1 Synchronization of Production cost modeling with Powerflow and Stability model Jinxiang Zhu, Lan Trinh ABB Power System Consulting
2 FERC Order 1000 Transmission needs driven by reliability, economic, and public policy Identify the efficient or cost-effective solutions for transmission needs Required regional and interregional transmission planning process that satisfies the transmission planning principles of Order No. 890 Coordinated, Open and transparent transmission planning Cost allocation method for new transmission facilities Cost allocation should be at least roughly commensurate with estimated benefits Cost allocation method and data requirements must be transparent Transmission Planning needs power flow and production cost model Power flow model: reliability, voltage stability, dynamic analysis, etc. Production cost model: economic dispatch, congestion, benefit calculation, cost allocation
3 Transmission Planning Goal: to identify efficient and cost-effective solutions to meet the transmission needs Transmission planning uses different tools Power flow study, using PSS/E, GE-PSLF, PowerWorld, etc. Economic transmission study, using GridView, PROMOD, etc. Data Sources and Challenges Different assumptions for future generation and transmission expansions Make the local area/region correct dispatch and topology is not enough Collaborate dispatch among multiple areas/regions may not be feasible, Due to non-coincident peaks and variable generation resources, it is difficult to predict generation dispatch and interchanges Interchanges may have significant impacts on results Not Well Coordinated
4 Proposed Transmission Planning Goal: to identify efficient and cost-effective solutions to meet the transmission needs Economic transmission study needs input from power flow case Topology, Impedance, Load distribution, Generator connections Consistent assumption for generation and transmission expansion Power flow study needs generation dispatch from economic study Generator dispatches, Bus loads, Estimated losses from economic study System wide coincident loads and generation dispatch based on security constrained economic dispatch to meet load and ancillary services Public policy (State RPS, Federal CPP, etc.) may change the way to operate system as of today; production cost model can provide the guidance on the dispatch changes.
Coordinated Transmission Planning with Economic Analysis 5 Generation dispatch in power flow should be security constrained economic dispatch, just as system operation Identify potential reliability concerns as renewable energy penetration increase: voltage support, ramping rates, inertia, frequency response, etc. Example: Southern California MinGen issues Transmission planning may be affected by generation dispatch Unit commitment determines voltage stability transfer limits, Central East Reliability Must Run Economic analysis consistent with power flow analysis Mimic market operation or utility operation closely (real power only) Production cost only enforces the selected limits; Power flow analysis requires all line/trans limits, VAR/voltage supports, inertia, and frequency response, etc.
6 Methodology Production Cost Run (8760) Production Cost w/solutions Extract dispatch for hours of interest Determine Cost/Benefit Transmission analysis If B/C < 1.25, examine alternative/additional solutions Develop transmission solutions
7 Coordinated Transmission Planning Process 1. Update production cost model with power flow case 2. Run 8760 hour simulation 3. Relax the highest congested constraint in the production cost model 4. Run 8760 hour simulation 5. Export power flow cases for selected hours (on-peak, off-peak) a. Solve it in AC solution b. Develop the transmission solutions to resolve violations under all selected hours ACàDC 6. Update transmission solutions to production cost model 7. Run 8760 hour simulation 8. Export power flow cases for selected hours (on-peak, off-peak) a. Solve it in AC solution ACàDC DCàAC DCàAC b. No violation in power flow analysis, then go to cost benefit analysis; otherwise, revise transmission solutions go to Step 7.
8 Cost-Benefit Curve Minimizing annual production costs and transmission costs 13000 11000 Pa 9000 Cost 7000 5000 3000 Cb Pb Ca 1000 Economic Comparison of Cases A (with RMR) & B (w/o RMR) Annual Production Cost Cost S A V I N G S Ta=Pa + Ca A Ta - Tb = Net Benefit B Tb=Pb +Cb Total Cost 1 6 New Transmission 11 Projects 16 Annualized Capital Cost for New Transmission
Example of Integrated Production Cost and Transmission Analysis 9 http://www.spp.org/publications/mbpc_summary_june%20report_final_r1.pdf
10 WOTAB - 2022 Benefit/Cost Ratio 180.00 Cost-Benefit Analysis 160.00 140.00 MUSD 120.00 100.00 80.00 Annualized Transmission Cost 60.00 40.00 Production Cost Benefit 20.00 Best Cost/Benefit Solution 0.00 WOTAB_5A WOTAB_5B WOTAB_5B1 WOTAB_5B2b WOTAB_5B2c WOTAB_5B3 Case
11 SPP Study Findings Benefit-to-cost ratios calculated for different load regions Benefit: Production cost savings Cost: Annualized cost of transmission additions In some areas, transmission costs outweighed benefits (RMR retained) In other areas, specific transmission projects pointed to savings in production costs Study identified cost-effective transmission projects that have potential to decrease overall cost
12 NTTG FERC Order 1000 NTTG Transmission Providers Attachment K s study process Evaluate the feasibility and reliability of system at peaking load and light load hours using power flow program Inconsistent power flow cases cause numerous issues NTTG initiated the round trip process that address these concerns in 2012 Round Trip (ACàDCàAC) Read a network data from AC power flow case into Production cost model Run Production cost model with updated network data Export any hour raw data to an AC Power Flow case Use power flow and production cost model as necessary to assess the impact from renewable resources or retirement of coal plants or loss of inertia Contribution from Jamie Austin, PacifiCorp
13 AC-DC-AC Round Trip Advantages Consistent topology amongst all selected hours Greater number of hours can be studied Dispatch based on economics Disadvantages Dispatch based on economics, it might not achieve rating level flows but generally would be a good starting point for a stressed case Generators in production cost model should match with generators in power flow case on a one-on-one or one-on-multiple basis. Gap generators lumped at area reference bus maybe OK for production cost model but it will not work for power flow case Contribution from Jamie Austin, Ron Schelberg
AC-DC-AC Round Trip 14
15 GridView Features to Make Round Trip Easier Update power flow by one click of button Export power flow for any given hour by one click of button Mapping generators in production cost model to generator in power flow so that the unit can have correct reactive cap Export a full power flow case with good estimated on losses Process reactive resources even it is not in production cost model Adjust reactive load as real power load changes DG generation will be netted to area load Data sanity check to make sure the generator in production cost model can be mapped uniquely to generators in power flow case
16 Contact Information Jinxiang (Jin) Zhu, Lan Trinh 901 Main Campus Drive, Suite 300 Raleigh, NC 27606 Phone: +1 919-807-8246 Cell: +1 919-389-9350 Email: Jinxiang.zhu@us.abb.com
1 2016 IEEE PES General Meeting July 17-21, Boston, MA Modeling Advanced PSH Technologies Across Different Timescales to Analyze their Role and Value in the Modern Power Grid (16PESGM2501) Presented by: Vladimir Koritarov Argonne National Laboratory koritarov@anl.gov 630-252-6711
DOE Funded a Study on the Modeling and Analysis of Value of Advanced Pumped Storage Hydro in the U.S. Clean energy goals require reliance on large amount of variable energy resources (VER), which makes electric grid difficult to manage PSH enables high penetration of VER: Provides large quantities of energy storage and full range of ancillary services necessary for grid operation Provides large amount of flexible dispatchable capacity Has none of the limitations of other flexible technologies like gas turbines and demand response Can mitigate over-generation of VER through storing and time-shifting excess generation Improves dynamic behavior and stability of power system 2 U.S. Energy Storage Capacity Mix Source: Grid Energy Storage, DOE 2013
3 Overview of Advanced PSH Study Project Team Main Objectives: Improve modeling representation of advanced PSH plants Quantify their capabilities to provide various grid services Analyze the value of these services under different market conditions and levels of variable renewable generation Provide information on full range of benefits and value of PSH Project website: http://ceeesa.es.anl.gov/projects/psh/psh.html
Analysis Addressed Wide Range of Operational Issues & Timeframes Analysis aimed to capture PSH dynamic responses and operational characteristics across different timescales, from a fraction of a second to days/weeks. 4 Source: Koritarov et al., 2014
5 Models - Spatial and Timescale Coverage Spatial Area/System Detail Grid component Region PSS/E FESTIV PLEXOS CHEERS 0.1 1 10 10 10 3 10 4 10 5 10 6 Time Step/Simulation Duration
Advanced Technology Modeling Model Development Model Development Developed vendor-neutral dynamic models for advanced PSH technologies (adjustable speed and ternary units) Review of existing CH and PSH models in use in the United States Dynamic simulation models for adjustable speed PSH Dynamic simulation models for ternary PSH units Comparison of system frequency with the FS and AS PSH units in response to generation outage in a test case AS PSH FS PSH 6
Advanced Technology Modeling Integration and Testing of Dynamic Models 7 Model Integration and Testing Dynamic models for adjustable speed PSH and ternary units were coded and integrated into the PSS E model Testing of these models for both generating and pumping mode of operation was performed using PSS E test cases and dynamic cases for Western Interconnection (WI) Additional AGC studies have been performed for SMUD balancing authority Published a report on frequency regulation capabilities of advanced PSH technologies
8 Production Cost and Reliability Simulations First, the Project Team developed a matrix of various PSH contributions and services provided to the power system A suite of computer models (PLEXOS, FESTIV, and CHEERS) was utilized to simulate system operation and analyze various operational issues occurring at different timescales Production cost and reliability simulations were performed to analyze the operation of PSH and the value of their services and contributions to the power system
PLEXOS Model with Detailed Representation of PSH was Used for Production Cost Simulations 9 Several levels of geographical scope, including the entire Western Interconnection, California, and SMUD Simulations were conducted for 2022 Multiple runs at different time resolutions Hourly simulations for the entire year to determine maintenance schedule of thermal units and annual-level PSH economics Runs at hourly and 5-min time steps for typical weeks in each season to analyze PSH operation under conditions of variability and uncertainty of renewable resources Simulations were based on detailed WI grid representation (3,700 generators, 17,000 transmission buses) and examined impact of different levels of wind and solar penetration
10 Production Cost Simulations with PLEXOS Cost-based approach was applied for WI and SMUD, while market-based approach was applied for California simulations Two sets of PLEXOS runs for each simulated system: Annual runs for Base and High Wind RE scenarios (DA runs with hourly time step and co-optimization of energy and ancillary services): Without PSH plants With existing conventional (fixed-speed) PSH plants With existing FS PSH and proposed new adjustable speed PSH Weekly runs for four typical weeks in different seasons (January, April, July, and October) applying three-stage approach (DA-HA-RT with 5-min time step) and co-optimization of energy and ancillary services: Without PSH plants With existing FS PSH plants With existing FS PSH and proposed adjustable speed PSH
Annual Simulation Results Show that PSH Significantly Reduces Power System Operating Costs 11 Production Cost Savings due to PSH Capacity in 2022 Annual System Production Cost Savings (%) 10 8 6 4 2 Western Interconnection Annual System Production Cost Savings (%) 10 8 6 4 2 California 0 No PSH With FS PSH With FS&AS PSH 0 No PSH With FS PSH With FS&AS PSH Base RE Scenario High Wind Scenario Base RE Scenario High Wind Scenario
Western Interconnect: PSH Provisions of System Reserves in 2022 (As % of Total System Requirements) 12 California:
Western Interconnection: Impact of PSH on RE Curtailments in 2022 13 Baseline RE scenario: High Wind RE scenario: RE curtailments reduced by 50% Annual generation of about 5,000 MW of wind capacity
PSH Impacts on Power System Emissions 14
Reductions in Thermal Generator Ramping 15
California: Thermal Generator Cycling in 2022 Baseline RE scenario: 16 High Wind RE scenario: FS & AS PSH plants reduce cycling cost of thermal units by one third
3-Stage (DA-HA-RT) Sequential Simulation Approach for Weekly PLEXOS Runs (5-min Time Step) 17
18 Summary of 3-Stage Modeling Results Detailed simulation (5-minute time step in RT simulations) of four typical weeks in different seasons of 2022 under High-Wind RE scenario Simulated: 3 rd weeks of January, April, July, and October 3 rd week in July is the peak load week Summary of 5-minute RT simulation results for High- Wind renewable generation scenario
FESTIV Model Was Used to Analyze the Impacts of PSH on Power System Reliability Impacts on PSH on ACE and steady-state reliability Simulated the operation of Balancing Authority of Northern California (BANC) during the third week in April and July of 2002 3 rd Week of April 2022 No PSH With FS PSH With AS PSH Total production cost ($ million) 3.449 3.169 3.032 Number of CPS2 violations 49 47 45 CPS2 Score (%) 95.1 95.3 95.5 Absolute ACE in Energy (AACEE) (MWh) 2,583 2,620 2,644 σ ACE (MW) 23.8 25.1 23.0 3 rd Week of July 2022 No PSH With FS PSH With AS PSH 5.394 $5.101 $5.021 40 16 15 96.0 98.4 98.5 3,201 2,736 2,593 29.3 21.3 20.2 19 150 Operation of Three FS PSH Units (One Day in April 2022) 150 Operation of Three AS PSH Units (One Day in April 2022) 100 Unit 1 Unit 2 Unit 3 100 Unit 1 Unit 2 Unit 3 50 50 MW 0 MW 0-50 -50-100 -100-150 95 100 105 110 115 120 Hour -150 50 55 60 65 70 Hour
20 CHEERS Was Used to Optimize Operations Co-optimization of PSH energy and ancillary services in generation and pump mode of FS and AS PSH Plants Energy generation Regulation Up & Down Spin & Non-Spin Reserves Optimal distribution of loads on individual PSH units Water Use Optimization Toolset (WUOT) CHEERS Conventional Hydropower Energy and Environmental Systems Source: Gasper et al., 2013
21 Hourly Operation of FS PSH (Unit 1, July, Wednesday) Max Generation Peak Efficiency Generation Rough Zone Min Generation Pumping Pumping Capacity
22 Hourly Operation of AS PSH (Unit 1, July, Wednesday) Max Generation Peak Efficiency Generation Rough Zone Min Generation Pumping Min Pumping Capacity Max Pumping Capacity
23 Additional Results, Details, and Information A total of 7 reports were published during the project Available at: http://ceeesa.es.anl.gov/projects/psh/psh.html U.S. Congress has also requested a report on the role a value of PSH in integrating VERs and on potential hydropower from conduits Detailed benefits of PSH for grid integration of VERs were documented in a supporting technical report Main Project Report
24 Contact: Vladimir Koritarov Tel: 630-252-6711 Argonne National Laboratory Email: koritarov@anl.gov 9700 S Cass Avenue, ES-362 Argonne, IL 60439
1 New Modeling Methodology for Renewable Energy Integration and Emerging Technology Studies Confidential and Proprietary Information. All Rights Reserved.
2 Overview Study methodology Case 1: PV integration impacts Case 2: Storage value assessment
3 Conventional study process overlooked operation details that are important to variable generation and storage. Lacking capability to investigate what s happening within an operation hour, which is information important to reliability and economics! Load, resource, fuel price and market data Scheduling Tool Resource Plan AGC Real-time Dispatch Unit Commitment Resource Planning Second Minute Hour Week Month Year Generator Start Time Generator Construction
New methodology expands the capability of existing tools and process. 4 Operation details within an hour is revealed by minutely simulation time step. Resource Schedules ESIOS Scheduling Tool Resource Plan AGC Real-time Dispatch Unit Commitment Resource Planning Second Minute Hour Week Month Year Generator Power Adj. Time Generator Start Time Generator Construction
5 Adding transmission models further enables the assessment of transmission impacts and optimal placement of new technologies. The most comprehensive evaluation process for integrating renewable and emerging technologies.
The methodology has been implemented in several types of studies. 6 Photovoltaic Generation Impacts for Generation and Transmission Systems Value Assessment of Emerging Technologies for the Integration of PV Generation Photovoltaic Generation Forecast Value Assessment
PV impacts studies quantify challenges and costs to integrating PV generation. 7 Key metric (reliability): control performance CPS2 or BAAL Key metric (economics): integration cost of PV energy per kwh Methodology: Production simulations for the entire year with PV and with reference generation Hourly scheduling (e.g., GenTrader, PLEXOS, PROMOD, PROSYM) Real-time AGC and operator dispatch of peaking units (ESIOS) Additional outcomes: Operating reserve requirements in PV cases Challenging operation hours Impact of using BAAL vs. CPS2 Value of improved load and PV forecasts Value of flexibility with generation fleet (and storage, DSM, dispatchable PV generation, etc.)
PV impacts assessment showed significant increase of regulation requirements and use of quick start units*. 8 DA Planning Reserve UP (Normalized) Regulation Reserve UP (Normalized) 1.4 1.2 1 0.8 0.6 0.4 0.2 0 2.5 2 1.5 1 0.5 0 0 0.05 0.1 0.15 0.2 PV Capacity Penetration w.r.t Peak Load 0 0.05 0.1 0.15 0.2 PV Capacity Penetration Operating reserve requirements increase with PV penetration. Low Mid High Integration cost per MWh of PV generation $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 -$2.00 2014 2016 2018 2020 2022 PV integration cost increases with PV penetration. Market *Source: S Lu, M Warwick, N Samaan, J Fuller, D Meng, R Diao, F Chassin, T Nguyen, Y Zhang, C Jin, and B Vyakaranam. 2014. Duke Energy Photovoltaic Integration Study: Carolinas Service Areas. PNNL-23226, Pacific Northwest National Laboratory, Richland, Washington. Available at http://www.pnnl.gov/main/publications/external/technical_reports/pnnl-23226.pdf ES CT AGC Base
9 ESIOS operates all resources participating in real-time dispatch and determines PV integration cost components. $/MWh 7 6 5 4 3 2 1 0-1 PV Integration Cost Component AGC fuel AGC OM CT fuel CT OM CT Start Up ES OM ES StartUp Series1 1.746058-0.08957 5.807057 0.056649 0.969619 0.138969 0.098064
Peaker dispatch in real time (blue line) is similar or less than hourly schedule (red line) in low PV cases. 10
Peaker dispatch in real time (blue line) is a lot more than hourly schedule (red line) in high PV cases. 11
12 Emerging technology studies quantify costs and benefits of storage and other new techs for integrating PV generation Key metric (reliability): control performance CPS2 or BAAL Key metric (economics): energy production cost reduction per unit (MWh) of new technology Methodology: Production simulations for the entire year with and without new technologies Hourly scheduling (e.g., GenTrader, PLEXOS, PROMOD, PROSYM) Real-time AGC and dispatch of peaking units and new technologies (ESIOS) Use hourly dispatch to run chronological AC power flow for the whole system (PSS/E) Additional outcomes: Optimal installation capacity of new technologies Optimal placement of new technologies
Adding transmission models further enables the assessment of transmission impacts and selecting optimal storage locations 13
Value of storage comes from reducing peaking capacity and energy provided by quick start units, with additional transmission benefits Generation Energy arbitrage by GenTrader - optimally determine charge and discharge schedules for storage devices Regulation service dispatched by ESIOS control storage charge and discharge rate based on regulation needs, and maintain hourly energy schedule determined by GenTrader Transmission Transmission capacity expansion deferral storage devices are placed under buses where peak flows are close to transformer capacity limits Transmission loss reduction reducing transmission losses by leveling load profile Increased reliability during contingencies 14
15 Battery storage is dispatched based on hourly energy schedule as well as following load shape to reduce regulation requirements from generators. 250 200 150 100 50 0 7000 6000 5000 4000 3000 2000 1000 0 Battery OP 1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 101 105 109 113 117 Net load 1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 101 105 109 113 117
Peak power flows on transformers could be reduced by storage to defer the need for capacity expansion 16
At appropriate amount and locations, storage devices can justify their costs Appropriate selection of storage size could allow the claim of capacity value of storage, by avoiding developing new peaking units Storage showed more values in the PV cases, where more peaking units are dispatched to catch up with the increased variability Transmission Increasing installation capacity of storage in the system would reduce the per MW value of storage, i.e., the return diminishes with increase of volume At locations where peaking units are occasionally needed to increase reliability, it could be more economic to use storage which can provide constant benefits to the system 17
18 Please contact us for any questions. Phone: (512)782-9708 Email: Info@EnerMod.com N e w A n a l y t i c s. N e w O p p o r t u n i t i e s.