Modeling of wind generation fluctuations in a dispatch model

Abstract

The speed of wind at the different wind generator sites fluctuates due to weather variations over time. As a result, the wind generations may fluctuate over a wide range. The fluctuations and uncertainty are presently covered, in the New Zealand electricity market (NZEM), by the reserves originally offered for the protection of larger risk units in the system and frequency regulating reserve with no cost to the wind generators. In fact, smaller units benefit from the magnitude of reserves determined by the largest risk units. The frequency of outage of wind generators and variability of wind generation outputs is quite high compared to other smaller units and these frequently need a considerable amount of reserves to cover the generation fluctuations. The wind generators, therefore, free ride on other reserve providers adding cost to the system but not necessarily sharing them in an equitable manner. This issue has not been addressed so far. We develop a dispatch optimization model that recognizes the additional risk imposed by the wind generators. The model is based on DC-OPF, driven by generator risk contingencies, security margins at the load buses to cover the large variation of load, and security margins at the wind generator buses to account for the uncertainty of wind generations. The margins are maintained using reserves. The margin required at each wind generator bus is an input to the model and can be estimated statistically from its past performance. The main thrust of this paper is to examine the effect of security margin constraints at the wind generator buses and also at the load buses on the nodal spot prices. The paper demonstrates that the generation, and demand prices at a bus are different in the presence of binding security margin constraints. Generation prices at the wind generator buses get reduced in the presence of binding security margin constraints at these buses.