Grid Integration Costs: Impact of The IRP Capacity Mix on System Operations Presenter: Bernard Magoro, System Operator, Transmission Division, Eskom SOC Holdings Date: 05 October 2018
Contents 1. Background 2. What are Grid Integration Costs? 3. The role of the System Operator 4. Impact of IRP capacity mix on System Operations 4.1 Migration from conventional-based to inverter-based generation 4.2 Observations from current RE penetration 4.3 Operational considerations 5. International experience on operations 6. Assessments required for the future grid operation 7. Conclusion 2
Background One of the key objectives of the IRP is to ensure there is security of supply by optimising demand and supply of energy based on a policy adjusted least cost path. However, grid integration costs (connection and grid stability costs) are not always factored into the IRP process. This presentation only focuses on grid stability costs System Operator (SO) has a mandate to control the operation of and be responsible for the short term reliability of the interconnected power system as defined in the South African Grid Code. The future capacity mix envisages an increase of generation capacity from non-synchronous or inverter based technologies. This is transforming how the grid is operated into the future. At the current renewable energy (RE) penetration levels, SO is already noticing a change in Grid operational performance, e.g. load forecasting, power flows, system stability etc Other potential challenges include energy dumping, increased ramp rates, lower inertia etc. To respond to these challenges, SO has identified a number of activities in preparation to operate a more complex future grid. Traditional ancillary services will have to evolve 3 with the changing system needs.
Grid Connection Costs are Regulated by the SA Grid Codes 4
Grid Stability Costs? Power oscillations Incidents and load following 5
What is the System Operator? Transmission & Distribution transports the electricity Customer Services sells the electricity The System Operator is the electricity transport and distribution supervisor. Generation makes the electricity System Operator ensures continuous delivery of quality electricity by maintaining a stable network
Balancing supply and demand 49.5 50.0 50.5 Generation Load Generation output is changed every 4 seconds to match customer demand. When there is insufficient generation available, customer demand is reduced to ensure system stability is maintained.
Meeting Demand with Traditional Technologies (TT) Peak Capacity Dispatched Ramping Energy Sync power System strength Frequency Voltage Fuel Capital Fundamental What is the optimal mix? Mid merit Gx Base Load Gx Peeking Gx Outcome from the optimisation process Gas Hydro / Pump Storage Coal Nuclear Levelized cost of electricity (LCOE) It includes the initial capital, discount rate, as well as the costs of continuous operation, fuel, and maintenance. Peak Capacity Dispatched Ramping Energy Sync power System strength Frequency Voltage R / MWh https://en.wikipedia.org/wiki/cost_of_electricity_by_source
Challenges (or Opportunities) from New Technologies Wind & Solar are efficient at producing Energy But not other services Peak Capacity Dispatched Ramping Energy Sync power System strength Frequency Voltage Wind Solar Increase ramping higher value short time Need Peak Capacity Capacity for uncertainty System Strength
Relative Comparison of Reliability Contributions of Resource Groups [3] 0 indicates no ability to contribute to reliability function 5 indicates full capability to contribute to reliability function Inverter based generation has a lower contribution to reliability compared to synchronous sources SO will need to procure additional ancillary services that was provided by synchronous generators 10
Traditional Ancillary Services From Generation and Load Reserves Reactive Power & Voltage Control From Generation only Constrained Generation Black-start & Islanding Ancillary Services refer to services, coordinated by the SO, required to ensure security, stability and power quality and support the capability of the network to transfer supply of electricity to customers. Peak Capacity Dispatched Ramping Energy Sync power System strength Frequency Voltage SO is currently reviewing the adequacy of ancillary services needed to operate the future grid
Draft IRP 2018 Capacity Mix up to 2030 2018 Generation Mix About 25% of PV+Wind is expected by 2030 [1] Substantial reduction in coal fired generation mix Will the additional gas/ diesel generation capacity improve inertia & flexibility? Where will the gas and hydro generation be located, as this will impact the operation of the grid? 12
00:00 to 01:00 01:00 to 02:00 02:00 to 03:00 03:00 to 04:00 04:00 to 05:00 05:00 to 06:00 06:00 to 07:00 07:00 to 08:00 08:00 to 09:00 09:00 to 10:00 10:00 to 11:00 11:00 to 12:00 12:00 to 13:00 13:00 to 14:00 14:00 to 15:00 15:00 to 16:00 16:00 to 17:00 17:00 to 18:00 18:00 to 19:00 19:00 to 20:00 20:00 to 21:00 21:00 to 22:00 22:00 to 23:00 23:00 to 00:00 Change in Demand Profile [4] Actual 2018 Summer Profile for Residual Demand Actual 2018 Summer Profile for RSA Contracted Demand 35000 34000 33000 32000 31000 30000 29000 28000 27000 26000 25000 24000 23000 22000 21000 MW Night Minimum Actual 2018 Winter Profile for Residual Demand Day min demand Actual 2018 Winter Profile for RSA Contracted Demand Steeper ramping 12000 MW Residual demand supplied by conventional dispatchable generation Increased in requirements for flexibility (Lower Min gen, Higher ramp rates and cycling times) Lower day troughs and steeper afternoon ramps are evident duck curve/ camel hump effect 13 Hours
Flexibility is Currently Provided by Coal, Gas and Pump Storage 2018/10/08 14
International Experience with integrating New Technologies [2] Eirgrid A composite measure was developed to monitor system non-synchronous penetration in real time Following an exhaustive set of simulations, the following requirements were determined: o Minimum inertia +/- 22600 MWs (with a system peak of 6500 MW in 2016) o Maximum RoCoF of 0.5 Hz/s South Australia Black Out In September 2016, a load of 2000MW was supplied by imports (48%), wind generation (34%) and conventional (18%). Severe storms caused cascading events resulting in loss of 75% of wind power. Due to few synchronous generators connected, frequency declined rapidly. RoCoF went to 6Hz/s which was faster than UFLS Electric Reliability Council of Texas (ERCOT) ERCOT (80 000 MW) has determined the following limits to avoid UFLS (at 59.3 Hz): o A critical inertia limit of 100 GWs o Keep frequency above 59.4 Hz following the loss of largest contingency (2750MW) 15
From Ancillary Services to Essential Services [6] Peak Gx, Demand side, Battery, etc Requirements for Inertia, Flecibility, Ramping, Cycling will increase costs in future 16 Ramping Gx, Battery, etc Flywheels, Synchronous condensers, Gx in SCO mode, Statcoms etc.
Key Considerations when Assessing Operational Impact [2] Assessment focus area Technical Frequency stability Rotor angle stability Voltage control Fault level Reactive power Electro magnetic transient (EMT) Power quality & reliability System flexibility Real time monitoring Assessment or study to be conducted Study declining inertia, inter-area oscillatory stability & sources of primary reserve Determine the impact of reduced inertia on critical fault clearing times Determine if required voltage control can be achieved in areas with low fault levels Establish how to quantify min fault level required to ensure RE generation operates Determine additional Mvar sources required to cater for increased RE penetration Determine potential range of the change in transient recovery voltage after switching or system disturbances Evaluate procedures for assessing power quality emissions with high RE penetration Develop a framework for implementation of system flexibility in energy planning and operations environments. Review scheduling and dispatch rules. Develop a method for situational awareness Operational Tx-Dx operator interaction Protection Aggregators Map out Tx and Dx responsibilities under normal and emergency conditions Conduct Out-of-Step tripping and Power Swing Blocking systems and co-ordination of Tx back-up protection Facilitate dispatch and communication between National Control and agenerators Regulatory Grid code review Review Grid Code to define minimum grid reliability and stability requirements 17
Typical Studies Required to Operate the Future Grid [5] SO studies IRP SO conducts complex studies for timeframes ranging from milliseconds to years Assumptions and considerations for SO and IRP studies should be aligned 18
Framework for Assessing RE impact onto the Grid [5] Expected 2030 RE penetration Current RE penetration 19
Conclusions Despite the choice of the IRP capacity mix, the core role of the SO will remain critical, underpinned by the mandate to maintain a safe, secure and reliable grid Unlike its counterparts in America and Europe which are confined in smaller geographical areas and highly interconnected, the South African grid is: weakly interconnected to neighboring countries spread over a large geographical area with long transmission lines linking the main Gx pools New technologies are just different and the grid operators are findings ways to respond Grid management costs are expected to rise resulting from: Additional essential services to traditional ancillary services Additional operational costs to make conventional generation more flexible (higher ramp rates, lower min stable gen levels) Close interaction between SO and the DSOs, (e.g. associated telecommunication) IRP, Grid Codes, PPAs should also align with the future grid operational requirements 20
Thank you
Bibliography [1] DoE, 2018, Draft Integrated Resource Plan 2018 [2] Eskom, 2018, Key Technical Considerations for Large Scale Renewable Energy Grid Integration in South Africa report [3] EPRI, 2015, Contributions of Supply and Demand Resources to Required Power System Reliability Services [4] H Bower, 2018, Impact of Renewables on Load Forecasting presentation [5] N Mararakanye, B Bekker, 2018, A conceptual framework for assessing the impact of intermittent renewable energy systems on the grid paper [6] J O Sullivan, 2017, Ireland s relevance to Global Electricity Markets 22