EE362G - Smart Grids: How Smart Are We Today

EE362G - Smart Grids: How Smart Are We Today
David Maggio, ERCOT, Inc. Ross Baldick, Department of Electrical and Computer Engineering Spring 2019 Copyright © 2019

Outline Overview of ERCOT Communication
Day-ahead and leading up to the operating hour Real-time operations Current and near-term discussion Thoughts and questions Copyright © 2019

ERCOT Overview ERCOT’s primary responsibilities:
System reliability, both in the planning and operations horizons Operation and settlement of the wholesale electricity market Retail switching process for customer choice Open access to transmission Copyright © 2019

Communication Acronyms for market participant types:
Qualified Scheduling Entities (QSEs) Transmission Service Providers (TSPs) These entities play a significant role in the ERCOT communication process and will be discussed later in the presentation. Copyright © 2019

Communication QSEs are the market participants that actively participate in the Day-Ahead and Real-Time Markets. May represent: Resource(s) Load Power marketer List of ERCOT market participants Copyright © 2019

Communication Three primary modes of communication with market participants: Inter-Control Center Communications Protocol (ICCP) Standard used for communications between control centers Market Information System (MIS) Public communication Operators also will communicate verbally, particularly during emergencies. Done through dedicated lines on a private network Copyright © 2019

Communication ERCOT communicates using ICCP with QSEs and TSPs.
~125k ICCP points going between ERCOT and the market participants Hundreds of resources and QSEs i.e., 36 points of data between a QSE and ERCOT for a single resource Shared at a rate between 2 and 10 seconds Data is sent out and received as packets across a private network Copyright © 2019

Communication Data elements include: Economic base-points
i.e., target net generation levels for individual resources for the end of the current 5-minute interval Based on resource-specific economics Reserve deployments Settlement Point Prices Resource/equipment power flows Resource/equipment conditions, i.e., operating states, limits, etc. Including information about dynamically rated transmission lines Copyright © 2019

Communication Telemetry from the QSEs and TSPs has a direct and indirect impact on all of the energy and market management system applications. As a result, so do any issues within the telemetry. It is critical to maintain good quality telemetry to support reliability and minimize market impacts. All points have validation checks, such as comparison against reasonability limits. However, this does not eliminate issues. Copyright © 2019

Communication ICCP communication occurs using ERCOT’s Wide Area Network (WAN) Participants whose facilities connect to ERCOT WAN have a number of responsibilities, notably compliance with Critical Infrastructure Protection requirements ERCOT is responsible for installing and maintaining equipment, and is reimbursed by the entities These responsibilities and costs may not be things that all parties are able or willing to deal with For example, an individual homeowner An “aggregator” may be willing to step into this role Copyright © 2019

Communication The MIS Web-based interface
Communication link to the public and/or market participants As a group (public and secure reports that are more generally applicable) Individually (certified reports that are specific and perhaps confidential) Copyright © 2019

Communication The MIS provides a wealth of information:
Dashboards on real-time grid conditions Forward market results Transmission planning models Settlements extracts Rules and user guides for market participants Data is often left in a relatively raw format to allow users to incorporate the information into their analytical tools Copyright © 2019

Communication The public site and other communication www.ercot.com
Social media Mobile app Market notices Mailing lists Copyright © 2019

Day-Ahead and Leading Up to the Operating Hour
Congestion Revenue Rights Day-Ahead Market Reliability Unit Commitment Adjustment Period Real-Time Operations Copyright © 2019

Day-Ahead The Day-Ahead Market (DAM)
Mixed Integer Program used for co-optimizing awards for wholesale energy bids and offers, Ancillary Service offers and Point-to-Point Obligation bids across all 24 hours of the day Note that Point-to-Point Obligations are financial instruments used for hedging or speculating on congestion in the wholesale markets Objective is to maximize bid-based revenues minus offer- based costs DAM is voluntary but financially binding Execution begins at 10 a.m. and takes at least 2.5 hours to post to the market Copyright © 2019

Day-Ahead The DAM How many bids and offers looking across the day and 200+ entities (using averages from December)? ~13k Point-to-Point Obligation bids ~1.5K energy-only bids and offers ~200 three-part offers Transactions can be for 1, multiple or all hours of the day Need to decide how to award these transactions taking into consideration transmission and resource limitations, plus changing topology, unit commitment, etc. 8 virtual CPUs and 80GB of memory allocated for the process Copyright © 2019

Day-Ahead The number of transactions in the DAM continues to grow
Copyright © 2019

Leading Up to the Operating Hour
Information coming in, generally with granularity of an hour: Demand forecasts Multiple models being executed in parallel Support includes on-staff meteorologist Resource operating plans, bids and offers Including multiple renewable resource forecasts Network topology information Transmission and resource outages Historical and current grid conditions Copyright © 2019

RUC RUC is a process performed by ERCOT to evaluate if there is adequate resource and reserve capacity in the proper locations to meet expected demand Answers the question: Now that the QSEs have started making operational decisions for their own resource fleets and are updating their resource plans, does the system have what it needs to meet ERCOT’s forecasts for energy demand without having transmission congestion issues? Different than the DAM where the demand and supply of energy is based on bids and offers, not forecasts within ERCOT’s systems Copyright © 2019

RUC The general philosophy is to let the market make commitment decisions for their fleet The process is using various inputs to determine if additional commitments are needed ERCOT attempts to defer sending out commitment instructions as long as possible Largely driven by the lead time of the particular resource Copyright © 2019

RUC Considering 4,800+ contingencies and the planned operating state of all online resources to evaluate pre- and post-contingency conditions on power grid When needed, the system then identifies a least cost solution to resolve load and system-wide concerns using resource costs and temporal constraints The cost of short lead-time (<= 1 hour) resources are scaled down so that the optimization tends to prefer those resources, thus allowing more time for the market to respond The process primarily occurs in the day ahead and hourly throughout the operating day, and solves in approximately 10 to 15 minutes Copyright © 2019

SASMs Ancillary Services are services provided by market participants to support a reliable, continual supply of electric power This includes during and following system disturbances (i.e., a large generator trip or sudden, unforeseen changes in demand) Ancillary Services are a market opportunity for resources in addition to solely providing energy These services are typically procured in the Day- Ahead Market, but may be procured via a SASM under certain unexpected conditions Copyright © 2019

Real-Time Operations Understanding the current system state
State estimator Combines real-time telemetry and network topology to determine where we are ERCOT does not receive telemetry for the flow on all equipment, so gaps must be estimated Over 9,000 lines and transformers, plus all the associated circuit breakers, switches, etc. State estimator also helps identify errors i.e., incorrect telemetry or modeling errors Re-evaluating the system state at least every 5 minutes Copyright © 2019

Real-Time Operations Understanding the current system state
Real-time contingency analysis Executing AC power-flow studies for ~7,400 contingencies Identifies thermal and voltage concerns across all the transmission lines, transformers and electrical buses (69 kV and above ) A “concern” is based on thresholds entered by the system operator Provides resource sensitivity information for the identified transmission constraints Also, re-evaluates potential congestion issues at least every 5 minutes Copyright © 2019

Real-Time Operations Simplifying the equations
The Resource Limit Calculator is used to simplify all resources down to a high and low dispatch limit constraint Executed every 4 seconds Evaluating local market competitiveness every 5 minutes using a Constraint Competitiveness Test Determines which resources are flagged for real-time offer mitigation Copyright © 2019

Real-Time Operations Security-Constrained Economic Dispatch (SCED)
600+ resources each having multiple optimization constraints, typically 0-20 transmission constraints The sensitivities of all the resources relative to the transmission constraints are pre-determined for SCED Optimization solves in seconds in determining economic base- points and prices for all resources This includes at least two executions of SCED Majority of SCED execution time is for writing and reading of data between systems Copyright © 2019

Real-Time Operations SCED
Automatically executed every 5 minutes, but can be initiated at any time Can be manually or automatically triggered following a frequency event (i.e., a large unit trip) As part of outputs, ERCOT posts Locational Marginal Prices (LMPs) for all electrical busses Not just for resources, hubs and load zones Also occurs within the overall SCED process that takes 10 to 30 seconds 13k+ points on the system Copyright © 2019

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

Real-Time Operations Deployments between SCED dispatch intervals
Regulation Services, including fast response regulation Responsive Reserve Services Automatic actions being taken by market participants (i.e., governor response, frequency relay trips, TSP remedial action schemes) Copyright © 2019

Real-Time Operations Participants may also be responding to market incentives other than SCED instructions and prices Four Coincidental Peak (4CP) incentives Emergency Response Services and programs Other passive demand or Distributed Energy Resource response Copyright © 2019

Current/Near-Term Discussions
How to engage current programs/resources in the wholesale market Engagement in price formation Distributed energy/demand-side resources The Ancillary Services markets Changes to the service types Real-Time Co-Optimization of energy and Ancillary Services Changes to scarcity pricing (Operating Reserve Demand Curve) Copyright © 2019

What’s potentially limiting progress of the increased engagement Historical energy and reserve prices Exposure to real-time, nodal pricing Cost and/or ability of technology to fit into the current market design These may be things an aggregator is willing to take on Copyright © 2019

Peaker Net Margin (PNM) PNM is a value calculated by ERCOT that accumulates during the year and is updated daily for market participants on the MIS One of the purposes of PNM is to provide an estimate of the annual net revenue of a hypothetical combustion turbine with a heat rate of 10 MMBtu/MWh in the ERCOT market Copyright © 2019

Summary Sophisticated systems are in place at the system operator level Volume of data Calculations for monitoring and operation How can new technologies and systems be joined with the system operator, and at what level do they need to be integrated? Are policy or market design changes needed to get us there? If so, what are they? Copyright © 2019

Homework Exercises: Due Thursday 2/7
3. Calculating a PNM for ERCOT in 2018 using data from the ERCOT website Use the settlement interval prices for 2018, available in the “Historical RTM Load Zone and Hub Prices” report on the ERCOT website (file ending in “RTMLZHBSPP_2018.zip”) Calculate PNM assuming a Fuel Index Price of 3.35 $/MMBtu. What is the aggregated annual value for 2018? The calculations should be performed using the settlement point name “HB_HUBAVG” Perform the calculation again and change the 10 MMBtu/MWH assumption in the POC value from 10 to 9. What is the new aggregated annual value for 2018? In what direction did the value change, and what does this signify for the hypothetical combustion turbine? Copyright © 2019

Homework Exercises: Due Thursday 2/7
4. Evaluation of ERCOT Load Zone wholesale energy prices in 2018 using data from the ERCOT website Again, use the settlement interval prices for 2018, available in the “Historical RTM Load Zone and Hub Prices” report on the ERCOT website (file ending in “RTMLZHBSPP_2018.zip”) Calculate simple average Load Zone prices for the year 2018 for each of the 8 Load Zones in the ERCOT region. What is the reason for differences in the values between the Load Zones? To get prices for only the Load Zones, filter the data for the settlement point type of “LZ” Based solely on the simple average Load Zone wholesale prices for 2018, which of the 8 Load Zones would be “best” for placement of a demand-side Resource? What led you to that conclusion? Copyright © 2019

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