Pandelis N. Biskas

A decentralized solution to the DC-OPF of interconnected power systems

This paper presents a new method for the decentralized solution of the DC optimal power flow (OPF) problem in large interconnected power systems. The method decomposes the overall OPF problem of a multiarea system into independent OPF subproblems, one for each area. The solutions of the OPF subproblems of the different areas are coordinated through a pricing mechanism until they converge to the global OPF solution. The prices used for the coordination of the subproblem solutions are the prices of electricity exchanges between adjacent areas. Test results from the application of the method to the three-area RTS-96 and the Balkan power system are reported.

Multiple Time Resolution Unit Commitment for Short-Term Operations Scheduling Under High Renewable Penetration

This paper introduces the idea of unified unit commitment and economic dispatch modeling within a unique tool that performs economic dispatch with up to 24-hour look-ahead capability. The tool provides financially binding dispatch and ex-ante locational marginal prices (LMPs) for the next 5-min interval and advisory commitment, dispatch schedule and prices for the remaining scheduling horizon. Variable time resolution and variable modeling complexity are used in order to reduce computational requirements. A finer time resolution and detailed modeling are used during the first hours of the scheduling horizon while coarser time resolution and simplified modeling during the last ones. The viability of the method for medium-sized systems is demonstrated through its application to the Greek power system.

European Electricity Market Integration With Mixed Market Designs—Part I: Formulation

The integration of the day-ahead electricity markets in Europe shall lead to one multi-area market that will substitute the local/national ones. In view of the “target model” that will be enforced in all European markets in conjunction with their forthcoming coupling/integration, a centralized market splitting algorithm is implemented in this paper, respecting the standard market regulatory framework of power exchanges (PXs) and power pools, including 1) block offers/bids, linked block offers/bids, flexible hourly offers/bids and convertible block offers in power exchanges and 2) unit technical/commitment constraints and system operating constraints in power pools. The problem is formulated as a mixed integer linear programming (MILP) model, which can be solved using commercial MILP solvers. The performance and computational requirements of an implementation in pan-European level is presented in the companion paper; the model is tested in terms of problem solvability to its limits, considering a day-ahead market clearing time threshold equal to one hour.

Demand Response in a Real-Time Balancing Market Clearing With Pay-As-Bid Pricing

The vast installation of intermittent energy sources (especially wind) has distorted the normal strict pattern of the net demand (demand minus RES production), increasing the importance of real-time balancing markets, which handle efficiently imbalances between supply and demand. In this paper, the incorporation of demand response bids within a real-time balancing market is modeled. The price signal, to which the demand responds, is a price derived from the total cost incurred by increasing or decreasing power of generation units, with a pay-as-bid pricing scheme. The demand price is defined implicitly as a function of the upward and downward supply offers. The proposed balancing market clearing model is formulated as a mixed complementarity problem. All inter-zonal and intra-zonal dc transmission constraints are incorporated to the problem, thus making it a problem of interregional balancing, and nodal prices are derived from its clearing. The credits/debits to generators for providing balancing energy are balanced in zonal and system level with the debits/credits of elastic and inelastic demand entities. The proposed model can be useful for designing future real-time balancing markets, in view of the forthcoming active participation of price-responsive demand and the significant RES penetration targets set by most countries.

Application of time series and artificial neural network models in short-term forecasting of PV power generation

This paper addresses two practical methods for electricity generation forecasting of grid-connected PV plants. The first model is based on seasonal ARIMA time-series analysis and is further improved by incorporating short-term solar radiation forecasts derived from NWP models. The second model adopts artificial neural networks with multiple inputs. Day-ahead and rolling intra-day forecast updates are implemented to evaluate the forecasting errors. All models are compared in terms of the Normalized (with respect to the PV installed capacity) Root Mean Square Error (NRMSE). Simulation results from the application of the forecasting models in different PV plants of the Greek power system are presented.

Balancing Supply and Demand Under Mixed Pricing Rules in Multi-Area Electricity Markets

Market clearing has always been an issue of great interest and research as liberalized electricity markets evolved over time in many countries. As trading in electricity evolves rapidly, multi-area power exchanges appear to substitute the local markets. The tie-lines constitute a significant parameter in multi-area power exchanges, since congestion leads to price differentiation. Prices are affected by physical (e.g., network) constraints, yet they should sometimes follow regulatory policy rules, which do not necessarily reflect or depend on physical characteristics. Until now, all approaches in clearing a multi-area power dispatch (or a multi-area market) are based on a zonal or nodal pricing model, which is applied uniformly to both production and demand within the same zone (or at each node). These approaches are not able to deal with complex pricing rules, which impose price discrimination for supply or demand entities within the same area. This paper presents a mathematical approach for the solution of a multi-area dispatch, in which production and demand of the same area may be cleared in different prices. The main principle is the formulation of a mixed complementarity problem for the system equilibrium conditions, in which supply and demand are associated to explicitly or implicitly defined prices. Illustrative implementations and test results for a simple five-zone system and the 73-bus IEEE RTS-96 are presented.

Simultaneous Clearing of Energy and Reserves in Multi-Area Markets Under Mixed Pricing Rules

The integration of the spot electricity markets in Europe shall lead to multi-area power exchanges that will substitute the local markets. In such scheme, market prices are affected by physical (e.g., network) constraints, yet they should sometimes follow regulatory policy rules, which do not necessarily reflect or depend on physical characteristics. In some cases, complex pricing rules should be implemented, which impose price discrimination for supply and demand entities within the same area. The methodology presented in this paper enables the balancing of supply and demand in a multi-area market considering energy and reserve bids, under complex pricing rules, which mix energy and reserve prices. A demand bid corresponds to the whole cost a demand entity is willing to pay for its participation in the energy market, including the cost for the procurement of the necessary reserves. The approach attains price integration of energy and reserves markets, simultaneous settlement of energy and reserves, and significant decrease of the payments through the uplift accounts. The main principle is the formulation of a mixed complementarity problem for the system equilibrium conditions, in which supply and demand are associated to explicitly or implicitly defined prices, which may be different even in the same zone.

A unified unit commitment — Economic dispatch model for short-term power system scheduling under high wind energy penetration

This paper presents a unified unit commitment and economic dispatch tool for the short-term scheduling of a power system under high renewable penetration. The proposed model uses variable time resolution and scheduling horizon extended up to 36 hours ahead and produces robust real-time decisions making the short-term operation of the power system almost insensitive to RES forecast errors. The proposed model is tested for a monthly period on the Greek interconnected power system using real load and wind power data for two different wind penetration levels. Simulation results show that the proposed methodology allows for the accommodation of large amounts of wind energy into the short-term scheduling of the power system at minimum cost.

Multiple Time Resolution Stochastic Scheduling for Systems With High Renewable Penetration

This paper presents a stochastic unified unit commitment and economic dispatch model for short-term operations scheduling of power systems with high renewable penetration. The model is a unique stochastic real-time tool that performs economic dispatch with up to 36-hour look-ahead capability, providing dispatch instructions for the first time interval and advisory commitment and dispatch schedules for the remaining scheduling horizon. Variable time resolution is used to contain computational requirements, i.e., finer time resolution is used during the first hours and coarser time resolution during the last hours of the scheduling horizon. The mathematical formulation comprises a MILP problem and it is presented as a two-stage scenario-based stochastic, multiple time resolution unit commitment model. The proposed stochastic model is tested against its deterministic counterpart via an annual simulation of Greek power system short-term operations using real 2013 data. Performance indices concerning dispatch costs, energy balances, and unit cycling are calculated and discussed.

European market coupling algorithm incorporating clearing conditions of block and complex orders

In this paper an algorithm for the solution of the European electricity market coupling is presented, considering all block and complex orders available in the European Power Exchanges. The model takes into account the clearing conditions of profile and regular block orders, linked block orders, exclusive group of block orders and flexible hourly orders, as well as the clearing conditions of Minimum Income Condition and Load Gradient orders, possibly under a scheduled stop condition. The model considers also hourly flow ramping constraints on single interconnections or group of interconnections, net position ramping constraints, interconnection losses and tariffs. The flow-based approach is implemented, using the zonal PTDF matrix. The algorithm eliminates possible paradoxically accepted block and MIC orders within an iterative process. The proposed algorithm is evaluated in a pan-European day-ahead electricity marketplace.