D1D1 D8D8
Week Ahead Planning
W1W1 W5W5 W9W9 W13W13
Long-Term Planning
Multi-Year Planning
Year Ahead Planning
Yr1Yr1 Yr2Yr2 Yr3Yr3 Yr4Yr4 Yr5Yr5 Yr6Yr6
Month Ahead Planning
M1M1 M3M3 M5M5 M7M7 M9M9 M11M11 M13M13 M15M15
Generating Units Are Taken Off-Line for Maintenance and Brought Back Into Service at a Later Time
GenerationSupply
Veselka - 09
GridSchool 2010
Maintenance Outages Are Scheduled During Periods of Low Electricity Demand
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
On-Line Capacity (MW)
Total System Capacity without Outages
ReserveCapacity
PlannedOutages
Capacity with Outages
Lo
ad/C
apac
ity
(MW
)
Demand
Maximize the Smallest Reserve Capacity During the Year
Veselka - 010
GridSchool 2010
Nuclear8 $/MWh
NGCC25 $/MWh
NG Steam40 $/MWh
Diesel120 $/MWh
Gas Turbines80 $/MWh
Oil Steam60 $/MWh
0
250
500
750
1,000
1,250
1,500
1,750
2,500
2,250
2,000
Supply MarginalCost
1,200 MW
40$/MWh
800 MW
25$/MWh
1,600 MW
80$/MWh
2,000 MW
120$/MWh
2,400 MW
Cost 500EnergyNot Served
Su
pp
ly S
tac
k w
ith
ou
t M
ain
ten
an
ce
(M
W)
NGCC25 $/MWh
NG Steam40 $/MWh
Diesel120 $/MWh
Gas Turbines80 $/MWh
Oil Steam60 $/MWh
MarginalCost
0
250
500
750
1,000
1,250
1,500
1,750
2,500
2,250
2,000
Supply
Su
pp
ly S
tac
k w
ith
Ma
inte
na
nc
e (
MW
)
1,600 MW
120$/MWh
1,200 MW
80$/MWh
800 MW
60$/MWh
2,000 MW
500$/MWh400MW not supplied
at 2000 MW Load
2,400 MW
500$/MWh800MW not supplied
at 2400 MW Load
Planned Transition
Scheduled Maintenance Alters the Supply Stack
Nuclear Unit Scheduled Out of Service
Veselka - 011
GridSchool 2010
0
50
100
150
200
250
300
350
500
450
400
Pro
du
cti
on
Co
st
($/M
Wh
)
0 250 500 750 1,000 1,250 1,500 1,750 2,500 2,2502,000
Cumulative Supply (MW)
80 $/MWh
40 $/MWh
Curve with Maintenance
Curve without Maintenance
1,200 MW
The Supply Curve Shifts When Units Are Either Taken Off-Line or Brought Back Into Service
1,800 MW
500 $/MWh
Since the Supply Curve Is Typically Steeper at High Loads the Increase in Generation Cost Attributed to a Scheduled Outage is Less Expensive when Loads Are Low
Veselka - 012
GridSchool 2010
0 1 2 3 4 5 6 7 8 9
Fossil Steam
Hydroelectric
Combined Cycle
Gas Turbine
Diesel Generator
Nuclear Steam
Forced Outage Rate (%)
Generating Units Unexpectedly Breakdown (Randomly Forced out of Service)
There are hundreds of causes for outages. The North American Electric Reliability Council (NERC) categorizes these into the following groups: Boiler Balance of plant Steam turbine Generator Pollution control equipment External Regulatory Personnel errors Performance
Generating Unit Forced Outages Add to System Uncertainty
Grid Operations Must Be Prepared to Immediately Fill the Generation Void when a Generator Suddenly Is Taken Off Line
Good Source: Generation Availability Dataset (GADS)
Veselka - 013
GridSchool 2010
It Is Very Unlikely that ALL Generating Units Will Be On-Line at any Point in Time when there Are Many Units in the System
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Planned & Maintenance Outages Forced Outages On-Line Capacity Load
Total System Capacity
Random Forced Outages
Lo
ad/C
apac
ity
(MW
)
Veselka - 014
GridSchool 2010
Mathematical Techniques that Use Probabilistic Methods Help Quantify System Risks and Help Planners and Operators Manage Outage Risks
Operational?Operational?
Operational?Operational?
Operational?Operational?
Dow
nU
nit
Up
DownDown
UnitUnit
UpUp
Unit Up
Down
Unit Up
Unit Up
Unit Up
16
16X6
16X6X6
0102030405060708090100
0 100 200 300 400 500 600 700 800 900 1000
90.00
0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 10.00Pro
babi
lity
(per
cent
)
Energy Not Served (MW)
Random Forced Outages & Probability that all Demand Will not Be Served
Example 1Number Plants = 1Plant Size = 1200 MWForced Outage Rate = 0.1Load = 1000 MW Possible Combinations
Plant A Operates
This occurs 90 percent of the time
90 = 0.9 X 100
Plant A Is Out of Service
This occurs 10 percent of the time
10 = (1.0 – 0.9) X 100
Expected Energy not Served (MW) = 100 MWh
Random Forced Outages & Probability that all Demand Will not Be Served
Example 2Load = 1000 MWNumber Plants = 2Plant Size = 600 MW eachForced Outage Rate = 0.1
Possible CombinationsPlant A Plant B
Occurrence Frequency Plant A Plant B
81 Percent0.9 X 0.9 = 0.81
9 Percent(1.0- 0.9) X 0.9 = 0.09
9 Percent0.9 X (1.0- 0.9) = 0.09
1 Percent(1.0- 0.9) X (1.0- 0.9) = 0.01
18 Percent
600 MW Served400 MW Not Served
0102030405060708090100
0 100 200 300 400 500 600 700 800 900 1000
81.00
0.00 0.00 0.0018.00
0.00 0.00 0.00 0.00 0.00 1.00
Pro
ba
bili
ty
(pe
rce
nt)
Expected Energy not Served = 82 MWh
Random Forced Outages & Probability that all Demand Will not Be Served
Engineering Guideline: Largest unit should be no larger than 10 percent of the peak load
0102030405060708090100
0 100 200 300 400 500 600 700 800 900 1000
72.90
0.0024.30
0.00 0.00 0.00 2.70 0.00 0.00 0.00 0.10
Example 3Load = 1000 MWNumber Plants = 3Combinations = 8Plant Size = 400 MW eachForced Outage Rate = 0.1
Pro
babi
lity
(per
cent
)
Expected Energy not Served = 65.8 MWh
0102030405060708090100
0 100 200 300 400 500 600 700 800 900 1000
65.61
29.16
0.00 0.00 4.86 0.00 0.00 0.36 0.00 0.00 0.01
Example 4Load = 1000 MWNumber Plants = 4Combinations = 16Plant Size = 300 MW eachForced Outage Rate = 0.1
Pro
babi
lity
(per
cent
)
Expected Energy not Served = 51.2 MWh
0102030405060708090100
0 100 200 300 400 500 600 700 800 900 1000
88.91
8.52 2.13 0.38 0.05 0.00 0.00 0.00 0.00 0.00 0.00
Example 5Load = 1000 MWNumber Plants = 12Combinations = 4096Plant Size = 100 MW eachForced Outage Rate = 0.1
Pro
babi
lity
(per
cent
)
Expected Energy not Served = 2.1 MWh
2 Units: Expected Energy not Served = 82.0 MWh
1 Unit: Expected Energy not Served = 100.0 MWh
3 Units:
4 Units:
12 Units:
All Examples Have the Same Total Capacity
Veselka - 018
GridSchool 2010
System Reliability Increases as a Function of Higher Capacity, but Higher Reliability Becomes Increasingly more Expensive
Reserve Margin
Rel
iab
ilit
yK
ee
p L
igh
ts o
n
ReliabilityKeep Lights on
Ca
pit
al E
xpe
nse
s a
nd
F
ixe
d O
&M
Co
sts
More On-line Capacity
Veselka - 019
GridSchool 2010
System Reliability Increases as a Function of the Number of Units in the System, but it Becomes Increasingly more Expensive
Number of Units
Rel
iab
ilit
yK
ee
p L
igh
ts o
n
ReliabilityKeep Lights on
Ca
pit
al E
xpe
nse
s a
nd
F
ixe
d O
&M
Co
sts
More Units (Identical Capacity)
Veselka - 020
GridSchool 2010
Operators Reserve (Do not Fully Load) Some of a Unit’s Capacity so the Generating System Can Rapidly Respond to a Forced Outage
Gen
erat
ing
Cap
acit
y (M
W)
ow
ing
Scheduled Output
SpinningReserves
Ou
tpu
t D
isp
atch
ed (
MW
) Reserves AreUsed to Fill
Outage Voids
Nuclear8 $/MWh
NGCC25 $/MWh
NG Steam40 $/MWh
Diesel120 $/MWh
Gas Turbines80 $/MWh
Oil Steam60 $/MWh
0
250
500
750
1,000
1,250
1,500
1,750
2,500
2,250
2,000
No Spinning
With Spinning
Su
pp
ly S
tac
k (
MW
)
Nuclear8 $/MWh
NGCC25 $/MWh
NG Steam40 $/MWh
Diesel120 $/MWh
Gas Turbines80 $/MWhOil Steam60 $/MWh
Reserves
Production Costs Are More Expensive
Load
Veselka - 021
GridSchool 2010
Spinning Reserves
Rel
iab
ilit
yK
ee
p L
igh
ts o
n
ReliabilityKeep Lights on
Pro
du
cti
on
Co
sts
($
/MW
h)
Operate More Expensive Units at Lower Efficiency
Reliability Increases as More Spinning Reserves Are Added, but it Is Increasingly More Expensive
Veselka - 022
GridSchool 2010
Random Outages Affect Electricity Prices Depending on the Type and Amount of Capacity that Is Off-Line
Lowest Load
0.00
30.40
0.00
10.50
40.52
16.51
1.110.00
0.830.07 0.07
0
5
10
15
20
25
30
35
40
45
13.0 13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8 13.9 > 13.9
Market Price ($/MWh)
Per
cen
t o
f T
ime
Typically, Low Loads Have Relatively Inexpensive Prices & Low Volatility
Average Load
0.00
16.09
0.00
7.90
0.00 0.00 0.00
56.26
17.53
0.27 0.001.68
0.00 0.00 0.05 0.09 0.00 0.06 0.00 0.00 0.01 0.02 0.00 0.02 0.01 0.010
10
20
30
40
50
60
<14.2 14.2 14.3 14.4 14.5 14.6 14.7 14.8 14.9 15.0 15.1 15.2 15.3 15.4 15.5 15.6 15.7 15.8 15.9 16.0 16.1 16.2 16.3 16.4 16.5 >15.8
Market Price ($/MWh)
Per
cen
t o
f T
ime
When Loads Increase Prices Are Higher and the Price Spread Increases
High Loads Are Associated with Expensive Prices and High Volatility
Veselka - 023
GridSchool 2010
Probabilistic Techniques Can Be Used to Estimate Market Prices and Price Volatility as a Function of Load
0
4
8
12
16
20
24
28
32
36
40
0 10 20 30 40 50 60 70 80 90 100
Load and Market Price Exceedance Probability (Percent of Time)
Lo
ad (
GW
)
0
10
20
30
40
50
60
70
80
90
100
Un
con
gested
Market P
rice ($/MW
h)
Min-Max Price Range
Load
Average Price
HighVolatility
LowVolatility
Veselka - 024
GridSchool 2010
Probabilistic Techniques Can also Be Used to Estimate Operating Profits (Payments to Capital)
0
10
20
30
40
50
60
70
80
90
100
110
0 9 18 27 36 45 54 63 72 81 90 99Unit Capacity Factor
Mark
et
Pri
ce (
$/M
Wh
)
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
15,000
An
nu
al P
rofit ($
/MW
of C
ap
acity
)
Average Price Over All Hours Dispatched ($/MWh)
Market Price ($/MWh)
Annual Profit ($/MW of Capacity)
New Unit Production
Cost
Projected Capacity Factor
Average Price When Dispatched
Annual Profits (Based On No Outages)
0
10
20
30
40
50
60
70
80
90
100
110
0 9 18 27 36 45 54 63 72 81 90 99Unit Capacity Factor
Mark
et
Pri
ce (
$/M
Wh
)
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
15,000
An
nu
al P
rofit ($
/MW
of C
ap
acity
)
Average Price Over All Hours Dispatched ($/MWh)
Market Price ($/MWh)
Annual Profit ($/MW of Capacity)
New Unit Production
Cost
Projected Capacity Factor
Average Price When Dispatched
Annual Profits (Based On No Outages)
Op
era
ting
Pro
fit ($/M
W o
f Cap
ac
ity)
Ma
rke
t P
ric
e (
$/M
Wh
)
Unit Production
Cost
Running Average
Price
Capacity Factor
Operating Profit(without outage)
Veselka - 025
GridSchool 2010
Hydroelectric Power Plants Are an Important Component of Grid Operations in Some Systems
Very flexible operation Change operations quickly Large range of operations Good resource for ancillary services
No fuel required Very low production costs Zero air emissions
High fixed costs Expensive to build Maintain dam, reservoir, & plant
Environmental concerns Effect operations and economics
Limited energy source Cannot always operate at full capacity Uncertainty
Veselka - 026
GridSchool 2010
Reservoirs Are Multi-Purpose Resources Operations Consider Many Factors
Reservoir water storage and management Flood control Irrigation Environmental management Fish and wildlife (endangered species) Municipal and industry water supply Supply for generating units with steam
turbines Recreation Navigation Soil erosion Hydroelectric power generation
In Addition to Power Plant Equipment Limits,Operations Are also Constrained by Reservoir Limits
S t = S t-1 + I t - O t - D t - L t
t is current time,S is reservoir storage or content, I is reservoir inflow,O is reservoir outflow,D is reservoir diversion,L is reservoir loss (e.g., evaporation)
Turbine
Reservoir ElevationHead
Tail
Dam
PowerPlant
WaterIntake
Reservoir Volume
ReleaseFlow
SideFlows
Upstream Releases Elevation
LimitsMax
Min
Reservoir Storage Capacity Range from a Few Hours or Less to Multiple Years of Water Release
Run-of-River Hydro Has no Storage (cannot dispatch)
Minimum Release Rate
Peak Shaved
Remaining Loads
Peaking Capability(100 MW)
Mandatory Water Release Pattern
(1,200 MWh)
DiscretionaryRelease Pattern
(710 MWh)
Lo
ads
(MW
)G
eneratio
n (M
Wh
)
Capability: 150 MWMinimum Release: 50 MWGeneration: 1,910 MWh No Other Restrictions
Traditional Hydropower Plant Dispatch Focused on Displacing High Cost Thermal Generation
Market Driven Operations Yield a Very Different Generation Pattern
30
Hydropower Plants Are Often Cascaded, Adding to the Complexity of Operations
ToMontrose
ToRiffle
CurecantiSubstation
Blue Mesa
CrystalMorrow Point
ToFourCorners
BlackCanyon
The Aspinall Cascade Is a Tightly Coupled System with a High Level of Operational Interdependencies
BlackCanyon
Recent Aspinall Cascade Dispatch Simulation Results
Reality Versus Theory
Hydropower Plant Operations Carry Financial Risks Due to Natural Reservoir Inflow Variability
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Exceedance Fraction
Mo
nth
ly R
ev
en
ue
(1
00
0's
$)
0
100
200
300
400
500
600
Revenue
Nu
mb
er
of
Occ
ura
nces
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
Exc
eed
an
ce F
req
uen
cy
Zero Occurances
Occurances
MonthAverage of All
TracesCRSS Average
HydrologyOver
EstimateJan 20,039.7 20,050.8 11.1Feb 16,936.9 16,935.1 -1.8Mar 14,476.2 14,477.7 1.6Apr 15,905.8 15,912.3 6.5May 18,042.7 18,021.3 -21.5Jun 20,624.8 20,787.2 162.3Jul 39,740.6 39,938.6 198.1Aug 33,145.3 33,294.6 149.3Sep 15,333.4 15,418.4 85.0Oct 13,794.6 13,781.7 -12.9Nov 16,547.5 16,534.9 -12.6Dec 24,733.0 24,752.7 19.7
Annual 249,320.6 249,905.4 48.7
Monthly Revenue (1000's $)
Veselka - 034
GridSchool 2010
ReservoirsInitial reservoir elevationMaximum reservoir elevationMinimum reservoir elevationElevation change per water releasePower conversion efficiency (upper) Generation capability (upper)
Pump
Energy is ProducedWhen Generating
Energy is ConsumedWhen Pumping
Substation
Upper Reservoir
LowerReservoir
Pumped Storage Plants Both Consume and Produce Power
Pump Maximum pumping rate Pumping efficiency
Veselka - 035
GridSchool 2010
Economics of Pump Storage Are Good when there Are Wide Price Spreads Between Off-Peak (Low Demand) and On-Peak (High Demand) Periods
Buy Electricityat Low Prices
Sell Electricityat High Prices
Price Difference ShouldCover Pumping Losses
Veselka - 036
GridSchool 2010
In the Absence of Transmission Congestion, Lower Cost Generators Are Used First
The Marginal Cost of Serving Load or
Locational Marginal Price (LMP)
Is the Same Throughout the System
Mid cost generator
Highest cost generator
Lowest cost generator
Load
Load
Load
Veselka - 037
GridSchool 2010
Congestion Results in a Re-dispacth of Some Units Resulting in Range of LMPs Across the Grid
A Spread in LMPs Across the Network Is an Indicator of Transmission Congestion
Higher LMP
Congested Line
Mid cost generator
Highest cost generator
Lowest cost generator
Load
Load
Load
Lower LMP
Veselka - 038
GridSchool 2010
Dispatch with Loads of 250 MW without Congestion Radial Network
100 MW30 $/MWh
100 MW75 $/MWh
Demand 100 MWh
100 MW10 $/MWh
Demand 150 MWh
LMP = 75 $/MWh @ all locations
Price setter
50
100
50
50 100 MWh Production
50 MWh Production
100
100 MWh Production
Assumes Bid Price = Marginal Production Cost
Economic/production cost $7,750
Consumer cost GenCo revenue
$18,750
GenCo Profit
$11,000
Note: Above example assumes that production and load levels are constant over a one-hour time period
Veselka - 039
GridSchool 2010
Dispatch with Loads of 250 MW with Congestion Radial Network
100 MW75 $/MWh
Load 100 MW
100 MW10 $/MWh
Load 150 MW
LMP = 30 $/MWh
Price setter
100 MW30 $/MWh
LMP = 75 $/MWh
Price setter
25 MW transfer
limitCongestion Charge
75 $/MWh-30 $/MWh 45 $/MWh
75
25
5075 MWh
Production
75
75 MWh Production
100
100 MWh Production
Assumes Bid Price = Marginal Production Cost
Economic/production cost was $7,750
w/congestion $8,875
Consumer cost was $18,750
w/cong $12,000
GenCo Profit
Was $11,000w/cong $2,000
Consumers save $6,750 with congestion
Amount re-dispatched (MWh) 25 Congestion charge ($/MWh) 45
Congestion payment ($) 1,125
Congestion Charge
Note: Above example assumes that production and load levels are constant over a one-hour time period
Economic Cost $1,125
Transmission CongestionAffect the Choice of Generators to Dispatch
0
40
60
80
100
120
140
160
0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000
Cumulative MW
Pro
du
ctio
n C
ost
or
Gen
erat
or
Gen
co B
id P
rice
($/M
Wh
)
Generation Bid
Curve
Price Responsive
Demand Curve(Load)
Generators Dispatched
Generators Off-line
For 1 hour Independent System Operator
Units Dispatched Out-of-Merit
In Many Situations More Expensive Bids Are Dispatched Because of Transmission Congestion
Veselka - 041
GridSchool 2010
Source: T. Overbye, UIUC
Red indicates high LMPs or load pockets where lower cost
power cannot be delivered
Blue indicates low LMPs or generator pockets where lower cost power cannot be sent out
The Eastern Interconnect Contains Thousands of Busses and a Very Complex Transmission System
LMPs are the result of the transmission congestion
Veselka - 042
GridSchool 2010
Power Flows Down Path of Least Resistance(Power Transfer Distributions Factor – Pathway)
.0446
.569
2
.189
4 .0670
.1744
.714
0
.2860
.0007.0069
.28
80 .2819 .1
88
7
.18
13
.0601
.1001
.3881.3705
.241
5
Power Injection(Generation)
Power Sink (Load)
Veselka - 043
GridSchool 2010
The System Operator Can Relieve Transmission Congestion by Opening Circuits (Once Opened, a Lower Cost Dispatch May Be Implemented)
Cap. 600 MWPC $20/MWh
Cap. 250 MWPC $100/MWh
Cap. 200 MWPC $50/MWh
Demand 450 MW
Cap. 600 MWPC $20/MWh
Cap. 250 MWPC $100/MWh
Cap. 200 MWPC $50/MWh
Demand 450 MW
Congested Line
Veselka - 044
GridSchool 2010
Balancing Authority (BA) Maintain Load-Interchange-Generation Balance within an Area and Supports Interconnection Frequency in Real-Time
Tie-line Flows
Tie-line Flows
Tie-
line
Flow
sTie-Line Flows Are Scheduled to Take Advantage of Economic Power Transfers while at the Same Time Inadvertent Power Travels Down the Path of Least Resistance
Veselka - 045
GridSchool 2010
In Addition to Spinning Reserves, Regulation Service Is Needed to Maintain Frequency
Reg
ulatio
n D
ow
n
Time
Load
Reg
ula
tio
n U
p
Time (minutes)
Reg
ula
tio
n S
ervi
ce (
MW
)
0
40
0 60-40
Veselka - 046
GridSchool 2010
Units that Provide Ancillary Service Have a Reduced Range of Scheduled Operation
Spinning reserves (SR)Affects maximum generation
Regulation services (RS)Affects minimum & maximum
generation Minimum Generation
When generation is off-line the unit cannot provide either spinning reserves or regulation services
Min
imu
mL
oad
Fo
llow
ing
Min
imu
mL
oad
Fo
llo
win
g
Increase Minimum
Decrease Maximum R
egu
lation
Service
SpinningReserves
Ca
pab
ility
(M
W)
Up
Down
Veselka - 047
GridSchool 2010
Area Control Error (ACE) Is a Measure ofSystem Error in BA Interchange and Time Error
ACE = (Ta - Ts) – 10Bf (Fa - Fs) +/- Bt Te
Actual Versus Scheduled Net Interchanges (MW)
Over BA Tie-Lines
Actual Versus Target Frequency (Hz)
Area Bias per 0.1 Hz (MW/Hz)
Time Error(seconds)
Time Error Bias (MW/second)
slow
fast
clock
Reg
ulatio
n D
ow
n
Reg
ula
tio
n
Up
Time (minutes)
Re
gu
lati
on
Se
rvic
e (
MW
)
0
40
0 60-40 M
inim
um
Lo
ad
Fo
llo
win
g
Min
imu
mL
oad
Fo
llow
ing
Increase Minimum
Decrease Maximum
Reg
ula
tion
Serv
ice
Spinning Reserves
Cap
abili
ty (
MW
)
Up
Down
Veselka - 048
GridSchool 2010
Summary: Power System Operators Balance Supply & Demand
Dispatch generating units to meet load
Have a least-cost operating objective
Adjust grid topology to help relieve congestion
Maintain operating reserves to keep the lights on when there is an outage
Regulate power quality Keep the clocks on time
Thank you for your attention
Source: BOR