Market Mechanics Review of Net Demand Variability from the E&AS Design Stream Working Group Meeting 6&8

Transcription

1 Market Mechanics Review of Net Demand Variability from the E&AS Design Stream Working Group Meeting 6&8 Impact of Net Demand Variability Reference Case and High Cogen scenario

2 Background Dispatching to Net Demand The system is dispatched to meet net demand defined as the demand net of variable resources (on the transmission and distribution system) that effectively self dispatch The variability of net demand can pose challenges on the system. Current system operation practices and tools may need to evolve in order to manage the variability (Net Demand Variability) introduced by increased variable generation The AESO is modelling the expected range of variability as well as considering scenarios related to future asset mix, market rules or products to evaluate the impact of NDV and if needed mitigation options At the WG2 meeting, based on the preliminary analysis, we indicated that; The current market practices and behaviour may create performance issues above 3,000 MW of variable generation (VG) (compared to current 1450 MW on line) Early modelling results indicate that the 3,000MW VG threshold may be reached by 2022/23 1

3 Further Analysis Simulation methodology Early results were modelled based on the system as a single block and using inputs from the 2016 LTO New Analysis: Two models were developed to simulate; Market functions Market simulation model Operations functions System dispatch simulation model Simulated merit orders from the Market simulation model are input into the System dispatch simulation model to simulate operational behaviour Historic behaviour observations will form the foundation of the models Historic data used to validate the models Assumptions of future changes to system are considered The validated model is then used to simulate the future Alternate sensitivity and/or mitigation scenarios will be simulated based on initial observations from the base case simulation 2

4 Further Analysis: Key Assumptions Load Forecast Load forecasts for tested years are based on the 2017 LTO Future generation scenarios Generation forecasts (and generation cases) for tested years are based on the 2017 LTO Future variable generation profile Wind/solar profiles and simulations are based on 200 sites extrapolated to future Profiles are also based on 2014, 2015 and 2016 weather years extrapolated to future Operation practices are based on historic observed behaviour At system level (dispatch interval) Based on observed behaviour and related rules Parametric, validated / tuned by simulation (Historical backcast) At asset level Based on observed and expected behaviour (market and operation) 3

5 Metrics The metrics will demonstrate impacts on market and system operations as a result of changing supply and system characteristics between now and 2030 # Focus Metric Description 1 Market Supply surplus/shortfall situations To Identify impact of unit commitment on supply surplus and shortfall situations 2 Market Merit order / market asset characteristics To identify merit order characteristics under different generation mixes such as quantity of $0, Minimum Stable Generation (MSG) and ramp capability 3 Market Unit cycling Quantify cycling of different types of thermal generation units (CC, SC, CTG and coal for some years) 4 Operations Impact/expected changes to Control Performance Standard 2 (CPS2) violations To measure the10 minute ACE (Area Control Error Balancing authority MW imbalance) performance at or above the 90% of the time within required threshold 4

6 Metrics cont. # Focus Metric Description 5* Operations System Operating Limit (SOL) violation (TOP-007-AB-0) 6* Operations Area Control Error (ACE) events. Related to impact on interties and neighboring systems 7 Operations Variable energy spill due to power management tool activations To measure the 30 minute or longer ACE performance benchmark and resultant SOL violation. i.e. to measure the SOL violation that exceeds the tie line Total Transfer Capability (TTC) for more than 30 minutes or longer To measure the 30 minute or longer ACE performance benchmark. i.e. to measure when the intertie flow exceeds the schedule by more than the Transmission Reliability Margin (TRM) of 65MW for more than 30 minutes, but not exceeding TTC Potential spill of variable energy due to using the AESO s wind power management tool (how often and how much) *The difference between high ACE and SOL is based on how high the BC tie is scheduled during the event. If tie is scheduled near full ATC, then it may cause an SOL; if tie is scheduled low, then it may cause high ACE events. 5

7 Summary Results Reference case and High Cogen Scenario The following is a summary comparison between the reference case results (presented at WG 6) and the high cogeneration scenario (WG 8) # Metric Reference Case Results High-Cogen Results 1 Supply surplus/shortfall situations 2 Merit order / market asset characteristic Supply surplus hours exceed historical values around 2026 Model results show no concerns of supply shortfall due to unit commitment Preliminary work shows that future assets will individually have enhanced ramp capability. There is about 10% difference between $0 and MSG blocks. i.e. flexibility 3 Unit cycling Future generation, including coal-fired replacements, is anticipated to increase in cycling from monthly to weekly on average 4 CPS2 violations CPS2 is always above the required 90% (so not an issue) The results show that a generation mix with more cogeneration would likely lead to moderately more supply surplus events Fourteen supply shortfall events occur between 2026 and 2030 The results show flexibility is similar to the Reference Case, however, the overall ramp capability of the fleet is slower Results are similar to the Reference Case CPS2 is always above the required 90% But, is less than in the reference case (still not an issue) 6

8 Summary contd. # Metric Reference Case Results High-Cogen Results 5 System Operating Limit (SOL) violation (TOP-007-AB-0) Although the simulation indicated that the 1st simulated SOL violation is in 2021, it is when the tie line is out of service. With the tie line in service, the 1st simulated SOL violation was in 2022 If the system controller used the existing practice of dispatch for ramp, these violation are avoided Similar observations as per reference case Similar to the reference case, with the existing practice of dispatch for ramp, these violations are avoided However, more instances of dispatch for ramp will be needed 6 Area Control Error (ACE) events 7 Variable energy spill due to power management tool activations There are more big ACE events with the increased variable generation level Both the limited hours and energy are small numbers, with limited energy less than 0.1% of wind power generation Even less (~10 times) if only considering the non supply surplus periods A few additional instances of big ACE events are observed Similar to the reference case 7

9 Reference Case and High Cogen Results Reference case LTO Based on further analysis, the NDV impact is measured at approximately 3000 MW of variability on the system; however, the estimated date for when the system impact is felt differs depending on the metric, starting in the original timeline of 2022 The impact varies significantly based on availability of intertie No expected system performance issues; however, increased hours of supply surplus which will impact assets and dispatch. Enhanced system flexibility important in managing variability High Cogen A high Cogeneration scenario results in a less flexible fleet Although system operations could be reliably managed, the lower flexibility of the system may require the system controller to dispatch the EMMO (dispatch for ramp) more frequently and in larger volumes to manage NDV The more frequent use of the EMMO to manage ramp needs may result in; price impacts (price fidelity); increased instances of unit cycling supply surplus and in rare instances supply shortfall issues 8

10 Initial Market Approach Suggestions In order to mitigate the NDV impacts the following alternate options may be evaluated; procuring additional volumes of current ancillary service products (ex. AGC); Introduction of specific ramp product; Consideration of how real time pricing signals can incent flexibility Need for changes / value to different unit commitment models 9

11 Next Steps Further testing of asset scenarios to evaluate any change in impact Examples: changes in coal to gas assumptions Evaluation of current rules to mitigate system impact Wind power management, forecasting, use of AGC, Evaluation of dispatch protocol / rules related to ramp Examples: Dispatch tolerance, ramp response Evaluation of further market rules / products Pricing to incent more system flexibility, new ancillary services products Efficiency analysis to evaluate mitigation options impact to system, fleet, costs AESO Internal 10