1 / 15

NPRR833 Workshop: Contingency Processing in CRR, DAM and SCED

NPRR833 Workshop: Contingency Processing in CRR, DAM and SCED. Shams Siddiqi, Ph.D. Crescent Power, Inc. (512) 619-3532 shams@crescentpower.net QMWG Meeting June 27, 2017. How are Contingencies created?. Network Operations Modeling Expectations for TSPs, REs, and QSEs :

renfro
Download Presentation

NPRR833 Workshop: Contingency Processing in CRR, DAM and SCED

An Image/Link below is provided (as is) to download presentation Download Policy: Content on the Website is provided to you AS IS for your information and personal use and may not be sold / licensed / shared on other websites without getting consent from its author. Content is provided to you AS IS for your information and personal use only. Download presentation by click this link. While downloading, if for some reason you are not able to download a presentation, the publisher may have deleted the file from their server. During download, if you can't get a presentation, the file might be deleted by the publisher.

E N D

Presentation Transcript

  1. NPRR833 Workshop: Contingency Processing in CRR, DAM and SCED Shams Siddiqi, Ph.D. Crescent Power, Inc. (512) 619-3532 shams@crescentpower.net QMWG Meeting June 27, 2017

  2. How are Contingencies created? • Network Operations Modeling Expectations for TSPs, REs, and QSEs: "Single element contingencies will be programmatically generated and appended to each CIM model." "The typical modeling criteria for contingency definitions are straightforward; contingencies are modeled breaker-to-breaker between autotransformers, non-radial AC transmission lines, or between a generator and its high-side breaker.“ “ERCOT will submit NOMCRs and model double contingencies in NMMS after consulting with the owners of the equipment in the double contingencies.” • Thus, programmatically generated single contingencies do not include radial lines and, logically, double contingencies also do not result in islanding in the normal status of Network Operations Model • Therefore, all islanding contingencies are inadvertent and due to change in network topology, i.e. transmission element outages • Solution (Option 1 & 2): Run contingency generation tool with current network model (that includes outages) and eliminate contingencies from approved Contingency List that are not in list of contingencies from this run – no radial/islanding contingency would be modeled in SCED/DAM/CRR

  3. ERCOT Handling of SPS/RAS • SCED: According to ERCOT, there is pre-positioning of generation for Generators outaged due to activation of SPS/RAS, i.e. EMS does pass to SCED any post-SPS activation overloaded constraints (if Generator backed down or tripped by SPS, pickup factors used to model loss of generation in constraint passed to SCED?) • DAM: No SPS/RAS related constraints are considered in DAM • CRR: No SPS/RAS related constraints are considered in CRR • Generation contingency (G-1) and transmission contingency (T-1) that results in islanding (outage) of generation are similar to SPS • NERC requirements for G-1 are met using Ancillary Services (RRS); T-1 with islanding could take out G-X, with X>>1; there is no requirement to be G-X secure • Option 4: Treat G-1 and T-1 with islanding same as SPS/RAS in DAM/CRR: do not consider in DAM/CRR (G-1 already not considered in DAM and CRR)

  4. G-1 Problem: Irresolvable Conflict • Does NERC require dispatch to be G-1 secure for post-contingency transmission overload or is the NERC requirement to ensure ERCOT has enough Ancillary Services (like RRS) to meet G-1? • In load pocket, T-1 may require generator G to run full out with high prices (SF ~ -1) whereas G-1 of the same G may require that the G be backed down (SF ~ 0) - how is this resolved? What if there are no other alternatives to resolve these conflicting constraints? Shadow price cap for the G-1 constraint is same as line shadow price cap – this can result in G being backed down with very high price for constraint violation at the "connectivity node“ • G-1s exist where the resource node is also outaged – exactly like T-1 with islanding. Then, prices are set using pickup SF or Generation Distribution Factors (GDFs) – large uplifts and oversold CRRs • Unit-specific (not resource node) settlement and pricing required to model G-1 in DAM/CRR with different prices for units at same bus • Solution: Consider G-1 evaluation in EMS but not modeled in SCED

  5. Decision Points • G-1 not modeled in CRR and DAM but is modeled in SCED • Optimization Shift Factor (SF) for G in G-1 different from Settlement SF • May lead to oversold CRRs, uplift and discrepancy between EOC and Base Point • However, modeling G-1 in CRR/DAM raises many issues – not recommended • Consider evaluating in EMS but no constraints in SCED, DAM and CRR • Since T-1 with islanding is unintended, adjust contingency list • Run contingency generation tool with current network model (that includes outages) and eliminate contingencies from approved Contingency List that are not in list of contingencies from this run • No change to CRR and DAM engine required – PTP issue is automatically resolved • Implementation cost impact should be minimal compared to alternative • Avoids Unnecessary cost to system (consumers) through inefficient dispatch to enforce unintended constraints and cost to implement unintended constraints • If unintended T-1 with islanding and G-1 kept, then decide between • (A) Modified ERCOT proposal of modeling such contingencies in CRR/DAM with Generation Distribution Factors (GDF) based on AGC resource headroom – requires ERCOT to post GDFs and market to model these contingencies • (B) Treat similar to G-1; i.e. do not model in CRR/DAM but model in SCED – no change to CRR/DAM engines required but change contingency processing tool

  6. G-1 Modeling and Settlement • G-1 not modeled in CRR and DAM but modeled in SCED with prices set using “connectivity node” SF – not optimization SF • Potential uplift and gaming opportunities exist • Min 10*G1 + 20*G2 + 50*G3 ST: a) G1+G2+G3 = 100; b) G2+0.5*G1 <= 40 • G1=80, G2=0, G3=20, SPa=50, SPb =-80, LMPg1=$10, LMP2=-$30, LMP3=$50 • However, ERCOT will settle G1 at “connectivity node” price, i.e. LMP1=$50 • Congestion rent = 100*50-80*50-20*50 = $0 • CRR payments = 40*(50-(-30))+200*(50-50) = $3,200 • Uplift = $3,200 x

  7. T-1 with Islanding same G1 • T-1 with Islanding of the same G1 has exactly the same equations as G-1 in this example but G1 settled using Optimization SF (GDF) • Min 10*G1 + 20*G2 + 50*G3 ST: a) G1+G2+G3 = 100; b) G2+0.5*G1 <= 40 • G1=80, G2=0, G3=20, SPa=50, SPb =-80, LMP1=$10, LMP2=-$30, LMP3=$50 • Congestion rent = 100*50-80*10-20*50 = $3,200 • If modeled the same in DAM and CRR using identical GDFs: • CRR payments = 40*(50-(-30)) or 80*(50-10) = $3,200 • Uplift will be from differences in GDFs x

  8. Why not use GDFs for G-1? • Using GDFs to set prices under G-1 introduces many complexities: • Settlement and prices would have to be at Unit level – not resource node level • Multiple generators at same resource node could have different prices • Min 10*G1+15*G1’+20*G2+50*G3 • ST: a) G1+G1’+G2+G3 = 100; b) G2+0.5*G1 <= 40 c) G2+0.5*G1’ <=40 • G1=80, G1’=10, G2=0, G3=10, SPa=50, SPb=-80, SPc=0 • LMPg1=$10, LMPg1’=$50, LMP2=-$30, LMP3=$50 • CRRs would be from units: Congestion rent = 100*50-80*10-20*50 = $3,200 • CRR payments = 40*(50-(-30)) or 80*(50-10) + 80*(50-50) = $3,200 G1’=10MW at $15/MWh

  9. Issues with Islanding Contingencies • The pricing and dispatch outcome from T-1 with islanding is quite unpredictable, depends on QSE behavior and can be manipulated: • If there were another unit G1' similarly connected in a separate node (even the same node for G-1 contingencies) owned by the same QSE as G1, then if the QSE commits both G1 and G1' with exactly the same total generation, there is no congestion and prices are $10/MWh everywhere. By committing only one of those units or keeping G1' at LSL of say 10MW, the QSE gets paid $50/MWh for the 10MW at G1' and $40/MW for each CRR from Node 1-3. This is much more profitable than getting $10/MWh for all its generation and $0 for its CRRs. Thus prices throughout the market are impacted by how this QSE decides to commit and dispatch its units and it's perfectly reasonable for the QSE to commit only G1 since Load is low.

  10. Islanding Options: Pros & Cons • Eliminate Unintended Islanding Contingencies Pros: • Contingency modeled similarly in CRR, DAM and SCED • Minimal cost to implement: rerun programmatic contingency generation Cons: • None – islanding contingencies should not exist to begin with • Modified ERCOT approach: Pros: • Contingency modeled similarly in CRR, DAM and SCED Cons: • Expensive - between $325k and $425k • Unnecessary cost to system (consumers) through Inefficient dispatch to enforce an unintended G-X (X>>1 in some cases when only G-1 required) constraint and cost to implement • Extensive changes and testing in CRR and DAM engines required • Electrically similar nodes may have significantly different prices – restrictions on activities in electrically similar nodes may mitigate some manipulation potential • GDFs need to be posted and these new type of contingencies need to be modeled by stakeholders to forecast congestion

  11. Islanding Options: Pros & Cons • Treat Similar to G-1 approach (if G-1 is still modeled in SCED): Pros: • Consistent treatment for exactly same outcomes • Expensive change to CRR/DAM engine not required – only contingency screen • No need for GDF posting and modeling by market for forecasting congestion Cons: • Similar to G-1 – likely to result in larger uplift

  12. Option 1: Eliminate Inadvertent Islanding

  13. Option 2: Remove Island; Keep G-1

  14. Option 3: ERCOT Proposal

  15. Option 4: Treat Islanding Like G-1

More Related