Hossein Farahmand

Balancing Market Integration in the Northern European Continent: A 2030 Case Study

Increased production flexibility will be needed for the operation of a future power system with more uncertainty due to an increased share of uncontrollable generation from renewable sources. Wind energy is expected to cover a large portion of the future renewable generation. In this paper, a comparison is carried out between two balancing market models, simulating a non- and fully-integrated northern European market in a future 2030 scenario. Wind power is modelled based on high resolution numerical weather prediction models and wind speed measurement for actual and forecasted wind power production. The day-ahead dispatch and balancing energy markets are settled separately. First, the day-ahead market is modelled with simultaneous reserve procurement for northern continental Europe. Available transmission capacity is taken into account in the reserve procurement phase. In a second step, the balancing energy market is modelled as a real-time power dispatch on the basis of the day-ahead market clearing results. The results show the benefit of balancing market integration for the handling of variable production. Cost savings are obtained from balancing market integration due to less activation of reserves resulting from imbalance netting and increased availability of cheaper balancing resources when integrating larger geographical areas.

Modelling of prices using the volume in the Norwegian regulating power market

A statistical model of the regulating market based on the regulating volume is proposed. The modelling process is divided into two steps; a long term and a short term study. The long term study is based on recorded data for 5 years. This analysis provides a statistical model of regulating prices and volumes for the whole market for the considered period. The combination of the long term model with expected regulating states and volumes is used in order to generate short term scenarios of the regulating market. The regulating state determination uses a Seasonal Auto Regressive Integrated Moving Average (SARIMA) process. The regulating volume scenarios are generated by using the statistical properties of the regulating volume based on recorded data. The proposed model is based on data from southern Norway and the result is a model estimating the regulating prices using the estimated regulating volumes. The resulting model makes it possible to estimate regulating market prices under changing conditions, like those occurring when different national markets are integrated.

Flow based activation of reserves in the Nordic power system

In the Nordic market, manually activated tertiary control based on bids for upward and downward regulation is used for system balancing. Although a system wide merit order list is used, the resulting regulation is suboptimal because of the congestion and the effect of losses, which are not taken into account. This paper proposes an algorithm for the dispatch of regulation resources based on an incremental DC optimal power flow formulation. The results of this model are compared with todays practice for some cases of up- and downward regulation, and a potential for cost reduction is observed. However, the method requires Automatic Generation Control that is not in use in the system, although it is presently evaluated. Also pricing of regulation is an issue, because Location Marginal Prices probably are unacceptable to market participants.

Optimal wind farm bids under different balancing market arrangements

If a wind power producer must pay the costs of imbalances, the question arises of what is the optimal bid, given the market rules and the statistical properties of the wind forecasts and the imbalance prices. In this paper we derive optimal wind power bids for two sets of market rules, reflecting previous and new rules in the Nordic power system. The optimal bids are based on the evaluation of a large number of scenarios for the realizations of the wind forecasts and the balancing market prices respectively. Scenario aggregation is used to limit the total number of scenarios. The wind forecast errors are described by a traditional ARMA model. The balancing market prices are described by a model that uses time series and statistical models of the volumes and prices on the balancing market. The optimal bid in the so-called 1-price system will normally be to either bid zero or maximum production. In the alternative 2-price system, the optimal bid will be close to expected production. For the particular case study in this paper, the optimal bid for the 1-price system gives an improvement in total revenues of 2.5%, while there is no observable improvement for the 2-price system. As such, the new system does give incentives to wind power producers to bid “correctly”. However, the total revenues for the wind park are reduced with 2% in the 2-price system, compared with the 1-price system.

Impact of system power losses on the value of an offshore grid for North Sea offshore wind

Grid connection is a critical factor for the integration of large scale wind power. This factor is even more important in the framework of transnational power exchange which is a way to improve power system operation. In this paper a comparison study has been carried out between two different grid building strategies for offshore wind farms in the North Sea using the 2030 medium wind scenario from the TradeWind project [1]. These strategies are i) radial and ii) meshed grid configuration. The paper has considered active power losses for both strategies and capture the effect of losses on different power system aspects, such as the total soci-economic benefit associated with each strategy, offshore wind power utilization, power exchange between the grid points, grid bottlenecks and utilization of HVDC connections. Using a meshed grid compared to radial there will be a total benefit of 2.7 billion Euro over the economic life time of the grid. However this benefit will be increased by 0.3 billion Euro by taking into account the grid losses for both cases. The results shows the benefit of using meshed offshore grid for future European power system with a large penetration of off- and onshore wind power.

Benefits of cross-border reserve procurement based on pre-allocation of transmission capacity

Integration of national balancing markets is one of the tools needed to integrate large amounts of intermittent generation. Such integration affects both balancing and day-ahead markets in the involved countries and analyses to study the effects of such integration are required. This paper describes an approach where the bidding prices for reserve capacity of generation units are determined on the basis of their opportunity costs in the day-ahead for the period considered for the reserve procurement. The approach is described both for a single balancing area, and for a system with several balancing areas, in which case also the availability of transmission capacity is important. The approach is illustrated with a small example.

Bidding in the Frequency Restoration Reserves (FRR) market for a Hydropower Unit

In this work we present an approach to determine the Frequency Restoration Reserves (FRR) bidding price for hydropower units. The piecewise linear approximation of discharge to power output relationship of a hydropower unit is used for the price estimation. The bidding prices for reserve capacity of generation units are determined on the basis of their estimated opportunity costs in the day-ahead market for the period reserves are procured. The approach is illustrated with a numerical example. The bidding prices for both upward and downward FRR from a hydro unit are related to the difference between the daily average spot price forecasts and the water value at the given day.

Introducing system flexibility to a multinational transmission expansion planning model

Grid investments are considered as sunk costs with a very long lifetime, particularly in an offshore grid context. The market mechanisms for cost recovery of these investments are exposed to an increasing share of variable power generation at the supply side, demanding more flexibility in the system. Hence, it is of great interest to account for these changes in tools being used for decision support. This paper presents an extension of an already existing mixed integer linear program (MILP) for transmission expansion planning (TEP), by including system flexibility in the form of energy storage and demand-side management. Moreover, an enhanced description of variable power generation is used to construct production profiles with a higher level of detail. The latter is achieved by simulating weather data for wind and solar incorporating higher temporal and spatial resolution than in previous studies. The impact of using new times series for variable power generation, and the introduction of system flexibility, are both presented separately using the North Sea area for a comparative case study with 2030 scenarios provided by ENTSO-E. The consequent results of interest include lifetime operational costs (OPEX), investment costs (CAPEX), and offshore wind power curtailment.

Impact of reserve market integration on the value of the North Sea offshore grid alternatives

Expected large scale integration of offshore wind power in the North Sea in future scenarios, 2020-2030, contribute to challenges on transmission planning and system operation in the Northern European electricity network. Moreover, the intermittency of the renewable resources makes the operational planning, forecasting, balancing, and control of the system more challenging. In this paper, a comparison is carried out between two reserve procurement market models. This is done by simulating non- and fully-integrated Northern European market using a 2030 scenario in combination with the effect of two different strategies for the development of the North Sea offshore grid: Radial grid and Meshed grid. The day-ahead market is modeled as a common market on an aggregate level for the whole European continent. Reserve procurement is done simultaneously with the clearing of the day-ahead market. For the analysis of day-ahead dispatch, a DC optimal power flow is used. The results show that about EUR 262 million and EUR 326 million per year could be saved as a result of the integration of the Northern European reserve market for the meshed and radial offshore grid topologies respectively.

Modeling the northern European electricity market

In this paper we present the methodology of a market model simulating the European day-ahead, intraday and real-time power markets. In a first step the day ahead market is modeled as a common European market including a simultaneous reserve procurement for northern Europe. Secondly, the intra-day market is simulated using the day ahead market results as an input. To reflect the current state of the system, the intraday market is restricted to the Central Western European (CWE) and the Nordic area. The scheduled day ahead dispatch is successively adjusted based on a continues revision of load and wind power forecasts. In a last step, the balancing market is modeled as a real time power dispatch on the basis of intraday market results and remaining deviations. Transfer capacities, start-up costs, technical constraints of thermal power plants in combination with a high resolution wind power model are used as a data basis for the model.