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Simulating Power System Operations

Simulating Power System Operations. GridSchool 2010 March 8-12, 2010  Richmond, Virginia Institute of Public Utilities Argonne National Laboratory Thomas D. Veselka Center for Energy, Economic, and Environmental Systems Analysis Decision and Information Sciences Division

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Simulating Power System Operations

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  1. Simulating Power System Operations GridSchool 2010 March 8-12, 2010  Richmond, Virginia Institute of Public Utilities Argonne National Laboratory Thomas D. Veselka Center for Energy, Economic, and Environmental Systems Analysis Decision and Information Sciences Division ARGONNE NATIONAL LABORATORY tdveselka@anl.gov  630.252.6711 Do not cite or distribute without permission MICHIGAN STATE UNIVERSITY

  2. Power System OperatorsBalance Supply and Demand Transmission Consumer Demand Distribution Generation Supply Demand Supply

  3. Load Time Operations Are Balanced Over Time and Space Load SCE BPA Time Load WASN Time

  4. Resource Stack and Least Cost DispatchUnits Are Loaded into the Grid Based on Electricity Production Cost 2,500 2,400 MW Cost ??? Energy Not Served 2,250 Future Growth Diesel 150 MW 120 $/MWh 2,000 MW 120$/MWh 2,000 Maximum Load 1,750 Diesel 120 $/MWh 1,600 MW 80$/MWh Gas Turbine 250 MW 80 $/MWh Gas Turbines 80 $/MWh 1,500 Cumulative Supply and Load (MW) 1,200 MW 40$/MWh 1,250 Oil Steam 250 MW 60 $/MWh Oil Steam 60 $/MWh 1,000 800 MW 25$/MWh NG Steam 250 MW 40 $/MWh NG Steam 40 $/MWh 750 Minimum Load Minimum Coal Steam 25 $/MWh 500 Coal Steam 500 MW 25 $/MWh 250 Nuclear 8 $/MWh Nuclear 500 MW 8 $/MWh 0 Supply Demand Marginal Cost

  5. Production Costs ($/MWh) Are a Function of Fuel CostsUnit Conversion Efficiency and Variable O&M Costs Very Low Fuel Cost Very High Fuel Cost High Fuel Cost High Fuel Cost No Fuel Cost Range: Low to High Fuel Cost

  6. Capital Expenses and Fixed O&M Costs Do notFactor into the Least-Cost Dispatch (Sunk Investments)

  7. The Least-Cost Resource Stack Can Be Used to Create a Supply Curve 500 Energy not Served > 2,500 Not Supplied 500 $/MWh 450 2,250 400 Diesel 120 $/MWh 2,000 Gas Turbines 80 $/MWh 350 1,750 300 1,500 Oil Steam 60 $/MWh Supply (MW) 250 Production Cost ($/MWh) 1,250 NG Steam 40 $/MWh 200 1,000 Steam Coal 25 $/MWh 150 750 40 $/MWh 1,200 MW Demand Diesel 100 500 Nuclear 8 $/MWh GasTurbine 50 Oil Steam 250 Nuclear NG Steam NGCC 0 0 Supply 0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 Cumulative Supply (MW)

  8. Generating Units Are Taken Off-Line for Maintenance and Brought Back Into Service at a Later Time Generation Supply

  9. Maintenance Outages Are Scheduled During Periods of Low Electricity Demand Total System Capacity without Outages Capacity with Outages Maximize the Smallest Reserve Capacity During the Year Reserve Capacity Load/Capacity (MW) Demand Planned Outages

  10. Scheduled Maintenance Alters the Supply Stack 2,500 2,400 MW 500$/MWh 2,500 2,250 800MW not supplied at 2400 MW Load 2,400 MW Cost 500 2,000 MW 500$/MWh 2,250 Energy Not Served 2,000 2,000 MW 120$/MWh 400MW not supplied at 2000 MW Load Diesel 120 $/MWh 2,000 1,750 1,600 MW 120$/MWh Gas Turbines 80 $/MWh 1,750 Diesel 120 $/MWh 1,500 1,600 MW 80$/MWh Supply Stack with Maintenance (MW) 1,200 MW 80$/MWh Gas Turbines 80 $/MWh 1,500 1,250 Planned Transition Oil Steam 60 $/MWh 1,200 MW 40$/MWh Supply Stack without Maintenance (MW) 1,250 1,000 800 MW 60$/MWh NG Steam 40 $/MWh Oil Steam 60 $/MWh 1,000 750 800 MW 25$/MWh NGCC 25 $/MWh NG Steam 40 $/MWh 750 500 Nuclear Unit Scheduled Out of Service NGCC 25 $/MWh 500 250 Nuclear 8 $/MWh 250 0 Supply 0 Supply Marginal Cost Marginal Cost

  11. The Supply Curve Shifts When Units Are Either Taken Off-Line or Brought Back Into Service 500 500 $/MWh Curve with Maintenance 450 400 350 Since the Supply Curve Is Typically Steeper at High Loads the Increase in Generation Cost Attributed to a Scheduled Outage is Less Expensive when Loads Are Low 300 250 Production Cost ($/MWh) 200 80 $/MWh 150 Curve without Maintenance 40 $/MWh 100 1,200 MW 50 1,800 MW 0 0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 Cumulative Supply (MW)

  12. 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 Good Source: Generation Availability Dataset (GADS) 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

  13. 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 Total System Capacity Random Forced Outages Load/Capacity (MW)

  14. Mathematical Techniques that Use Probabilistic Methods Help Quantify System Risks and Help Planners and Operators Manage Outage Risks Operational? Down 1 1 1 Unit Up Operational? Unit Up 6X6 6X6X6 6 Operational? Down Down Unit Up Unit Up Unit Up

  15. Example 1 Number Plants = 1 Plant Size = 1200 MW Forced Outage Rate = 0.1 Load = 1000 MW Random Forced Outages & Probability that all Demand Will not Be Served Possible Combinations Plant A Is Out of Service Plant A Operates Load Served = 1000 MW Not Served = 0 Load Served = 0 MW Not Served = 1000 This occurs 10 percent of the time 10 = (1.0 – 0.9) X 100 This occurs 90 percent of the time 90 = 0.9 X 100 Expected Energy not Served (MW) = 100 MWh Probability (percent) Energy Not Served (MW)

  16. Random Forced Outages & Probability that all Demand Will not Be Served Expected Energy not Served = 82 MWh Probability (percent) Example 2 Load = 1000 MW Number Plants = 2 Plant Size = 600 MW each Forced Outage Rate = 0.1 Occurrence Frequency Possible Combinations Plant A Plant B Plant A Plant B Load Served = 1000 MW Not Served = 0 81 Percent 0.9 X 0.9 = 0.81 Load Served = 600 MW Not Served = 400 9 Percent (1.0- 0.9) X 0.9 = 0.09 18 Percent 600 MW Served 400 MW Not Served Load Served = 600 MW Not Served = 400 9 Percent 0.9 X (1.0- 0.9) = 0.09 Load Served = 0 MW Not Served = 1000 1 Percent (1.0- 0.9) X (1.0- 0.9) = 0.01

  17. Random Forced Outages & Probability that all Demand Will not Be Served Example 3 Load = 1000 MW Number Plants = 3 Combinations = 8 Plant Size = 400 MW each Forced Outage Rate = 0.1 Probability (percent) 1 Unit: Expected Energy not Served = 100.0 MWh Expected Energy not Served = 65.8 MWh 2 Units: Expected Energy not Served = 82.0 MWh 3 Units: Example 4 Load = 1000 MW Number Plants = 4 Combinations = 16 Plant Size = 300 MW each Forced Outage Rate = 0.1 Expected Energy not Served = 51.2 MWh Probability (percent) 4 Units: Example 5 Load = 1000 MW Number Plants = 12 Combinations = 4096 Plant Size = 100 MW each Forced Outage Rate = 0.1 All Examples Have the Same Total Capacity Expected Energy not Served = 2.1 MWh Probability (percent) 12 Units: Engineering Guideline: Largest unit should be no larger than 10 percent of the peak load

  18. System Reliability Increases as a Function of Higher Capacity, but Higher Reliability Becomes Increasingly more Expensive More On-line Capacity Capital Expenses and Fixed O&M Costs Reliability Keep Lights on Reliability Keep Lights on Reserve Margin

  19. System Reliability Increases as a Function of the Number of Units in the System, but it Becomes Increasingly more Expensive More Units (Identical Capacity) Capital Expenses and Fixed O&M Costs Reliability Keep Lights on Reliability Keep Lights on Number of Units

  20. Operators Reserve (Do not Fully Load) Some of a Unit’s Capacity so the Generating System Can Rapidly Respond to a Forced Outage Spinning Reserves 2,500 Production Costs Are More Expensive Scheduled Output 2,250 Diesel 120 $/MWh 2,000 Reserves Reserves Are Used to Fill Outage Voids Gas Turbines 80 $/MWh 1,750 Generating Capacity (MW) owing Diesel 120 $/MWh 1,500 Gas Turbines 80 $/MWh Oil Steam 60 $/MWh Supply Stack (MW) 1,250 Load Oil Steam 60 $/MWh NG Steam 40 $/MWh Output Dispatched (MW) 1,000 NG Steam 40 $/MWh NGCC 25 $/MWh NGCC 25 $/MWh 750 500 Nuclear 8 $/MWh Nuclear 8 $/MWh 250 0 No Spinning With Spinning

  21. Reliability Increases as More Spinning Reserves Are Added, but it Is Increasingly More Expensive Operate More Expensive Units at Lower Efficiency Reliability Keep Lights on Production Costs ($/MWh) Spinning Reserves Reliability Keep Lights on

  22. Typically, Low Loads Have Relatively Inexpensive Prices & Low Volatility High Loads Are Associated with Expensive Prices and High Volatility Random Outages Affect Electricity Prices Depending on the Type and Amount of Capacity that Is Off-Line When Loads Increase Prices Are Higher and the Price Spread Increases

  23. Probabilistic Techniques Can Be Used to Estimate Market Prices and Price Volatility as a Function of Load High Volatility Low Volatility

  24. Probabilistic Techniques Can also Be Used to Estimate Operating Profits (Payments to Capital) Market Price ($/MWh) Operating Profit ($/MW of Capacity) Running Average Price Operating Profit (without outage) Capacity Factor Unit Production Cost

  25. 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

  26. Reservoirs Are Multi-Purpose ResourcesOperations 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

  27. 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) Run-of-River Hydro Has no Storage (cannot dispatch) Upstream Releases Side Flows Elevation Limits Max Dam Reservoir Elevation Head Reservoir Volume Min Water Intake Power Plant Release Flow Tail Reservoir Storage Capacity Range from a Few Hours or Less to Multiple Years of Water Release Turbine

  28. Peaking Capability (100 MW) Peak Shaved Traditional Hydropower Plant Dispatch Focused on Displacing High Cost Thermal Generation Capability: 150 MW Minimum Release: 50 MW Generation: 1,910 MWh No Other Restrictions Discretionary Release Pattern (710 MWh) Loads (MW) Mandatory Water Release Pattern (1,200 MWh) Generation (MWh) Remaining Loads Minimum Release Rate

  29. Market Driven Operations Yield a Very Different Generation Pattern

  30. Hydropower Plants Are Often Cascaded, Adding to the Complexity of Operations The Aspinall Cascade Is a Tightly Coupled System with a High Level of Operational Interdependencies Black Canyon Black Canyon To Riffle Crystal Morrow Point To Montrose Blue Mesa Curecanti Substation To Four Corners 30

  31. Recent Aspinall Cascade Dispatch Simulation Results

  32. Reality Versus Theory

  33. Hydropower Plant Operations Carry Financial Risks Due to Natural Reservoir Inflow Variability

  34. Upper Reservoir Energy is Produced When Generating Substation Energy is Consumed When Pumping Lower Reservoir Pumped Storage Plants Both Consume and Produce Power Reservoirs • Initial reservoir elevation • Maximum reservoir elevation • Minimum reservoir elevation • Elevation change per water release • Power conversion efficiency (upper) • Generation capability (upper) Pump Pump • Maximum pumping rate • Pumping efficiency

  35. Economics of Pump Storage Are Good when there Are Wide Price Spreads Between Off-Peak (Low Demand) and On-Peak (High Demand) Periods Sell Electricity at High Prices Buy Electricity at Low Prices Price Difference Should Cover Pumping Losses

  36. In the Absence of Transmission Congestion, Lower Cost Generators Are Used First Load Load Mid cost generator Lowest cost generator Highest cost generator Load The Marginal Cost of Serving Load or Locational Marginal Price (LMP) Is the Same Throughout the System

  37. Load Lower LMP Load Mid cost generator Lowest cost generator Congested Line Highest cost generator Load Higher LMP 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

  38. 50 100 MWh Production 100 MWh Production 100 100 50 GenCo Profit $11,000 Dispatch with Loads of 250 MW without Congestion Radial Network Demand 150 MWh LMP = 75 $/MWh @ all locations 100 MW 30 $/MWh 100 MW 10 $/MWh 50 MWh Production 100 MW 75 $/MWh Demand 100 MWh 50 Consumer cost GenCo revenue $18,750 Economic/production cost $7,750 Price setter Assumes Bid Price = Marginal Production Cost Note: Above example assumes that production and load levels are constant over a one-hour time period

  39. GenCo Profit Was $11,000 w/cong $2,000 50 75 MWh Production 100 MWh Production 100 75 25 75 MWh Production 75 Congestion Charge Amount re-dispatched (MWh) 25 Congestion charge ($/MWh) 45 Congestion payment ($) 1,125 Dispatch with Loads of 250 MW with Congestion Radial Network Price setter Load 150 MW 100 MW 30 $/MWh 100 MW 10 $/MWh LMP = 30 $/MWh 25 MW transfer limit Congestion Charge 75 $/MWh -30 $/MWh 45 $/MWh Price setter 100 MW 75 $/MWh Load 100 MW LMP = 75 $/MWh Economic/production cost was $7,750 w/congestion $8,875 Consumer cost was $18,750 w/cong $12,000 Economic Cost $1,125 Consumers save $6,750 with congestion Assumes Bid Price = Marginal Production Cost Note: Above example assumes that production and load levels are constant over a one-hour time period

  40. 160 Independent System Operator For 1 hour 140 Price Responsive Demand Curve (Load) Generation Bid Curve 120 Production Cost or Generator Genco Bid Price ($/MWh) 100 80 Units Dispatched Out-of-Merit 60 40 Generators Off-line Generators Dispatched 0 0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 Cumulative MW In Many Situations More Expensive Bids Are Dispatched Because of Transmission Congestion Transmission Congestion Affect the Choice of Generators to Dispatch

  41. The Eastern Interconnect Contains Thousands of Busses and a Very Complex Transmission System 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 LMPs are the result of the transmission congestion Source: T. Overbye, UIUC

  42. .2860 .7140 .0446 .1744 .0670 .5692 .1894 .0069 .0007 .2819 .1813 .0601 .1887 .2880 .1001 .3705 .2415 .3881 Power Flows Down Path of Least Resistance(Power Transfer Distributions Factor – Pathway) Power Injection (Generation) Power Sink (Load)

  43. The System Operator Can Relieve Transmission Congestion by Opening Circuits(Once Opened, a Lower Cost Dispatch May Be Implemented) Cap. 600 MW PC $20/MWh Cap. 600 MW PC $20/MWh Congested Line Cap. 200 MW PC $50/MWh Cap. 200 MW PC $50/MWh Cap. 250 MW PC $100/MWh Cap. 250 MW PC $100/MWh Demand 450 MW Demand 450 MW

  44. Balancing Authority (BA) Maintain Load-Interchange-Generation Balance within an Area and Supports Interconnection Frequency in Real-Time SCE BPA Tie-line Flows Tie-line Flows WASN Tie-line Flows Tie-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 44

  45. In Addition to Spinning Reserves, Regulation Service Is Needed to Maintain Frequency Load 40 Time Regulation Up Regulation Service (MW) 0 Regulation Down -40 60 0 Time (minutes)

  46. Units that Provide Ancillary Service Have a Reduced Range of Scheduled Operation Spinning Reserves Decrease Maximum • 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 Up Load Following Regulation Service Load Following Capability (MW) Increase Minimum Minimum Minimum Down

  47. Area Control Error (ACE) Is a Measure ofSystem Error in BA Interchange and Time Error Spinning Reserves Actual Versus Scheduled Net Interchanges (MW) Over BA Tie-Lines 40 Decrease Maximum Actual Versus Target Frequency (Hz) Time Error (seconds) Regulation Service Load Following Load Following ACE = (Ta - Ts) –10Bf(Fa- Fs) +/-Bt Te Regulation Up Capability (MW) slow fast Time Error Bias (MW/second) Area Bias per 0.1 Hz (MW/Hz) Increase Minimum Regulation Service (MW) clock 0 Minimum Minimum Regulation Down Up Down -40 60 0 Time (minutes) 47

  48. 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

  49. Thank you for your attention Source: BOR

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