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For market-based procurement of low-voltage flexibility, DSOs identify the amount of flexibility needed for resolving probable distribution network (DN) voltage and thermal congestion. A framework is required to avoid over or under-procurement of flexibility in the presence of uncertainty. To this end, we propose a scenario-based robust chance-constrained (CC) day-ahead flexibility needs assessment (FNA) framework. The CC level is analogous to the risk DSO is willing to take in flexibility planning. Multi-period optimal power flow is performed to calculate the amount of flexibility needed to avoid network issues. Future uncertainties are considered as multiple scenarios, which are utilized to solve the flexibility needs assessment optimal power flow (FNA-OPF) problem. The FNA tool calculates the temporal and locational ramp-up and ramp-down flexibility needs of the DN. We also propose a Pareto optimal mechanism for selecting CC level to reduce flexibility needs while reducing DN congestion. Zonal clustering of a DN feeder is performed using electrical distance as a measure, with spatial partitioning and silhouette coefficient. Further, a zonal and nodal bid matching algorithm is proposed, where alternate flexibility bids in the same zone are identified in case nodal matching is not exact, compared to the calculated FNA. The proposed bid matching algorithm assists the system operator in bid selection by avoiding rerunning power flow evaluations. The zonal and nodal bid matching leads to more than 43% additional reduction of probable network incidents compared to naive nodal bid matching. Furthermore, we also calculate FNA for a real German DN with 646 nodes and 331 consumers.

HVDC networks play an ever-more-significant role in today's and future power systems due to the rapid adoption of intermittent energy sources. In order to maximize the utilization of transmission grids for power systems with high share of renewable energy sources (RES) there is a need for an adequate quantification tool that is capable of accurately representing the uncertain operational characteristics of RES along with reflecting the control capabilities of HVDC converter stations. In that manner, the development of such a tool as a non-sampling one-shot mathematical structure is invaluable from the operational decision making point-of-view. This paper presents a mathematical chance-constrained framework for solving stochastic optimal power flow problem for hybrid AC/DC grids, which includes HVDC controllability and the uncertainties brought about by load and renewable energy generation, by using an intrusive general polynomial chaos approach. Three case studies are conducted on 5-bus and 67-bus hybrid AC/DC test systems to highlight the efficacy of the proposed method with a focus on the added flexibility of HVDC converters and the effects of various chance-constraint levels as well as to validate the method against Monte-Carlo simulations.

In the ever complex world of the power systems, robust decision making in the context of investment planning becomes a difficult problem. In the decision making process, the costs and benefits of implementing complementary or competing technologies (AC versus DC or storage versus classical transmission expansion) need to be assessed. Additionally, the electrification of industrial demand and the integration of smart loads, such as heat pumps or electric vehicles, pave the way for demand flexibility provision on large scale. Considering that the majority of the demand flexibility is located in the distribution grid, there is a need for planning models and tools able to perform combined transmission and distribution grid planning. This paper introduces FlexPlan.jl, a Julia/JuMP-based opensource tool for holistic planning of transmission and distribution grids which includes a complete set of planning candidates for transmission and distribution networks and fully internalizes demand flexibility and storage usage. We use stochastic optimisation, in order to find robust decisions with respect to different climate conditions and operating hours within given climate years. To keep the optimisation problem tractable, we introduce a novel decomposition between the transmission and distribution grid planning problems. We demonstrate that using the proposed approach a speed improvement of up to 100 times can be achieved for cases with a large number of distribution grids, with negligible increase of the objective function value and a good solution quality in terms of power flow. Index Terms—Holistic planning, mixed-integer optimisation, transmission grid planning, distribution grid planning, demand flexibility, storage, hvdc.

Flexibility needs assessment (FNA) refers to the amount of flexibility DSO needs to plan or procure from the flexibility market to avoid probable DNI. The probable DNI are captured using modeling uncer- tainties using generated scenarios that emulate the different realizations which could happen. The scenario generation utilizes the nodal load and generation forecast along with historical forecast errors. Flexibility needs assessment optimal power flow (FNA-OPF) problem is solved for each of the scenarios. The robust FNA, considering the worst-case scenario, if used for flexibility procurement would lead to substantial over-procurement. In order to avoid this, a risk-based index, e.g. a chance constraint (CC), is introduced for procurement. Higher values of the chance constraint would project on to greater risk DSO might have to encounter by facing unresolved DNI. DNI in low voltage grids are often a local problem in which flexible resources in the proximity respond to avoid these incidents. To that end we cluster distribution grids onto connected zones, extend the local search for flexibility resources and propose a zonal bid selection framework that selects flexibility bids from neighborhoods to avoid DNI.

In the last years, we are assisting to a high-speed deployment of Renewable Energy Sources (RES) in electric Transmission and Distribution (T&D) grids as well as to an increased penetration of Distributed Energy Sources (DER) in distribution grids. This is making grid planning activities more and more complex and affected by a high level of uncertainty and calls for a deep revision of the consolidated grid planning methodologies applied by the System Operators. On this pathway, the FlexPlan project (https://flexplan-project.eu/) aims at establishing a new T&D grid planning methodology considering the opportunity to install new storage devices as well as to perform a flexible exercise of some loads located in selected grid nodes as an alternative to building new lines. Local compensation of RES generation spikes could allow to reduce the amount of congestion the grid is exposed to with a less expensive and less environment-impacting intervention. This paper first analyses which aspects of the present consolidated grid planning methodologies applied by System Operators are becoming critical and then describes the key aspects of the new FlexPlan grid planning methodology aimed to overcome those criticalities. Then, the paper provides details on the reference scenarios adopted by FlexPlan for the three grid years (2030, 2040 and 2050) and provides the first results for the simulations carried out by each of the 6 regional cases. Finally, the paper provides some conclusions that can be drawn from these studies on the role flexibility will play in Europe in the medium-long term and on the benefits that can be reaped by taking it into account in the transmission and distribution grid planning process.

The need for flexibility and curtailable resources is crucial for ensuring the healthy operation of future distribution networks (DN). In this work, we propose a network-state driven framework that distribution system operators (DSOs) can utilize for activating flexible and curtailable resources for alleviating network voltage and thermal issues, while accounting for network voltage and current imbalances. This approach assumes the availability of dynamic network state information and uses nodal sensitivities for calculating a flexibility activation signal (FAS). The signal design is motivated by volt-Var and volt-watt inverter control, and thus bounded. The FAS also considers network voltage and current imbalances and incentivizes activation of active and reactive power flexibilities for reducing imbalance in addition to mitigating voltage and thermal imbalances in a three-phase unbalanced distribution network. The FAS design resembles optimal power flow duals, often used as locational marginal prices. The gains associated with the imbalance component of the objective function of three-phase unbalanced resource activation (TPU-RA) is performed using Pareto optimality. A numerical case study is presented showing the efficacy of the proposed framework in avoiding network issues while reducing voltage unbalance factor by more than 80\%. Further, DN's flexibility needs are quantified for location and time of day.

DOI and ISBN not available ispartof: Proceedings of the Power Systems Computation Conference 2022 ispartof: 22nd Power Systems Computation Conference location:Porto, Portugal date:27 Jun - 1 Jul 2022 status: Published online

ispartof: pages:1-8 ispartof: Power Systems Computation Conference pages:1-8 ispartof: 22nd Power Systems Computation Conference (PSCC) location:Porto, Portugal date:27 Jun - 1 Jul 2022 status: published

Traditionally, the distribution system operator (DSO) relied on a fit-and-forget network design. However, there will be a greater need to integrate flexible and curtailable resources to cope with growing distributed generation (DG) installations and new consumer loads such as electric vehicles. Distribution network (DN) vulnerabilities, voltage and thermal limit violations, often require resource activation in the vicinity. Consumers located close to the end of the feeder in a radial DN witness more over-voltages (due to DG injection) and under-voltages (due to additional load). The per-unit change in active or reactive power of a consumer at the end of the feeder causes a greater marginal impact, referred to as nodal sensitivity. This will cause a higher activation of flexible resources close to the vulnerable nodes. A flat flexible activation priority will not be fair for such flexible owners. We propose a new mechanism to activate flexibility based on voltage sensitivity, which considers nodal sensitivities. The proposed activation design is motivated by inverter voltage control norms and has similarities with optimal power flow duals often utilized as locational marginal prices. These dual variables are active only when some network constraints are violated, and do not provide correction prior to such a violation. The proposed flexibility activation design, due to its drooping characteristics, actively contributes to avoiding such network issues from happening. The resource activation optimization formulation proposed is non-convex. Second-order cone relaxations are used to convexify the proposed resource activation optimization problem. We use numerical evaluations to show the proposed formulations can be used for activation of load flexibilities and can be used for valuing and planning flexible and curtailable resources.

This paper quantifies the operational cost of maintaining the frequency stability in a scenario when the largest loss of infeed originates from an offshore grid. The loss of infeed is considered only temporary, by taking advantage of fast dc grid protection. The power restoration curve is used to define the impact of protection on the stability and sensitivity analysis of its parameters is performed. A North Sea based grid topology shows a significant benefits of using a faster and more selective protection. Consequently, a FS protection strategy is recommended for the topology. The topological changes have a considerable impact on the cost and a meshed system that can restore the power to a higher level is highly cost effective.

n HVDC grid in the North-Sea is considered to have a high potential to aid the energy transition in Europe.n HVDC grid in the North-Sea is considered to have a high potential to aid the energy transition in Europe.A High investment cost and operational challenges are the major roadblocks in its realisation. This paper proposes a demonstration grid in the North-Sea and shows that it is a financially viable project. A sensitivity analysis corresponding to line capacities and base prices is performed. Recommendations for the construction and operation of such a grid are made from the regulatory stand point.

Low-voltage distribution networks are facing the increasing penetration of electric vehicles, which can cause congestion in the form of undervoltage and overcurrent events. A possible mitigation strategy is asking residential users to reduce their power consumption below a given threshold if congestion risk is forecasted. Although active power reduction of loads does not necessarily entail direct economic losses to the residential customer, unlike the case of PV generation, this type of congestion mitigation method needs to be adjusted to be acceptable for the public, as it might affect user comfort. This paper presents a mitigation method in which several residential users accept to reduce their power demand in exchange for economic benefits. The solution is based on a set of contractual agreements that can be stipulated between residential users and their system operators. The contractual terms limit the time and duration of power reduction, in order not to compromise the comfort of the users. The fairness of different sets of contractual criteria is explored. In particular, it is assessed how the selection of the contractual agreement affects customers, depending on their locations.

With the increased utilisation of high-voltage direct current (HVDC) links in power systems, it is necessary to upgrade the traditional ac grid focused transmission network expansion planning (TNEP) problem to accommodate multiple HVDC links and even HVDC grids. This study proposes a non-linear formulation for the TNEP problem of dc grids and derives two relaxations of the problem: the linear approximation, the second-order cone convex relaxation as a branch flow model. The presented formulations allow both monopolar and bipolar configurations, and this as point-to-point connections and HVDC grids as expansion candidates. The three formulations are examined on various test cases and compared for their accuracy and computational speed.

HVDC is becoming an increasingly important part of the present day transmission systems. Accurate models of active and reactive power control capabilities of HVDC converter stations are required to analyze the operation of power systems consisting of ac and dc grids, including ancillary services and security. Different converter station technologies exist, with varying control characteristics. This paper develops an optimal power flow model for ac and dc grids. A variety of formulations, from non-linear to convexified to linearized, are developed and implemented in an open-source tool. A convex relaxation formulation of a parameterized ac–dc converter model is developed. The hierarchy of common ac optimal power flow formulations is mapped to formulations for converter stations and dc grids. Numerical illustrations for a number of test cases, up to 3120 ac nodes and up to ten dc nodes and converters, are provided.

This work develops a hybrid optimization method for determining optimal radial transmission topologies for the connection of offshore wind farms combining Association Rule Mining (ARM) and a greedy algorithm. The method is capable of optimally placing offshore substations and accounts for Capital Expenditures (CAPEX), Corrective Maintenance (CM), losses and Expected Energy Not Transmitted (EENT). The stochastic nature of wind is also considered. First, an inequality based apriori algorithm is applied to a randomly generated population of Offshore Wind Power Plant (OWPP) pairs within a specified search domain. This way, a set of simple constraints is obtained reducing the effective combinatorial search space. A verified optimal greedy algorithm is then applied to efficiently search the reduced search space for the lowest cost radial topology to connect offshore wind. The hybrid approach is shown to introduce minimal error given a sufficient sample population while greatly extending the feasible problem size of the greedy search algorithm. ispartof: PSCC 2022 ispartof: PSCC 2022 location:Oporto Portugal date:27 Jun - 1 Jul 2022 status: accepted

This work develops a method of quantifying the effect of adding meshed connections to radial network topologies used for offshore extraction. The method accounts for Capital Expenditures (CAPEX), Corrective maintenance (CM), losses and Expected Energy Not Transmitted (EENT). The stochastic nature of wind is also accounted for. The method is applied to a statistically significant randomly generated population of Offshore Wind Power Plant (OWPP) pairs. Analysis of both Medium Voltage (MV) and High Voltage (HV) bus meshing is performed. It is demonstrated that in the two OWPPs case meshed connections have a narrow but significant region of applicability. Further, the method is applied to a system of 6 wind farms and compared to the lowest cost radial connection, using a number of different planning horizons. It is shown that the optimal radial topology is no longer the clear choice as the development horizon increases.

The FlexPlan Horizon2020 project aims at establishing a new grid-planning methodology which considers the opportunity to introduce new storage and flexibility resources in electricity transmission and distribution grids as an alternative to building new grid elements, in accordance with the intentions of the Clean Energy for all Europeans regulatory package of the European Commission. FlexPlan creates a new innovative grid-planning tool whose ambition is to go beyond the state of the art of planning methodologies by including the following innovative features: assessment of the best planning strategy by analysing in one shot a high number of candidate expansion options provided by a pre-processor tool, simultaneous mid- and long-term planning assessment over three grid years (2030, 2040, 2050), incorporation of a full range of cost–benefit analysis criteria into the target function, integrated transmission distribution planning, embedded environmental analysis (air quality, carbon footprint, landscape constraints), probabilistic contingency methodologies in replacement of the traditional N-1 criterion, application of numerical decomposition techniques to reduce calculation efforts and analysis of variability of yearly renewable energy sources (RES) and load time series through a Monte Carlo process. Six regional cases covering nearly the whole European continent are developed in order to cast a view on grid planning in Europe till 2050. FlexPlan will end up formulating guidelines for regulators and planning offices of system operators by indicating to what extent system flexibility can contribute to reducing overall system costs (operational + investment) yet maintaining current system security levels and which regulatory provisions could foster such process. This paper provides a complete description of the modelling features of the planning tool and pre-processor and provides the first results of their application in small-scale scenarios The research leading to these results/this publication received funding from the European Union’s Horizon 2020 research and innovation programme under grant agreement no. 863819

The limitations associated with the traditional N-1 reliability criterion and increasing system operation uncertainties are key drivers for switching to risk-based criteria for secure and optimal grid operation. The increased use of HVdc technology in existing power system motivates the need for inclusion of converter control into the decision-making for reliable operation. In line with these objectives, this paper introduces a non-linear preventive-corrective security constrained optimal power flow formulation for a hybrid ac/dc system. The model is used to investigate the impact of contingency probability, corrective costs and converter corrective control on the resulting risk and tradeoff between preventive and corrective actions. The analysis finds that while lower contingency probability requires only corrective actions, higher probability leads to preventive actions in addition to corrective control. The exclusion of converter corrective control leads to higher operational risk and preventive costs as compared to the case allowing the converter actions in corrective stage, thus highlighting the additional flexibility offered by converters in reliability management. ispartof: pages:1-6 ispartof: 2021 IEEE Madrid PowerTech pages:1-6 ispartof: IEEE PowerTech 2021 location:Madrid date:28 Jun - 2 Jul 2021 status: Published online

The electrification of transport and heating systems brings new challenges for the low voltage distribution networks, which in the future might be more prone to congestion. This calls for methods to perform optimization and control actions, to ensure their correct operation. Their large extension and non-negligible degree of voltage unbalance make low voltage systems difficult to analyze. This paper features a comparison of three unbalanced formulations for power flow and OPF analyses: the full nonlinear, non-convex AC formulation, a second-order cone relaxation and a linear approximation. Accuracies and computational efforts are evaluated for different problem types, to assess whether the conic and linear formulation are suitable to perform low voltage systems calculations.

This paper describes the main features of the new European research project FlexPlan. This project aims at establishing a new grid planning methodology considering the opportunity to introduce new storage and flexibility resources in electricity transmission and distribution grids as an alternative to building new grid elements. FlexPlan will create a new innovative grid planning tool whose ambition is to go beyond the state of the art of planning methodologies, by including the following innovative features: integrated transmission distribution planning, inclusion of environmental analysis, probabilistic contingency methodologies replacing the N-1 criterion as well as optimal planning decision over several decades. Then, the new tool will be used to analyse six regional cases covering nearly the whole European continent, aimed at demonstrating the application of the tool on real scenarios as well as at casting a view on grid planning in Europe till 2050. In this way, the FlexPlan project will try to answer the question of which role flexibility could play and how its usage can contribute to reduce planning investments yet maintaining current system security levels. The project will end up formulating guidelines for regulators and planning offices of system operators.

HVDC technology has gone through major developments in the past decades, resulting in higher power ratings, increased efficiency, and the availability of effective means for HVDC grid protection. These developments have made overlay HVDC grids a viable option to accommodate the shift towards a carbon-free power system by enabling optimal use of renewable resources. In particular, overlay HVDC grids greatly increase the prospects of building (trans-)continental supergrids to facilitate global economic development. Notwithstanding the significant progress made over the last decades, overlay HVDC grids still encounter challenges due to the distance and amount of power involved. This paper focuses on analyzing the readiness of the current technologies and the challenges associated with overlay HVDC grids. An in-depth analysis is carried out to evaluate the applicability of current technologies for overlay HVDC grids. Based on the review of recent R&D efforts, the gaps and challenges towards the realization of a global HVDC grid are summarized. ispartof: CSEE Journal of Power and Energy Systems vol:7 issue:4 status: Published online

Within this work, a techno-economic optimization of large offshore wind regions, consisting of multiple concessions is developed and investigated. Currently, the practice within the European offshore wind industry is for countries to designate an offshore wind power zone within their exclusive economic area (EEA). This zone is then further divided into individual concessions which are auctioned off to developers. Developers then optimize each individual concession independently. As such, research on electrical system optimization has been heavily focused at the scale of the individual concession, ignoring the possible gains that come from current or future developments in neighboring concessions within the same region [1]. It is believed that there is a significant opportunity for both cost savings and increased system reliability by optimizing an entire offshore wind zone prior to the development of each individual concession [2]. This work attempts to investigate these opportunities. The techno-economic optimization is formulated as a mixed integer linear program (MILP). Typical voltage levels for HVAC and HVDC transmission are included as well as mid-point reactive power compensated HVAC transmission. Mid-point compensation has been shown to extend the economic range of HVAC systems [3]. The optimization finds a global minimum for the lifetime cost of energy. To guarantee the feasibility of the results, a full “AC” analysis of the proposed technical design is performed. The lifetime costs accounted for are capital expenditures (CAPEX) related to material and labor during the construction phase, operating expenditures (OPEX) related to plant maintenance and operation, and the Expected Energy Not Served (EENS). The use of site-specific wind profiles and turbine specific power curves make for geographically and technologically relevant solutions. To quantify the possible benefits of optimizing an entire region, a case study within the Belgian North-sea is investigated. The offshore wind zone within the Belgian EEA consists of 10 concessions all at varying degrees of development. The zone spans an area of 175 km2 and will have a total capacity, once fully developed, exceeding 2.2GW [4]. The optimal solution is compared to the existing solution in order to extract the areas in which improvement can be made using the proposed optimization method.