Chance-Constrained Outage Scheduling using a Machine Learning Proxy

Outage scheduling aims at defining, over a horizon of several months to years, when different components needing maintenance should be taken out of operation. Its objective is to minimize operation-cost expectation while satisfying reliability-related constraints. We propose a distributed scenario-based chance-constrained optimization formulation for this problem. To tackle tractability issues arising in large networks, we use machine learning to build a proxy for predicting outcomes of power system operation processes in this context. On the IEEE-RTS79 and IEEE-RTS96 networks, our solution obtains cheaper and more reliable plans than other candidates

Long-term power system capacity expansion planning considering reliability and economic criteria

Before the deregulation of the electric industry, a vertically integrated utility made planning decisions for both the generation system and the transmission system according to reliability criteria. The deregulation of the electric industry has resulted in an unbundling of the long-term planning function for generation and transmission systems. In the deregulated world, transmission planning is different from that in the regulated environment. In this study, we present a market-based transmission expansion planning model and compare it with a traditional reliability-based transmission planning model. Reliability-based transmission planning tries to install new lines at minimal cost while fulfilling system reliability criteria. Market-based transmission planning, on the other hand, seeks investment opportunities so that network expansions can generate more economic benefits than the costs. Benders decomposition technique is employed in both methods, and their master problems and slave problems are compared, respectively. The scalability of the market-based transmission planning algorithm is also discussed. Various uncertainties occur in the planning process. Uncertainties appearing in the planning process are analyzed systematically and classified into random and non-random uncertainties. Monte Carlo simulation method is applied to simulate random uncertainties, while robustness testing method is employed to incorporate non-random uncertainties. Most planning optimization tools optimize generation expansion plans under an assumed transmission expansion plan, or they optimize transmission expansion plans under an assumed generation expansion plan. In practice, engineers typically find optimal transmission expansion plans for various generation expansion futures, often iterating between generation planning and transmission planning results, settling on those transmission expansion plans which are needed under most or all of the generation expansion futures. Inadequately accounting for the interdependency between the two planning processes may result in suboptimal investment decisions and lost economic benefits. In this article, the interactions between large-scale wind integration and transmission system planning are analyzed, and a new computational procedure of system expansion planning that coordinates generation and transmission investment is proposed

Generation expansion planning optimisation with renewable energy integration: A review

Generation expansion planning consists of finding the optimal long-term plan for the construction of new generation capacity subject to various economic and technical constraints. It usually involves solving a large-scale, non-linear discrete and dynamic optimisation problem in a highly constrained and uncertain environment. Traditional approaches to capacity planning have focused on achieving a least-cost plan. During the last two decades however, new paradigms for expansion planning have emerged that are driven by environmental and political factors. This has resulted in the formulation of multi-criteria approaches that enable power system planners to simultaneously consider multiple and conflicting objectives in the decision-making process. More recently, the increasing integration of intermittent renewable energy sources in the grid to sustain power system decarbonisation and energy security has introduced new challenges. Such a transition spawns new dynamics pertaining to the variability and uncertainty of these generation resources in determining the best mix. In addition to ensuring adequacy of generation capacity, it is essential to consider the operational characteristics of the generation sources in the planning process. In this paper, we first review the evolution of generation expansion planning techniques in the face of more stringent environmental policies and growing uncertainty. More importantly, we highlight the emerging challenges presented by the intermittent nature of some renewable energy sources. In particular, we discuss the power supply adequacy and operational flexibility issues introduced by variable renewable sources as well as the attempts made to address them. Finally, we identify important future research directions

Hydropower Scheduling Toolchains:Comparing Experiences in Brazil, Norway,and USA and Implications for Synergistic Research

While hydropower scheduling is a well-defined problem, there are institutional differences that need to be identified to promoteconstructive and synergistic research. We study how established toolchains of computer models are organized to assist operational hydro-power scheduling in Brazil, Norway, and the United States’Colorado River System (CRS). These three systems have vast hydropowerresources, with numerous, geographically widespread, and complex reservoir systems. Although the underlying objective of hydropowerscheduling is essentially the same, the systems are operated in different market contexts and with different alternative uses of water, where thestakeholders’objectives clearly differ. This in turn leads to different approaches when it comes to the scope, organization, and use of modelsfor operational hydropower scheduling and the information flow between the models. We describe these hydropower scheduling toolchains,identify the similarities and differences, and shed light on the original ideas that motivated their creation. We then discuss the need to improveand extend the current toolchains and the opportunities to synergistic research that embrace those contextual differences.Hydropower Scheduling Toolchains:Comparing Experiences in Brazil, Norway,and USA and Implications for Synergistic ResearchacceptedVersio

Flexible Transmission Network Planning Considering the Impacts of Distributed Generation

The restructuring of global power industries has introduced a number of challenges, such as conflicting planning objectives and increasing uncertainties,to transmission network planners. During the recent past, a number of distributed generation technologies also reached a stage allowing large scale implementation, which will profoundly influence the power industry, as well as the practice of transmission network expansion. In the new market environment, new approaches are needed to meet the above challenges. In this paper, a market simulation based method is employed to assess the economical attractiveness of different generation technologies, based on which future scenarios of generation expansion can be formed. A multi-objective optimization model for transmission expansion planning is then presented. A novel approach is proposed to select transmission expansion plans that are flexible given the uncertainties of generation expansion, system load and other market variables. Comprehensive case studies will be conducted to investigate the performance of our approach. In addition, the proposed method will be employed to study the impacts of distributed generation, especially on transmission expansion planning.

Model Predictive Control for Smart Grids with Multiple Electric-Vehicle Charging Stations

Next-generation power grids will likely enable concurrent service for residences and plug-in electric vehicles (PEVs). While the residence power demand profile is known and thus can be considered inelastic, the PEVs' power demand is only known after random PEVs' arrivals. PEV charging scheduling aims at minimizing the potential impact of the massive integration of PEVs into power grids to save service costs to customers while power control aims at minimizing the cost of power generation subject to operating constraints and meeting demand. The present paper develops a model predictive control (MPC)- based approach to address the joint PEV charging scheduling and power control to minimize both PEV charging cost and energy generation cost in meeting both residence and PEV power demands. Unlike in related works, no assumptions are made about the probability distribution of PEVs' arrivals, the known PEVs' future demand, or the unlimited charging capacity of PEVs. The proposed approach is shown to achieve a globally optimal solution. Numerical results for IEEE benchmark power grids serving Tesla Model S PEVs show the merit of this approach