EE379K/EE394V Smart Grids: Ancillary Services

EE379K/EE394V Smart Grids: Ancillary Services
Julia Matevosyan, ERCOT, Inc. Ross Baldick, Department of Electrical and Computer Engineering Spring 2019 Copyright © 2019

From David Maggio’s presentation:
Real-Time Operations Monitoring the system between SCED dispatch intervals Responses to SCED instructions Frequency and area control error Reserves Ancillary Services, Physical Responsive Capability, capacity available for economic dispatch, etc. Forced outage detection Current status of equipment vs. planned state State of applications (i.e., last run time) Copyright © 2019

Outline AS Definition and Need Frequency control, ACE, AGC
ERCOT’s Ancillary Services Changes to ERCOT’s Resource Mix Changes to ERCOT’s AS Requirements and Situational Awareness Tools Key Takeaways Homework Assignment Copyright © 2019

What is Ancillary Service?
In ERCOT Protocols: Ancillary Service – A service necessary to support the transmission of energy to load while maintaining reliable operation of the transmission system… Ancillary Services in ERCOT include all reserves (Responsive, Regulation, Non-Spin) In other areas, the term AS often also includes voltage support, emergency reserves and black start Copyright © 2019

Need for Ancillary Services in ERCOT
ERCOT is a single interconnection Imbalance in ERCOT system due to generation or load change needs to be corrected internally with internal reserves Interconnected areas may rely on their neighbors for help with balance over the interconnections Copyright © 2019

Outline AS Definition and Need Frequency Control, ACE, AGC

General Reserve Deployment Sequence after a Generator Trip
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Primary Frequency Control, Generation
All online generators (except nuclear) are required to provide Primary Frequency Response (PFR) with pre-set droop and dead-band. Wind and solar generation resources are also required to have PFR (over-frequency when in operation, under-frequency when under curtailment). Nuclear generation is exempt. Primary Frequency Response droop is given in % and shows percent change in frequency that will result in 100% change in power production from a generator. For example 5% droop means that for 5% (or 3Hz) change in frequency, power production of a plant should double (increase by 100%). Note that 3 Hz change in frequency is very large and is not possible (except just prior to a black out), and therefore droop setting merely showing a ratio between frequency change and resulting power change. Source for the tables: NERC BAL-TRE-001 Copyright © 2019

Primary Frequency Response, Load
In ERCOT, some industrial loads with under-frequency relays are qualified to provide frequency response during generation trip events These load resources are equipped with under-frequency relays If frequency is at or below 59.7 Hz, the relays will trip within 0.5 seconds, freeing up some generation capacity Full response from a load resource is faster than full PFR from generators Types of participating industries: Industrial process plants that produce chemicals Air separation plants that extract industrial gas Natural gas compression sites that are part of pipeline operation Oil field loads Industrial process loads (i.e., cement plants, manufacturing plants) Limited number of large commercial sites, mainly data centers The list of load resource providing frequency response is sorted from the largest MW size to the smallest. Copyright © 2019

Physical Responsive Capacity Monitoring
ERCOT monitors all capacity available for Primary Frequency Response, called Physical Responsive Capacity (PRC). For generators, the capacity that counts toward PRC is the available “headroom” or 20% of installed capacity of all online generators, whichever is less: Headroom is capacity minus generation. For loads, all load resources equipped with under-frequency relays count toward PRC. Generation headroom refers to available capacity calculated as a difference between generation level and it’s highest sustainable limit (i.e. maximum possible output at given ambient temperature and/or any other possible de-rates). 20% of installed capacity is used for the following reason. In ERCOT involuntary underfrequency load shedding (UFLS) starts at 59.3 Hz. ERCOT plans it’s operation to avoid UFLS. With 0.1 Hz margin, 0.6 Hz is the largest frequency deviation ERCOT may encounter (excluding emergency situationns). With 5% droop for 0.6 Hz frequency deviation any generator will be able to deploy only 20% of it’s capacity as PFR. Copyright © 2019

Secondary Control: Area Control Error and Automatic Generation Control
Area Control Error (ACE) is a continuous measure of imbalance in the area scheduled transmission flows and grid frequency The goal of a balancing area authority is to keep the ACE close to zero 𝐴𝐶𝐸= −∆ 𝑃 𝑡𝑖𝑒 −10𝐵 𝑓 𝑚 − 𝑓 𝑠 + 𝐸 𝑀𝐸 + 𝐸 𝑇 In ERCOT, tie-line interchange error term (−∆ 𝑃 𝑡𝑖𝑒 ) is not needed 𝐸 𝑀𝐸 , 𝐸 𝑇 are meter error correction and time error correction in MW Automatic Generation Control (AGC) is used to update the set point of participating generators (in ERCOT every 4 seconds) and minimize the ACE The AGC set points for all participating generators are calculated by a controller with a proportional-integral (PI) characteristic based on the following equation: ∆ 𝑃 𝑔𝑒𝑛,𝑖 =−( 𝐾 𝑃,𝑖 ∙ 𝐴𝐶𝐸 𝑖 + 1 𝑇 𝐼,𝑖 𝐴𝐶𝐸 𝑖 𝑑𝑡 ) In ERCOT, integral term is not included in AGC controller In the ACE equation, ∆ 𝑃 𝑡𝑖𝑒 is the net tie-line interchange error; B is the frequency bias measured in MW/0.1Hz; 𝑓 𝑚 and 𝑓 𝑠 are the measured and scheduled frequencies; and 𝐸 𝑀𝐸 and 𝐸 𝑇 are the meter error correction and time error correction factors respectively in MW. Typically, 𝑓 𝑠 is set to nominal frequencies of 50 Hz or 60 Hz. However, in some cases 𝑓 𝑠 can be set to different values (e.g Hz in 50 Hz systems or 60.2 Hz in 60 Hz systems) during time error corrections. Time error correction is utilized by some system operators to restore the mean frequency back to its nominal value, so the accumulated time error can be driven to zero. The accumulated time error 𝜀 𝑡 can be calculated by comparing the measured frequency with the nominal frequency in the respective time period 𝑇: 𝜀 𝑡 = 0 𝑇 𝑓 𝑡 − 𝑓 𝑛𝑜𝑚 𝑓 𝑛𝑜𝑚 𝑑𝑡 (2) Where 𝑓 𝑡 and 𝑓 𝑛𝑜𝑚 are measured and nominal system frequency respectively. For example, if 𝑓 𝑡 > 𝑓 𝑛𝑜𝑚 then the time error 𝜀 𝑡 will be positive. This means that grid frequency-based clocks will run faster. Error 𝜀 𝑡 is corrected by modifying ACE in the control areas. In AGC set point calculation, 𝐾 𝑃,𝑖 and 𝑇 𝐼,𝑖 are proportional and integral gains of the AGC controller of the area 𝑖. The output value of PI controller is used to determine the total desired generation that will drive ACE to zero. Copyright © 2019

ERCOT’s Ancillary Services
Regulation Up Regulation Down Responsive Non-Spin Copyright © 2019

Responsive Reserve Service
RRS provides operating reserves intended to: Arrest frequency decay within the first few seconds of a significant frequency deviation on the ERCOT grid (deployment as PFR) After the first few seconds of a significant frequency deviation, to help restore frequency to 60 Hz (release of capacity to SCED and dispatch as needed) Provide energy during emergency situations Provide backup Regulation (i.e. secondary reserves) SCED – Security Constrained Economic Dispatch, ran by real-time market every 5 minutes (David Maggio discussed it in his class). Copyright © 2019

Resources providing RRS
RRS may be provided by: Unloaded, online generation resource capacity, through PFR (Governor Response) Load resources controlled by high-set, under-frequency relays (0.5 second response time, 59.7 Hz trigger) Controllable load resources through PFR Hydro generation resources in synchronous condenser mode Copyright © 2019

Regulation Reserve Service
Deployed to balance net load variability between 5-minute SCED intervals Reg-Up is used during negative imbalance between generation and load (i.e., shortage) Reg-Down is used during positive imbalance between generation and load (i.e., surplus) SCED – Security Constrained Economic Dispatch, ran by real time market every 5 minutes (David Maggio discussed it in his class). Deployed by ERCOT through AGC that proportionally divides Regulation needed between all participating generators and issues deployment signals every 4 seconds Regulation can be provided by generators and controllable loads Copyright © 2019

Non-Spinning Reserve Service
Non-Spin may be deployed to: Replace loss of generating capacity Compensate for load, wind, solar forecast uncertainty Address the risk of net load ramps Assist when there is a limited amount of capacity available to SCED Historically, the need for Non-Spin has occurred during: Unexpected hot weather (in shoulder seasons) Cold weather, early morning load ramp outpacing the ability of generation to follow Summer afternoons when high loads and unit outages outstrip generating capability Following large unit trips to replenish reserves Copyright © 2019

Resources providing Non-Spin
Non-Spin Service is provided by using: Generation resources (online or offline) that are capable of being synchronized and ramped to a specified output level within 30 minutes, and are available to run at a specified output level for at least one hour Controllable load resources that qualify for SCED dispatch and are capable of ramping to a specific consumption level within 30 minutes, and are able to consume at this level for an hour Most of the Non-spin is provided by 10-minute quick start units Quick Start units are generators capable of starting and ramping to their full capacity all within 10 minutes. Copyright © 2019

Changing Resource Capacity Mix
Note these charts are based on capacities as of September 30th, 2018 Note: 2020 capacity numbers include planned projects with commercial operation date through 2020, as well as account for confirmed retirements and mothballs Copyright © 2019

Wind Generation Growth Chart
This slide is showing wind generation development since 2012, blue bars correspond to existing operational projects, burgundy bars are showing planned projects with signed interconnection agreements and paid financial security (these projects are more likely to be built), green bar is showing projects with just signed interconnection agreements not yet paid financial security (these projects are less certain at this point in time). The chart it showing cumulative capacity. Copyright © 2019

Solar Generation Growth Chart
This slide is showing solar generation development since 2012, blue bars correspond to existing operational projects, burgundy bars are showing planned projects with signed interconnection agreements and paid financial security (these projects are more likely to be built), green bar is showing projects with just signed interconnection agreements not yet paid financial security (these projects are less certain at this point in time). The chart it showing cumulative capacity. Copyright © 2019

System’s Need to Adapt to the Generation Mix Changes
As the generation mix continues to change, ERCOT has to adapt by: Increasing situational awareness Continuously adjusting AS methodology to adapt reserve amounts to changing system needs Considering changes to AS product set to address the need for faster responding resources Copyright © 2019

Outline AS definition and Need Frequency Control, ACE, AGC

Consequences of Changing Resource Mix
Synchronous generators provide synchronous inertia, among other capabilities Synchronous inertia is stored kinetic energy in rotating masses of synchronous machines connected to the grid Enables the power system to resist changes in frequency after sudden imbalances, and defines the initial Rate-of-Change-of- Frequency (RoCoF) Inverter-based resources (wind, solar, storage) do not contribute to inertia As more of these resources are integrated into the grid, synchronous generation is displaced and inertia decreases RoCoF after generation trip events is becoming faster Copyright © 2019

Effect of Synchronous Inertia on System Frequency
Initial rate of change of frequency (RoCoF) is solely a function of inertia Copyright © 2019

Effect of Synchronous Inertia on System Frequency
With increasing integration of renewables, there could be periods when total inertia of the system could be low, as less synchronous machines will be dispatched. During such situations, it is essential to have adequate frequency response capabilities. UFLS trigger indicates the frequency (59.3 Hz) at which the first stage of involuntary underfrequency load shedding will happen. ERCOT plans and operates the system such that for the simultaneous trip of two largest generating units (2750 MW), UFLS should not be triggered, though it still can happen in some extreme unexpected situations. UFLS trigger Copyright © 2019

Min synch. Inertia (GW*s) System load at minimum synch. Inertia (MW)
ERCOT Inertia For each box, the central mark (red line) is the median, the edges of the box (in blue) are the 25th and 75th percentiles, the whiskers correspond to +/- 2.7 sigma (i.e., represent 99.3% coverage, assuming the data are normally distributed. The corresponding lowest inertia in each year is given in the table. The circles on each boxplot correspond to system inertia during the yearly wind penetration record (i.e. highest percentage of load served by wind generation). Date and Time 2013 3/10/13 3:00 AM 2014 3/30/14 3:00 AM 2015 11/25/15 2:00 AM 2016 4/10/16 2:00 AM 2017 10/27/17 4:00 AM 2018 11/03/18 3:30 AM 132 135 152 143 130 128.8 Min synch. Inertia (GW*s) 24,726 24,540 27,190 27,831 28,425 28,397 System load at minimum synch. Inertia (MW) 31 34 42 47 54 53.4 Copyright © 2019

Critical Inertia Definition
What is the minimum inertia level that we can reliably operate at? Critical inertia is the minimum level of system inertia at or below the point at which a system cannot be operated reliably with existing frequency control practices. For ERCOT, this is the inertia level that -- after a 2,750 MW trip -- will give load resources providing RRS sufficient time to respond before frequency reaches 59.3 Hz (UFLS threshold). Copyright © 2019

Frequency Response (Initial Stage)
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Current Critical Inertia for ERCOT
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Maintaining Critical Inertia
Based on current frequency control mechanisms, critical inertia for ERCOT is around 100 GWs ERCOT is monitoring inertia in the control room Visual alarms are raised when inertia gets close to critical 120 GWs >= Inertia Normal 120 GWs > Inertia >= 110 GWs Yellow 110 GWs > Inertia >= 100 GWs Orange 100 GWs < Inertia Red Copyright © 2019

Inertia Monitoring and Forecasting
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Change to RRS requirements
ERCOT used to procure 2,800 MW of RRS for every hour of the year. How much RRS is needed for different inertia conditions? A series of studies were conducted based on recent historical real-time cases in 2016 and 2017 for different levels of inertia varying between 130 GWs thru 376 GWs. Same criteria used for critical inertia (at each inertia level, must have sufficient amount of RRS to avoid trigger of UFLS after 2,750 MW trip). The goal of the studies was to find out how much RRS is needed overall and determine the equivalency ratio between load resources and generation resources providing RRS. Copyright © 2019

RRS Requirements 𝑃𝐹𝑅 𝑁𝑜 𝐿𝑅 =399275 𝐼𝑛𝑒𝑟𝑡𝑖𝑎 −0.890
𝐿𝑅/𝑃𝐹𝑅= 𝐼𝑛𝑒𝑟𝑡𝑖𝑎 −0.892 Copyright © 2019

RRS Study Results Copyright © 2019
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Scenario 6 Scenario 7 Scenario 8 Scenario 9 Scenario 10 Scenario 11 Scenario 12 LR/PFR 2.25:1 2.11:1 1.99:1 1.87:1 1.77:1 1.69:1 1.61:1 1.54:1 1.47:1 1.41:1 1.36:1 1.3:1 Inertia (GW∙s) 130 140 150 160 170 180 190 200 210 220 230 240 PFR Req. (no LR) (MW) 5246 4916 4620 4361 4132 3927 3743 3576 3424 3285 3157 3040 *RRS (MW) 3229 3162 3090 3039 2984 2920 2868 2815 2772 2726 2676 2643 Scenario 13 Scenario 14 Scenario 15 Scenario 16 Scenario 17 Scenario 18 Scenario 19 Scenario 20 Scenario 21 Scenario 22 Scenario 23 Scenario 24 Scenario 25 LR/PFR 1.26:1 1.22:1 1.17:1 1.14:1 1.1:1 1.07:1 1.04:1 1.01:1 1.00:1 Inertia (GW∙s) 250 260 270 280 290 300 310 320 330 340 350 360 370 PFR Req. (no LR) (MW) 2932 2831 2737 2650 2569 2492 2421 2353 2290 2230 2173 2119 2068 *RRS (MW) 2594 2550 2523 2477 2446 2408 2373 2342 *RRS quantity is calculated with limit of 50% limit on LRs, based on historic participation. **Red font in table above identifies study scenario where RRS needed < 2300 MW MW floor will be used in RRS requirement determination. ***Generation mix (CCs, Gas, SC, Coal, Steam) providing 1150 MW of PFR has been aligned with actual historic system operations. Inertia < 250 GW·s: 30% Coal + 70% Rest. Inertia ≥ 250 GW·s: 15% Coal + 85% Rest Copyright © 2019

RRS Requirements for 2018 Example of January 2018 requirements: RRS requirements are determined in December for the upcoming year, for six 4-hourly blocks for each month, based on 70% of system inertia in the previous two years during that month/hour block. Copyright © 2019

RRS Sufficiency RRS requirements are determined before the operating year, for the whole year. ERCOT determines actual RRS needs based on expected inertia conditions in the DA and closer to RT, and monitors RRS sufficiency. If RRS is insufficient, ERCOT can rely on Physical Responsive headroom (PRC) or open the Supplemental Ancillary Services Market (SASM) to procure additional RRS. DA-Day Ahead, RT-Real Time Copyright © 2019

RRS Sufficiency Tool, Real Time
Actual PFR needed Actual PFR (based on PRC) Shortfall in Procured RRS but adequate PRC Actual RRS available Actual RRS needed Shortfall in RRS available Copyright © 2019

Reliability Risk Desk ERCOT added a new desk in the control room to monitor: System inertia Resulting RRS requirements and RRS sufficiency Sufficiency of AS to cover forecast error risk and net load ramps Renewable forecasts versus actual output The items in grey are not covered in this lecture Copyright © 2019

Changes for Load Resources providing RRS
Historically, load resources were limited to 50% of total RRS requirement, to allow more diversity of RRS resources and to avoid frequency overshoot. With wind and solar resources providing PFR, overshoot is no longer an issue. In November 2017, the limit was increased to 60%. Copyright © 2019

Regulation Requirements
Regulation requirements are based on historic wind and solar power production and load variability, as well as historic Reg deployments. For determining the base Reg-Up requirements for a particular hour, ERCOT calculates: 95th percentile of non-zero Reg-Up deployments (5-minute averages) for the same month, same hour of the previous two years, and 95th percentile of the positive net load (load – wind – solar) changes over each 5-minute interval for the same month, same hour of the previous two years Maximum of these two values sets the Reg-Up requirement for the hour in this month next year + the adjustment for new capacity (see slide 45) Similar process is followed to determine Reg-Down requirements For Reg Dn requirements calculate: the 95th percentile of non-zero Reg-Dn deployments (5-min averages) for the same month, same hour, of the previous two years, and the 95th percentile of the negative net load (load – wind – solar) changes over each 5-min interval for the same month, same hour of the previous two years. Maximum of these two values sets the Reg-Dn requirement for the hour in this month next year + the adjustment for new capacity (see slide 46) Copyright © 2019

Incremental Reg-Up Adjustment Table
In order to consider the increased amount of wind penetration, ERCOT calculates the increase in installed wind generation capacity and then, depending on the month of the year and the hour of the day, ERCOT adds incremental MWs to the Reg values. The tables of incremental MWs for Reg-Up and Reg- Down come from the study ERCOT performs annually. Copyright © 2019

Non-Spinning Requirement
Non-Spin requirements are based on the historic net load forecast error, determined for every month, 6 four-hourly blocks. For determining the Non-Spin requirements for a particular hour: ERCOT will determine the Non-Spin requirement using the 70th to 95th percentile of hourly net load uncertainty from the same month and four-hourly blocks of the previous three years. Periods where the risk of net load ramp is highest will use 95th percentile compared to 70th percentile for periods with lowest risks. Similarly to Reg requirements, calculation and adjustment for newly installed wind capacity is made. The risk of net load ramp is determined based on the change in net load over an hour divided by highest observed net load for the season. The fixed value of percentile ranging between 70th percentile and 95th percentile will be assigned to the net load forecast uncertainty calculated previously. Copyright © 2019

Key Takeaways ERCOT is a single balancing authority, all frequency control and balancing needs are provided internally Primary Frequency Control is realized through governor response from all generating resources and load resources with under-frequency relays Secondary Control is realized through Automatic Generation Control Tertiary Control is realized through use of Non-Spinning AS To ensure sufficiency of frequency control reserves, ERCOT procures AS ERCOT’s resource mix is changing, adding more variable energy resources such as wind and solar ERCOT needs to adapt by increasing situational awareness and introducing more dynamic AS requirements based on historic system conditions New AS products can also be introduced Copyright © 2019

Homework: Due Thursday 2/14 Calculate Reg Requirements
Calculate the Regulation Up and Regulation Down Requirements for January 2018 Data provided: 5-minute, wind, load and solar production data for January 2016 and 2017 (Spring 2019-EE362G-AS-HW.xlsx) 5-minute average Reg Up and Reg Down deployments for January 2016 and 2017 (Spring 2019-EE362G-AS-HW.xlsx) Installed wind capacity increase between the end of 2016 and the end of 2017 (3,084 MW) Based on this data, calculate Reg Up and Reg Down requirements for every hour (1-24) for January Use methodology described on slide 44 and incremental Reg values from slides 45 and 46 (the part of the table you’ll need is already included in Spring 2019-EE362G-AS-HW.xlsx). Ref: these slides and ERCOT Methodologies for Determining Minimum AS Requirements doc Copyright © 2019

Homework: Calculate Reg Requirements
In ERCOT Methodologies for Determining Minimum AS Requirements doc, you may see that additional adjustments may be made to the Regulation requirements in case of historic violations of the CPS1 score and/or exhaustion of Regulation Reserve. You do not need to include these in your calculation. Copyright © 2019

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