Post on 10-Jun-2022
Utility OperationsDebbie Lew, PhDWestern Interstate Energy BoardNov 13, 2014
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Informational Seminar Series Utility Operations – Nov 13, 3pm MT
Ramping – Nov 19, 11am MT
Frequency Response – Dec 2, 11am MT
Transient Stability – Dec 11, 11am MT
Distributed Generation – Dec 18, 11am MT
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North American Electric Power System
Four independent interconnections, or “machines”
All generators within an interconnection are synchronized: 60 Hz, 3600/1800 rpm
North American Electric Reliability Corporation is responsible for bulk electric power system reliability
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Generation + Imports
Load+ Exports
Supply and Demand in the interconnection is balanced: 60Hz
Generation + Imports
Load+ Exports
Overgeneration/overfrequency in the interconnection
Generation + Imports
Load+ Exports
Undergeneration/underfrequency in the interconnection
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NERC standards BAL-001-1 Real Power Balancing Control
Performance: maintain frequency by balancing supply and demand in real time
Area Control Error (ACE) is essentially a measure of whether a BA balanced its supply and demand (including imports and exports), taking into account whether overgeneration or undergeneration helped or hurt frequency at that time.
http://www.nerc.com/pa/Stand/Reliability%20Standards%20Complete%20Set/RSCompleteSet.pdf
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If the Interconnection looks like this:
Overgeneration/overfrequency
If the Interconnection looks like this
Overgeneration/overfrequency
Then it may be ok, in fact it may be good, for your BA to do this:
Performance measures Control Performance Standard 1 (CPS1) – measures
ACE variability and whether BA was helping or hurting frequency 1-minute-average ACE – is BA helping or hurting
frequency Rolling 12 month index
Control Performance Standard 2 (CPS2) – measures large unscheduled interchanges to limit size of ACE 10-minute-average ACE deviation must be less than
assigned value (L10) Monthly index
In compliance if CPS1 ≥ 100% and CPS2 ≥ 90%
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The job of a system operator Low-cost, reliable power
Risk-reward calculation of an operator Risks are severe – blackout Rewards are modest Therefore, operators are CONSERVATIVE!
What can an operator do? Control generation Configure transmission Control load Restore system
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Unit commitment and economic dispatch
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Time (hour of day)0 4 8 12 16 20 24
Syst
em L
oad
(MW
)
seconds to minutes
Regulation
tens of minutes to hours
LoadFollowing
day
Scheduling
A Chronological View of Utility Operations
Hours to Day ahead: use forecasts to commit units10 minutes to few hours: manually adjust generator set pointsSeconds to minutes: Automatic Generation Control (AGC) automatically adjusts generator output
Zavadil, 2010
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Unit commitment In the day-ahead, unit commitment software considers day-
ahead load, wind, solar forecasts, outages, etc. and determines which generators need to be online for each hour. The output is the start/stop schedules for each unit. Software optimizes total production cost: Economic factors – fuel costs, efficiency, Operating characteristics – maximum output, start times, ramp
capability, minimum generation level, down times Emissions compliance
Security-constrained unit commitment – ensure system is secure in case of contingency, transmission loadings
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What can change between day-ahead and real-time? Load forecast errors
Wind/solar forecast errors
Loss of generation
Transmission
Changes to imports/export schedules
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Economic Dispatch In real time, set optimal output levels for each unit. This
adjusts the day-ahead unit commitment for conditions in real-time. Software optimizes total production cost. Utilities might typically dispatch their units every 5 minutes or every hour.
Security-constrained economic dispatch – ensure system is secure in case of contingency
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Energy Management System (EMS) SCADA (supervisory control and data acqusition)
data input to EMS
State Estimator calculates current state (power flows) of the system
EMS performs contingency analysis of the system. Simulate taking each component out of service, one at a time to determine system impacts.
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How much generation do you need online? Meet the load
Sufficient regulating reserve
Sufficient operating reserve Contingency reserves Load following reserves Flexibility reserves (for
wind/solar)
Zavadil, UVIG, 2014
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NERC Standards BAL-002-1 Disturbance Control Performance: Disturbance Control
Standard (DCS) ensures each BA is able to utilize its contingency reserve to balance the system and restore frequency. BA’s can provide contingency reserves through their generation, their
controllable load, their interchanges or reserve sharing group. A BA or RSG must restore ACE (to 0 if ACE prior to disturbance if ACE was
≥0 or to pre-disturbance value if ACE was <0) within 15 minutes after the start for 100% of Reportable Disturbances.
BAL-002-WECC-2 Each BA and RSG must hold contingency reserves equivalent to the
greater of: Single largest contingency or 3% load + 3% generation (hourly average)
Half of these contingency reserves must be spinning, respond to frequency deviations, and capable of full output in 10 min.
http://www.nerc.com/pa/Stand/Reliability%20Standards%20Complete%20Set/RSCompleteSet.pdf
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Ancillary Services Normal Operating Conditions Regulation – very fast changes
in generator output responding to AGC signal of 4-6 seconds
Load-following – 10’s of minutes to hours
Contingency Conditions Spinning – online and reach full
output in 10 minutes Non-spin – offline but still reach
full output in 10 minutes Supplemental/replacement –
30-60 minute response time; restores spin and non-spin to pre-contingency status
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What about ADI, EIM, joint unit commitment,
RBC?
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ACE Diversity Interchange (ADI) Pool ACE between a group of BA’s
Net upward and downward movements of generators in a group of BA’s
This saves movement of your regulating reserves (the reserves on AGC) and can lead to better CPS2 scores
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Energy Imbalance Market (EIM) Fast, joint economic dispatch
5-minute balancing energy market using security-constrained, least-cost dispatch
Does NOT impact unit commitment (decisions to turn units on)
Regulating reserves still need to be held to cover <5 minute variability but can likely be reduced as a result of the EIM
EIM can call upon any generator in footprint without considering pancaked transmission charges/losses
Aggregation of geographically diverse variable renewables may reduce overall ramping requirements
An EIM may decrease curtailment by allowing BA’s to export more easily
Depending on how transmission is constrained, an EIM can result in more efficient transmission utilization
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Joint unit commitmentA step beyond joint economic dispatch (EIM) is joint
unit commitment. All units in the footprint are considered in the day-ahead unit commitment process.
Your coal plant may not be committed because it is less economic than your neighbor’s.
Day-ahead/Day 2 markets do a joint unit commitment. In the day-ahead, an ISO receives offers from the generators regarding what they are willing to sell each hour. That feeds into ISO market software that determines commitment and schedules.
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Piwko, GE, UVIG, 2009
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Piwko, GE, UVIG, 2009
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4-6 hour ahead unit commitment Wind, solar, load forecasts are more accurate
Commit gas combined cycle, gas steam, oil steam units
Save money in case of forecast error, by being able to commit a gas CC midday instead of a quick start gas CT unit in real time.
May be able to reduce operating reserves because forecasts are more accurate
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Reliability Based Control (RBC)Balancing Authority ACE Limit Proposed to replace CPS2.
Limits duration of operating outside of bounds that get tighter as frequency deviates from 60 Hz.
If frequency is near 60 Hz, do nothing. The further frequency deviates from 60 Hz, the more generators should adjust output to push frequency to 60 Hz
RBC field trial in WECC 3/1/10 with 26 BA’s
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To integrate variable renewables:
Big, Fast Markets
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What will help to integrate more variable renewables? Options that let you aggregate diversity Joint economic dispatch (EIM) Joint unit commitment Reliability Based Control ADI
Options that let you follow the variability better Fast dispatch (5 minutes)
Options that reduce forecast error implications 4-6 hour-ahead unit commitment
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Extra slides
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Area Control Error (ACE): WECC-specific
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NERC Standards BAL-003-1 Frequency Response and Bias: ensures
consistent method for calculating Frequency Bias
BAL-004-0 Time Error Correction: ensures time error correction does not adversely impact reliability BAL-004-WECC-02
BAL-005-0.2b Automatic Generation Control: requirements for AGC to calculate to ACE and deploy regulation.
BAL-006-2 Inadvertent Interchange: ensure BAA’s don’t excessively lean on other BAA’s
http://www.nerc.com/pa/Stand/Reliability%20Standards%20Complete%20Set/RSCompleteSet.pdf
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