Operational flexibility of future generation portfolios with high renewables

The costs and technical implications of thermal plant operating constraints within high renewable electricity systems are receiving growing attention. However, many future scenario modelling studies take limited consideration of such constraints. In this study, different generation portfolios were modelled over a year’s dispatch for the Australian National Electricity Market (NEM), to examine operational impacts and the costs of different power plant operating constraints. As the level of variable renewable energy (VRE) increases, thermal plants are subject to frequent cycling (ramp up/down and start/stop) as they are dispatched to accommodate the outputs of VRE. However, the extent of the operational impact depends on the mix of conventional technologies within the portfolio. Many coal and gas operational constraints were found to be inexpensive, even in a 85% renewable scenario with primarily wind and solar generation. The combined impact of ramp rate constraints, minimum generation constraints and start-up costs was found to add only 0.1–3% to total annual system costs. In contrast, a minimum synchronous generation (SG) constraint (intended to maintain minimum levels of system inertia) was found to have a significant impact on system costs when the renewable energy penetration exceeds 40%, and a moderate cost of greenhouse emissions is assumed. For a renewable share of less than 40%, the SG requirement has negligible impact since synchronous generators are already supplying at least 40% of the demand in each dispatch period. A 50% SG requirement increases total system cost by 20% in a 85% renewable portfolio. Similarly, costs are increased by 10% in a 60% renewable portfolio. This suggests significant value in investigating measures that minimize the need for a stringent SG constraint in a future carbon constrained world.