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With the global consensus to achieve carbon neutral goals, power systems are experiencing a rapid increase in renewable energy sources and energy storage systems (ESS). Especially, recent development of hub substations (HS/S) equipped with ESS, applicable for resolving site constraints if implemented as mobile transformers, is expanding the development of ESS-equipped facilities. However, these units require centralized control strategies considering variability within integrated networks. While studies on electric vehicle charging considering the variability of renewable energy or load are widely studied, ESS management scheme for individual substations requires further optimization, especially considering the state of distributed sources at lower levels and transmission system operators. Thus, in this study, an optimal control approach for ESS located at the connection point of transmission and distribution systems, including further consideration of the loss in distribution lines and the constraints of renewable energy sources is presented. This study attempts to derive proactive control strategies for ESS in HS/S to operate with various distribution networks. By establishing control priorities for each source through optimal operation strategy, a suitable capacity of ESS and its economic benefits for distribution network management can be examined. Validation of the current analysis results is performed by utilizing MATPOWER. By adapting the operational range of design scenarios, diverse distribution systems can be tested against multiple configurations of connected devices. [ABSTRACT FROM AUTHOR]

Abstract With the global consensus to achieve carbon neutral goals, power systems are experiencing a rapid increase in renewable energy sources and energy storage systems (ESS). Especially, recent development of hub substations (HS/S) equipped with ESS, applicable for resolving site constraints if implemented as mobile transformers, is expanding the development of ESS-equipped facilities. However, these units require centralized control strategies considering variability within integrated networks. While studies on electric vehicle charging considering the variability of renewable energy or load are widely studied, ESS management scheme for individual substations requires further optimization, especially considering the state of distributed sources at lower levels and transmission system operators. Thus, in this study, an optimal control approach for ESS located at the connection point of transmission and distribution systems, including further consideration of the loss in distribution lines and the constraints of renewable energy sources is presented. This study attempts to derive proactive control strategies for ESS in HS/S to operate with various distribution networks. By establishing control priorities for each source through optimal operation strategy, a suitable capacity of ESS and its economic benefits for distribution network management can be examined. Validation of the current analysis results is performed by utilizing MATPOWER. By adapting the operational range of design scenarios, diverse distribution systems can be tested against multiple configurations of connected devices.

In the context of increasing distributed flexibility, enhanced TSO-DSO coordination is needed when procuring and activating flexibility. The literature shows that pricing the changes in the power flow over the TSO-DSO interfacing substation leads to optimal flexibility procurement cost in sequential TSO-DSO flexibility markets. This paper proposes a bilevel model, considering a TSO leader which sets interface flow prices freely, and DSO-followers in a Stackelberg game. This game-theoretical approach allows for the identification of regulatory risks and the testing of regulatory mechanisms. Based on two case studies, results show that, if left unregulated, the strategic TSO creates significant cost allocation distortions, creating unwanted financial transfers from DSOs to the TSO. However, when acting strategically, the TSO also activates (or leads to the activation of) economical flexibility providers, having as a reference the first-best option, namely the Common Coordination Scheme (CS). Leveraging on these results, a cap and floor mechanism is proposed, limiting unwanted cost allocation distortions and retaining incentives for efficient flexibility activations. Results showcase that a Fragmented CS with regulated interface flow prices could be an efficient second-best compared to the Common CS, outperforming other regulatory options found in the literature.

The integration of Distributed Energy Resources (DER) like renewable generation into the power system has increased the need to develop effective strategies for procurement of flexibility services from these distribution network connected resources. In order to realize the flexibility potential of DERs to support flexibility needs of the system operators, the aggregated available flexibility at the interconnection point between transmission and distribution system needs to be estimated. This paper presents a novel optimization-based method to estimate the time-dependent flexibility at a primary distribution substation while accounting for the uncertainty of renewable generation. The proposed approach integrates the stochasticity of the flexibility resources using a scenario-based robust optimization and incorporates the intertemporal constraints of DER into the estimation process, ensuring a realistic representation of the flexibility capability over time. The scenarios are derived through sampling from a probability distribution of the renewable energy forecasts. This process utilizes a joint probability distribution and copulas to account for the temporal and spatial correlation among the renewable energy sources of the same region. Based on the joint hourly probability of the different scenarios a robust solution is finally obtained according to the assumed confidence level.

This paper analyses the Norwegian Power System through a sequence of models that represents dynamics of the wholesale power market, distribution power network, end-users, and a coordination scheme between Transmission System Operators (TSOs) and Distribution System Operators (DSOs). The models assess the impact of end-user flexibility and TSO-DSO coordination on the power system’s operation, with an emphasis on two research questions: the extent to which flexibility from end-users affects the power system’s operation under the TSO-DSO coordination scheme, and the potential of the TSO-DSO coordination scheme in incentivizing end-users’ flexibility. The paper presents three scenarios, involving varying degrees of coordination and end-user participation that are modeled and applied to the entire Norwegian power system. The results indicate that active end-user participation in the power market with a TSO-DSO coordination scheme could enhance the flexibility of the power system and support redispatch, while attaining a 14.5% redispatch cost reduction and 0.33% total system cost reduction. These findings offer insights for power system stakeholders concerning the potential advantages and challenges associated with fostering end-user flexibility and further developing TSO-DSO coordination schemes.

Abstract The intermittencies of renewable generations give rise to situations, which require both slow‐ and fast‐ramping flexibility capability from a variety of resources connected at the medium voltage (MV) andlow voltage (LV) distribution grids. Moreover, this may increase the grid reinforcement costs. To defer this reinforcement, the grid needs to be operated optimally. This paper proposes—(a) such an optimal operational methodology forthe MV and LV grids; and (b) an aggregated flexibility estimation methodology separately for fast and slow services at the primary substation (transmission interface). The methodologies based on model‐based MV grids and sensitivity coefficients‐based LV grids are suitable for LV grids where an up‐to‐date, accurate model and topology are not always available. Besides, the costs and resources associated to create full LV grid model and visibility should be prevented. The approaches, here, use the synchronised and accurate measurements from grid monitoring devices located at the LV distribution grids. They have been validated on a real MV and LV networks of a Swiss distribution grid operator equipped with such devices. The results, in terms of reducing technical losses, reducing grid violation costs,and estimating flexibility capability show the efficacy of the proposed methodologies and therefore, can be easily deployed.

This paper introduces a theoretical market framework (TMF) for conceptualizing and designing electricity markets, integrating transmission system operator and distribution system operator (TSO–DSO) coordination mechanisms. The TMF represents a comprehensive tool that formalizes new, innovative market concepts and their impact on existing markets, and outlines fundamental categories and decisions essential to market design. This paper, through the TMF, addresses the integration challenges posed by new mechanisms for system services. Utilizing the TMF, the study maps 13 European demonstrators' TSO–DSO coordination solutions, identifying real-world challenges in designing and implementing novel system services markets. Drawing on these real-world insights, the paper offers market design and policy recommendations to address and overcome the specific challenges in market-based TSO–DSO coordination. [ABSTRACT FROM AUTHOR]

The intermittencies of renewable generations give rise to situations, which require both slow‐ and fast‐ramping flexibility capability from a variety of resources connected at the medium voltage (MV) andlow voltage (LV) distribution grids. Moreover, this may increase the grid reinforcement costs. To defer this reinforcement, the grid needs to be operated optimally. This paper proposes—(a) such an optimal operational methodology forthe MV and LV grids; and (b) an aggregated flexibility estimation methodology separately for fast and slow services at the primary substation (transmission interface). The methodologies based on model‐based MV grids and sensitivity coefficients‐based LV grids are suitable for LV grids where an up‐to‐date, accurate model and topology are not always available. Besides, the costs and resources associated to create full LV grid model and visibility should be prevented. The approaches, here, use the synchronised and accurate measurements from grid monitoring devices located at the LV distribution grids. They have been validated on a real MV and LV networks of a Swiss distribution grid operator equipped with such devices. The results, in terms of reducing technical losses, reducing grid violation costs,and estimating flexibility capability show the efficacy of the proposed methodologies and therefore, can be easily deployed. [ABSTRACT FROM AUTHOR]

The exploitation of flexibility services provided by distributed energy resources (DERs) located in the distribution grid becomes increasingly important for the secure and reliable operation of power systems. These resources are typically small-scale and located close to end-users, however their aggregated flexibility can offset the imbalance caused by the stochastic variations of the Renewable Energy Sources (RES). This paper proposes a methodology to estimate with increased accuracy the available flexibility of DERs in an Active Distribution Grid (ADG) at the point of interconnection with the transmission system. An optimization-based approach is used to estimate the available maximum active and reactive power flexibility for specific search directions formed by constant active to reactive power ratios. In order to keep calculations manageable and estimate the available flexibility with high accuracy, the search directions are sampled from a distribution that is iteratively updated at each step. Three variations are proposed for the angle sampling, both in the angle domain and in the p-q domain. Each variation is tested on a modified 18-bus radial distribution system and its effectiveness and convergence is compared.

Future power systems with a high share of intermittent renewable energy sources (RES) in the energy portfolio will have an increasing need for active power balancing. The integration of controllable and more flexible distributed energy resources (DERs) at the distribution-grid level represents a new solution and a sustainable alternative to conventional generation units for providing balancing services to the transmission system operator (TSO). Considering that the extensive participation of DERs in ancillary services may lead to the violation of limits in the distribution network, the distribution system operator (DSO) needs to have a more active role in this process. In this paper, a framework is presented that allows the DSO, as the central coordinator of the aggregators, to participate in the balancing market (BM) as a balancing service provider (BSP). The developed mathematical model is based on the mixed-integer second-order cone programming (MISOCP) approach and allows for determination of the limits of active power flexibility at the point of the TSO–DSO connection, formation of the dependence of the price/quantity curve, and achievement of the optimal dispatch of each DER after clearing the balancing market. The simulation results are presented and verified on modified IEEE distribution networks. [ABSTRACT FROM AUTHOR]

Abstract In this study, a novel coordinated market scheme is proposed, enabling the participation of distributed energy resources (DERs) in the wholesale as well as local energy market (LEM). First, a day‐ahead energy market framework is proposed that is operated by a distribution system operator (DSO) in coordination with the transmission system operator (TSO). The DERs present in a distribution system have the freedom to select among the local or wholesale electricity markets (WEM) to offer their energy. The DSO aggregates all DERs' services and power demand to represent them in a WEM operated at the transmission level. The proposed model allows the DSO to select more economical ways of allocating the resources utilising the TSO‐DSO coordination strategy. The objective is to maximise social welfare in light of network constraints. Furthermore, a practical method is developed for DSOs to redistribute any monetary surplus among different DERs participating in the WEM. Numerical simulations indicate the proposed model's economic effectiveness compared to the scenario where DERs are allocated only at the local market level.

Distribution Level Flexibility Markets (DLFMs) constitute a timely development towards facilitating bottom-up RES and flexibility investments as well as instantiating a fair and regulated interaction framework among energy sector stakeholders, namely System Operators (DSO, TSO), aggregators, Flexibility Service Providers (FSPs), the recently introduced actor called Flexibility Market Operator (FMO) that operates the DLFM and the end energy prosumers. Moreover, the interaction of DLFMs with existing Transmission Level markets and with distributed energy resources is of special interest. In this paper, we present and analyze three possible ways to integrate DLFMs in today's regulatory framework, each corresponding to a different market architecture, and we evaluate their implications. A comparative analysis reveals the strengths and drawbacks of each one of them both from a system's as well as from each individual stakeholder's perspective. The effects of different distributed RES and flexibility penetration levels are also analyzed through a sensitivity analysis. The comparison of the proposed DLFM architectures, both with each other and the current electricity market paradigm, testifies the necessity and the importance of DLFMs and quantifies the impact that they have in: (i) reducing distribution grid management costs, (ii) guaranteeing distribution service quality, and (iii) increasing the penetration of bottom up RES/flexibility investments. • Coordination schemes between TSO and DSO are needed for high RES penetration. • Interactive, reactive and proactive flexibility market schemes are proposed. • Flexibility markets can accommodate the desired high RES penetration rates. • Flexibility markets can have a key role in minimizing overall cost. [ABSTRACT FROM AUTHOR]

In the context of increasing distributed flexibility, enhanced TSO-DSO coordination is needed when procuring and activating flexibility. The literature shows that pricing the changes in the power flow over the TSO-DSO interfacing substation leads to optimal flexibility procurement cost in sequential TSO-DSO flexibility markets. This paper proposes a bilevel model, considering a TSO leader which sets interface flow prices freely, and DSO-followers in a Stackelberg game. This game-theoretical approach allows for the identification of regulatory risks and the testing of regulatory mechanisms. Based on two case studies, results show that, if left unregulated, the strategic TSO creates significant cost allocation distortions, creating unwanted financial transfers from DSOs to the TSO. However, when acting strategically, the TSO also activates (or leads to the activation of) economical flexibility providers, having as a reference the first-best option, namely the Common Coordination Scheme (CS). Leveraging on these results, a cap and floor mechanism is proposed, limiting unwanted cost allocation distortions and retaining incentives for efficient flexibility activations. Results showcase that a Fragmented CS with regulated interface flow prices could be an efficient second-best compared to the Common CS, outperforming other regulatory options found in the literature. [Display omitted] • Bilevel optimisation model to study interface flow pricing. • Evaluation with two case studies, including a 102-node case study. • A strategic TSO leads to efficient activations, but also cost allocation distortions. • Identification of regulatory risks on TSO-DSO coordination scenarios. • Proposal of a cap and floor mechanism and comparison with other regulatory options. [ABSTRACT FROM AUTHOR]

Recently, there has been lot of research on finding the feasible operating region (FOR) of the active distribution network (ADN) to provide ancillary services to the transmission grid. The current focus of research is on finding methods that can accurately determine the shape of the FOR and have fast computation time. However, there is little focus on analyzing how network constraints impact the shape of the FOR. This paper attempts to address this issue and provides a mathematical derivation of how network constraints, such as cable loading and voltage limits, would influence FOR. The approach is based on a linear distflow mathematical analysis. The relations derived in the analysis are verified with numerical simulation on radial low-voltage (LV) and medium-voltage (MV) networks. The results show that cable loading constraints cut the FOR in a circular way and voltage constraints cut the FOR with a straight line of slope − ϵ , which is the ratio R n / X n of the path from root node to the node under analysis of the radial distribution network. • An analytical approach to analyze impact of network constraints on FOR is proposed. • Cable loading constraints represent sets of circles with line capacities as radius. • Voltage constraints cut FOR with straight line of slope equal to minus R/X ratio. • The approach is validated by case studies on LV and MV network with flexible loads. • Proposed method represent network constraints and results in faster FOR computation. [ABSTRACT FROM AUTHOR]

This paper proposes the new problem of calculating the worst-voltage-case (WVC) under power flows uncertainty, particularly at interfaces between transmission and distribution grid operators. The goal of the calculation is to verify if the realization of the worst uncertainty scenario leads to abnormal voltages, or assure where the voltage instability is not a risk, and inform the transmission system operator. The problem is formulated as a tailored non-convex, nonlinear optimal power flow (OPF) with complementarity or equilibrium constraints (ECs). The latter model the generator switch between under voltage control and under reactive power limit. The problem is converted into a mathematically equivalent nonlinear programming OPF problem in which ECs are handled as penalty terms in the objective function. The paper has conducted a series of experiments on the 60-bus Nordic system, which have pointed out the challenges associated to such computations to obtain meaningful results and unveiled new insights. The findings and scalability are confirmed using a real-world 1203-bus system. • This paper proposes the new problem of calculating the worst voltage under flows uncertainty at TSO-DSO interfaces. • The goal of the calculation is to verify if the worst uncertainty scenario creates voltage instability. • The problem is formulated as a tailored AC optimal power flow with complementarity constraints. • The problem is converted into a scalable equivalent OPF problem in which complementarity constraints are handled as penalty terms. • The paper pointed out the challenges to this computation to obtain meaningful results and unveiled new insights. [ABSTRACT FROM AUTHOR]

This paper introduces a theoretical market framework (TMF) for conceptualizing and designing electricity markets, integrating transmission system operator and distribution system operator (TSO–DSO) coordination mechanisms. The TMF represents a comprehensive tool that formalizes new, innovative market concepts and their impact on existing markets, and outlines fundamental categories and decisions essential to market design. This paper, through the TMF, addresses the integration challenges posed by new mechanisms for system services. Utilizing the TMF, the study maps 13 European demonstrators’ TSO–DSO coordination solutions, identifying real-world challenges in designing and implementing novel system services markets. Drawing on these real-world insights, the paper offers market design and policy recommendations to address and overcome the specific challenges in market-based TSO–DSO coordination.

In this paper, a transmission-distribution systems flexibility market is introduced, in which system operators (SOs) jointly procure flexibility from different systems to meet their needs (balancing and congestion management) using a common market. This common market is, then, formulated as a cooperative game aiming at identifying a stable and efficient split of costs of the jointly procured flexibility among the participating SOs to incentivize their cooperation. The non-emptiness of the core of this game is then mathematically proven, implying the stability of the game and the naturally-arising incentive for cooperation among the SOs. Several cost allocation mechanisms are then introduced, while characterizing their mathematical properties. A case study is then presented, considering an interconnected system composed of the IEEE 14-bus transmission system and the Matpower 18-bus, 69-bus, and 141-bus distributions systems. The numerical results showcase the cooperation-induced reduction in system-wide flexibility procurement costs, and identify the varying costs borne by the different SOs under different cost allocations methods. [ABSTRACT FROM AUTHOR]

Electric vehicles (EVs) are becoming a promising source of grid ancillary services due to the temporal and spatial charging flexibility, quick response and storage capability. Such advantages are increasing with government policy promotion and technology improvement. However, the exploration of EV flexibility requires the coordination of both transmission system operators (TSOs) and distribution system operators (DSOs), to ensure the safe and reliable operation of power network. In this paper, we propose a coordinated evaluation method that determines the optimal utilization of EV temporal flexibility without compromising EV owners’ usage. At the distribution level, DSOs first evaluate EV aggregators’ operational boundaries to exploit distribution level services. At the transmission level, TSOs then determine EV charging schedules and ancillary service capacity simultaneously, taking into account the requirement from DSOs. We validate the model in a case study using the IEEE 123 node test feeder and EV charging sessions obtained from a transportation simulation tool that uses real-world data. [ABSTRACT FROM AUTHOR]

The Feasible Operating Region (FOR) is defined as a set of points in the PQ plane that includes all the feasible active and reactive power flows at the Transmission System Operator (TSO)–Distribution System Operator (DSO) interconnection. Recent trends in power systems worldwide increase the need of cooperation between the TSO and the DSO for flexibility provision. In the current landscape, the efficient and accurate estimation of the FOR could unlock the potential of the DSO to provide flexibility to the TSO. To that end, much existing research has tackled the problem of FOR estimation, which is a challenging problem. However, no research that adequately organizes the literature exists. This work aims to fill this gap. Three categories of FOR estimation methods were identified: Geometric, Random Sampling, and Optimization-Based methods. The basic principles behind each method are analyzed and the most significant works involving each method are presented. For the reviewed works, we focus on the types of flexibility providing units included in the FOR estimation, the examination of time dependence, and the monetization of the FOR. Finally, the strengths and weaknesses of each category of methods are compared, providing a holistic review of the available FOR estimation methods. [ABSTRACT FROM AUTHOR]

The large-scale integration of renewable generation and the gradual decommissioning of conventional power plants has led to decreased availability of resources for providing services and support to the bulk transmission grid. This paper presents a novel methodology for providing support to the bulk transmission system through the control of thousands of small distributed energy resources (DERs), located in distribution systems. This control scheme is expected to serve jointly with other classical countermeasures against instability conditions. The proposed method is model-free, scalable, and does not rely on extensive communication infrastructure. It integrates an online method (New LIVES) to monitor the voltage stability status of the transmission system, a rule-based decentralized decision algorithm, and the local DER mechanisms implementing the control actions. The proposed approach is implemented on a combined transmission and distribution test system with over 4200 low-voltage buses and the dynamic simulation results illustrate its flexibility, practicality, and tractability. [ABSTRACT FROM AUTHOR]

• Adaptive energy and flexibility market is designed for wholesale and local markets. • The market can adapt to changing conditions of TSO and DSOs. • The market operator prioritizes demands and receive energy and flexibility from TSO and DSO. The aim of this paper is to present the design of an energy and flexibility market that operates in coordination with both wholesale and local markets. By utilizing greater flexibility through the integration with transmission and distribution networks, the market can adapt to changing operational conditions over time. The market operator uses information from the TSO-DSO to implement the necessary submarket type based on network conditions.The market operator, in turn, will select the proper sub-market based on technical and economic specifications, from the operators, i.e., the required energy, flexibility, and associated costs. The proposed method offers a decentralized and non-iterative coordinated market for energy and flexibility at both the transmission and distribution levels, guided by the principle that, electricity flows naturally from low-cost to high-cost nodes in an uncongested network. The market operator directs energy and flexibility to higher cost buses using an appropriate market mechanism. Consequently, the existing network is oriented towards being congestion-free. Simulation results demonstrate that the proposed market not only aligns with TSO-DSO operational priorities but also approaches the outcomes of a centralized market in terms of optimality. Also, the proposed method requires less calculation time for than previously coordinated market execution methods, such as TSO-leader and DSO-leader. [Display omitted] [ABSTRACT FROM AUTHOR]

Grid integration of distributed energy resources (DERs) is vital to provide flexibility services, required to ensure efficient system operations at both transmission and distribution levels. To prevent negative interactions between transmission system operators (TSO) and distribution system operators (DSOs) while procuring flexibility services from DERs, it is imperative to prioritize them. However, for system's cost-effectiveness allocating DER flexibility to the operator with the highest need is preferable rather than giving upfront priority. To address this, a novel coordinated decision-making approach for a common TSO-DSO market is proposed. This approach considers global balancing for the TSO and distribution congestion management for the DSO as objectives, using them as deciding factor to allocate DER flexibility to the system operator with the greatest need to fulfil its objective. Results show proposed method enhances DSO's flexibility transfer to TSO and maintains reactive power at T-D interface. Gap between TSO's DER flexibility needs and availability, influenced by congestion and line losses, is critical for prioritization. Specifically, network capacity and line losses constitute 18.79 % and 3.42 % of offered DER flexibility, respectively. Reactive power deployment improves Q/P ratio, reducing standard deviation from 0.19 to 0.018. Framework reduces conflicts, provides clear flexibility allocation rules without upfront priority. • Novel decentralized variant of common TSO DSO market is proposed. • Avoids upfront priority to TSOs or DSOs, focuses on highest system need. • Aims for global balancing for TSOs and distribution congestion management for DSOs. • Enhances DSO-to-TSO flexibility transfer while maintaining reactive power. • Reduces conflicts and sets clear rules for acquiring DER flexibility effectively. [ABSTRACT FROM AUTHOR]

Future power systems with a high share of intermittent renewable energy sources (RES) in the energy portfolio will have an increasing need for active power balancing. The integration of controllable and more flexible distributed energy resources (DERs) at the distribution-grid level represents a new solution and a sustainable alternative to conventional generation units for providing balancing services to the transmission system operator (TSO). Considering that the extensive participation of DERs in ancillary services may lead to the violation of limits in the distribution network, the distribution system operator (DSO) needs to have a more active role in this process. In this paper, a framework is presented that allows the DSO, as the central coordinator of the aggregators, to participate in the balancing market (BM) as a balancing service provider (BSP). The developed mathematical model is based on the mixed-integer second-order cone programming (MISOCP) approach and allows for determination of the limits of active power flexibility at the point of the TSO–DSO connection, formation of the dependence of the price/quantity curve, and achievement of the optimal dispatch of each DER after clearing the balancing market. The simulation results are presented and verified on modified IEEE distribution networks.

The proliferation of distributed energy resources (DERs), located at the Distribution System Operator (DSO) level, bring new opportunities as well as new challenges to the operations within the grid, specifically, when it comes to the interaction with the Transmission System Operator (TSO). To enable interoperability, while ensuring higher flexibility and cost-efficiency, DSOs and the TSO need to be efficiently coordinated. Difficulties behind creating such TSO-DSO coordination include the combinatorial nature of the operational planning problem involved at the transmission level as well as the nonlinearity of AC power flow within both systems. These considerations significantly increase the complexity even under the deterministic setting. In this paper, a deterministic TSO-DSO operational planning coordination problem is considered and a novel decomposition and coordination approach is developed. Within the new method, the problem is decomposed into TSO and DSO subproblems, which are efficiently coordinated by updating Lagrangian multipliers. The nonlinearities at the TSO level caused by AC power flow constraints are resolved through a dynamic linearization while guaranteeing feasibility through “ $l_1-$ proximal” terms. Numerical results based on the coordination of the 118-bus TSO system with up to 32 DSO 34-bus systems indicate that the method efficiently overcomes the computational difficulties of the problem. [ABSTRACT FROM AUTHOR]

The growing penetration of renewable energy sources (RES) in the electrical power sector has increased the amount of distributed generation (DG) units connected at the distribution system level. In this context, new balancing challenges have arisen, creating the need for a novel use case methodology to enable an active role at the distribution system level such that transmission system operators (TSOs) can coordinate with distribution system operators (DSOs) with regard to connected resources for balancing purposes. In this study, the exploitation of the DSO-connected resources for balancing purposes in a market environment is proposed and evaluated via a novel business use case (BUC) methodology based on the categorization of IEC 62913-1. More specifically, in order to address different balancing market situations, two scenarios are considered with regard to the BUC. The first one represents the data exchange between the TSO, the DSO, and the balancing service provider (BSP). The second one represents an alternative scenario where data are exchanged directly between the TSO and the DSO, where the DSO also takes on the role of the BSP. The proposed BUC was also developed in order to validate the required data modeling and exchange mechanisms between DSOs and TSOs in order to exploit DSO-connected resources for overall system balancing purposes across different time scales.

This paper analyses the Norwegian Power System through a sequence of models that represents dynamics of the wholesale power market, distribution power network, end-users, and a coordination scheme between Transmission System Operators (TSOs) and Distribution System Operators (DSOs). The models assess the impact of end-user flexibility and TSO-DSO coordination on the power system's operation, with an emphasis on two research questions: the extent to which flexibility from end-users affects the power system's operation under the TSO-DSO coordination scheme, and the potential of the TSO-DSO coordination scheme in incentivizing end-users' flexibility. The paper presents three scenarios, involving varying degrees of coordination and end-user participation that are modeled and applied to the entire Norwegian power system. The results indicate that active end-user participation in the power market with a TSO-DSO coordination scheme could enhance the flexibility of the power system and support redispatch, while attaining a 14.5% redispatch cost reduction and 0.33% total system cost reduction. These findings offer insights for power system stakeholders concerning the potential advantages and challenges associated with fostering end-user flexibility and further developing TSO-DSO coordination schemes. • TSO-DSO coordination applied countrywide (Norway) with high spatial resolution • Modelling the TSO-DSO coordinated power market to study the role of active end-users • Reductions in grid redispatch costs due to active end-user participation • Active end-users influence electricity prices by participating in the TSO-DSO scheme. • Active end-users also slightly smooth out the electricity supply and demand. [ABSTRACT FROM AUTHOR]

The Feasible Operating Region (FOR) is defined as a set of points in the PQ plane that includes all the feasible active and reactive power flows at the Transmission System Operator (TSO)–Distribution System Operator (DSO) interconnection. Recent trends in power systems worldwide increase the need of cooperation between the TSO and the DSO for flexibility provision. In the current landscape, the efficient and accurate estimation of the FOR could unlock the potential of the DSO to provide flexibility to the TSO. To that end, much existing research has tackled the problem of FOR estimation, which is a challenging problem. However, no research that adequately organizes the literature exists. This work aims to fill this gap. Three categories of FOR estimation methods were identified: Geometric, Random Sampling, and Optimization-Based methods. The basic principles behind each method are analyzed and the most significant works involving each method are presented. For the reviewed works, we focus on the types of flexibility providing units included in the FOR estimation, the examination of time dependence, and the monetization of the FOR. Finally, the strengths and weaknesses of each category of methods are compared, providing a holistic review of the available FOR estimation methods.

Summary: Modern power system requires optimally coordinated operation between transmission and distribution systems due to large‐scale integration of distributed energy resources (DERs). Commonly, transmission system operator (TSO) solves its own cost optimization problem and evaluates required targets for each distribution system operator (DSO). Thus, TSO problem becomes more complex and highly scaled with increase in number of connected distribution systems, which requires more computational time and resources. Therefore, this paper proposed a method to reduce computational burden on TSO and solve coordinated security constrained unit commitment (C‐SCUC) problem by involving a coordinator in upper level hierarchy. Coordinator is required to solve system‐wide problem to adjust targets for transmission system (TS) and all distribution systems (DS). Besides, TSO and DSO only need to solve their own cost optimization problems. In this paper, we have proposed analytical target cascading (ATC) along with hybridized particle swarm optimization with differential evolution (PSO‐DE) for solving increased complexity of the coordinated problem. ATC provides coordination between transmission and distribution sections of power system while hybrid PSO‐DE provides better accuracy of optimization in ATC layers. For evaluation of efficacy of proposed method, this paper has taken IEEE 118‐bus system as TS and IEEE 33‐bus system as DS. Results has depicted that proposed method could help TSO in reducing computational resources and improving computational time. [ABSTRACT FROM AUTHOR]

The article presents the findings on market-based congestion management (CM) in power systems. The main idea is to unlock flexibility from both small and large-scale resources by creating a platform so that flexibility can enter the markets through the platform and be used by system operators (DSOs and TSOs) for CM. The article recognizes two pressing issues in market-based CM: low liquidity and adverse impacts of flexibility activation. The article proposes leveraging market integration and TSO-DSO coordination to address the pressing problems and incorporate them into the platform. Bids from the intraday market at Nord Pool as well as the balancing market bids, were used for CM to show the possibility of addressing the low liquidity issue by receiving bids from well-established markets. In TSO-DSO coordination, an algorithm-agnostic process is proposed and implemented to involve SOs' network limitations before flexibility is traded to mitigate the adverse impacts of flexibility activation. As the market integration and TSO-DSO coordination functionalities rely on flexibility-related data that are often in huge quantities, a metadata register is also implemented to gather, process, and store data to be smoothly accessed by different stakeholders depending on their needs and access rights. • Market integration is one way of increasing system operators' access to flexibility • TSO-DSO coordination helps mitigate the adverse impact of flexibility activation • Intraday and balancing market bids could be used for congestion management • Flexibility-related data can be gathered, stored, processed in a centralized system • Access to Flexibility-related data can improve visibility and decision-making [ABSTRACT FROM AUTHOR]

The high and growing share of renewable sources and the more important role of Distributed Energy Resources (DERs) in the Distribution System (DS) is leading to a need for more efficient coordination of those sources. In future power systems, TSO–DSO coordination will play a key role in providing flexibility services. Lack of proper coordination of sources may lead to congestion in the network or to a lack of possibility to generate or consume energy on a requested level. The crucial aspect is that the TSO–DSO coordination must be based on an active role of all participants: TSO, DSO, generation units and the demand. This paper presents the possible application of the TSO–DSO coordination by providing the flexibility services from DS to the Transmission System (TS). The paper presents the complex optimization of TS, DS and its coordination. The main goal of the paper is to show the possibility of the application of the flexibility market into the current system design. It requires the creation of a new platform, where the offers of the flexibility services could be submitted and then exchanged between entities. The paper shows that the usage of flexibility services may decrease the operational cost of the system, and the DERs providing those services may benefit from an additional source of income.

Power systems rely on ancillary services (ASs) to ensure system security and stability. Until recently, only the conventional power generation resources connected to the transmission grids were allowed to provide these ASs managed by the transmission system operators (TSOs), while distribution system operators (DSOs) had a more passive role, focused on guaranteeing distribution capacity to bring power to final consumers with enough quality. Now, with the decarbonization, digitalization and decentralization processes of the electrical networks, the growing integration of distributed energy resources (DERs) in distribution grids are displacing conventional generation and increasing the complexity of distribution networks’ operation, requiring the implementation of new active and coordinated management strategies between TSOs and DSOs. In this context, DERs are becoming potential new sources of flexibility for both TSOs and DSOs in helping to manage the power system. This paper proposes a systematic characterization of both traditional and potentially new ASs for TSOs, and newly expected DSO local system services to support the new distribution grid operation paradigm, reviewing, in addition, the main TSO-DSO coordination mechanisms.

This paper proposes a near to real-time local market to provide reactive power to the transmission system operator (TSO), using the resources connected to a distribution grid managed by a distribution system operator (DSO). The TSO publishes a requested reactive power profile at the TSO-DSO interface for each time-interval of the next delivery period, so that market agents (managing resources of the distribution grid) can prepare and send their bids accordingly. DSO resources are the first to be mobilized, and the remaining residual reactive power is supplied by the reactive power flexibility offered in the local reactive market. Complex bids (with non-curtailability conditions) are supported to provide flexible ways of bidding fewer flexible assets (such as capacitor banks). An alternating current (AC) optimal power flow (OPF) is used to clear the bids by maximizing the social welfare to supply the TSO required reactive power profile, subject to the DSO grid constraints. A rolling window mechanism allows a continuous dispatching of reactive power, and the possibility of adapting assigned schedules to real time constraints. A simplified TSO-DSO cost assignment of the flexible reactive power used is proposed to share for settlement purposes.

Increasing penetration of distributed energy resources (DER) is pushing to increase the coordination between the transmission system operator (TSO) and the distribution system operator (DSO) to improve the power systems efficiency for active distribution network (DN) scenarios. In this context, the European CoordiNet project seeks to develop tools to measure the potential benefit of efficient TSO–DSO coordination in Greece, Spain, and Sweden networks, considering demand response, storage systems, and small-scale generation. This article presents the TSO–DSO coordination framework for the Spanish demonstration through developing a DSO platform that manages the services provided by the DERs, maintaining the congestion and voltage level in the operational ranges for the day-ahead and intraday markets. Thus, a deterministic mixed-integer non-linear model, based on the AC-OPF, is introduced for congestion management in two Spanish DNs (MV and MV/LV). The operational model constraints and the MV and MV/LV networks have been validated using the power system modeling software PandaPower. The results show that the DSO platform developed under the CoordiNet project guidelines allows for managing congestion and voltage issues at the distribution level through the flexibility provided by the DERs. • A DSO platform framework for the CoordiNet project Spanish demonstration is presented. • A mixed-integer optimization model is introduced to manage flexibility services. • Congestion and voltage issues are managed through a flexibility market framework. • The model is tested in two real Spanish distribution networks with DERs presence. [ABSTRACT FROM AUTHOR]

• Presenting a nested model to coordinate TSO and DSO in energy and flexibility markets with the participation of SBs, EV fleets and DERs. • Presenting a novel DRP design mechanism to build time-varying incentive tariffs based on TSO's flexibility requirements. • Flexibility-oriented scheduling of SBs considering occupants' thermal comfort in a decentralized space with minimal data sharing. • Improving operational security by developing a two-stage interval-based optimization method. • Using KKT conditions, SDT and Big-M method to convert the bi-level NLP problem into a convergent single-level LP problem. Emerging renewable-based transmission and distribution systems, despite many environmental and economic benefits, due to the intermittent nature of their production resources, compared to traditional systems, need more flexibility capacities, which necessitates the need for more suppliers of flexibility. To deal with these challenges, a nested framework is presented to derive the required flexibility of the transmission system operator (TSO) from distributed energy resources (DERs) and active end-users such as smart buildings (SBs) and electric vehicle (EV) fleets at the distribution level. To this end, a novel mechanism to design the demand response program (DRP) is introduced in which tariffs with time-varying rewards are built based on flexibility requirements. The coordination between TSO and distribution system operator (DSO) is initially modeled as a bi-level non-linear programming (NLP) problem, in which the upper-level is day-ahead (DA) operational planning of DS considering the schedules received from SBs, while the lower-level is DA operational planning of the TS. The bi-level NIL problem is transformed into a single-level linear programming (LP) problem by Krush Kuhn Tucker (KKT) conditions, Big-M method and Strong Duality Theory (SDT), which makes it computationally tractable. Finally, a two-stage interval-based algorithm solves the obtained single-level problem to secure the planning against uncertainties where battery energy storage systems (BESSs) are responsible for dealing with extreme conditions. The simulation results testify that the proposed interval-based nested framework has improved the economic, technical and security aspects of the TSO-DSO coordination since it has reduced the daily costs of the energy and flexibility markets, relieved lines congestion and improved voltage characteristics. [ABSTRACT FROM AUTHOR]

This paper proposes a novel approach to TSO–DSO coordination in day-ahead operation planning for the procurement of ancillary services (AS) such as congestion management and voltage control. The approach overcomes two major issues hindering practical applicability of existing TSO–DSO coordination mechanisms, namely the computational complexity due to the large number of times the TSO and DSO problems are resolved as well as the inability to map analytically the cost and amount of flexibility at DSO level into TSO problem. To this end, a two-fold novelty of our approach consists of the decomposition of the overall AS problem into two sequential stages, which seek the procurement of: (i) "active power related" AS (i.e., for congestion management) and then (ii) the "reactive power related" AS (i.e., for voltage support), respectively as well as a fast approximation of the cost of aggregated active and reactive power flexibilities of active distribution systems (ADSs). Unlike existing mechanisms, the proposed approach considers real-world challenging aspects such as the N-1 security at TSO level and operation uncertainties at both TSO and DSO levels. Accordingly, the approach relies on tailored versions of stochastic multi-period AC security-constrained optimal power flow (S-MP-SCOPF) at TSO level and stochastic multi-period AC optimal power flow (S-MP-OPF) at DSO level, which are formulated as non-linear programming (NLP) problems. The importance and performance of the proposed approach are illustrated on a power system connecting a 60-bus transmission system (under 33 N-1 contingencies) with five 34-bus ADSs. • This paper proposes a two-stage approach to TSO–DSO coordination in day-ahead operation. • The approach procures optimally ancillary services for managing congestion and voltages. • A new mapping cost vs amount of aggregated flexibility in distribution grid is proposed. • The paper considers real-world challenges such as operation uncertainties and the N-1 security. • The approach relies on tailored versions of stochastic multi-period AC optimal power flow. [ABSTRACT FROM AUTHOR]

Due to the increasing penetration level of local generating resources at the distribution network, the transmission system operator (TSO) and distribution system operators (DSOs) need to coordinate their operations to use these resources and provide the required energy and regulation for the power system. This work proposes a hierarchy model for scheduling the local flexible resources at the distribution and transmission levels. In the first stage, the optimal bidding strategy of balance service providers (BSPs) and the distribution balancing market-clearing problem are formulated by a bi-level optimization problem, respectively. At this stage, the lower-level sub-problem is replaced by the Karush–Kuhn–Tucker (KKT) conditions, and the bi-level problem is formulated as a mathematical programming with equilibrium constraints (MPEC) problem. Results of the first stage are considered as fixed parameters for the second stage problem, which specifies the feasible bids of local resources that the TSO can dispatch. At the second stage, DSO checks the feasibility of remaining bids, which are not dispatched in the distribution balancing market, and determines the maximum regulation capability of the local resources that the TSO can use. Simulation results indicate that in the IEEE 33-bus distribution test system with the total imbalance energy of 4.672 MWh, 32.36% and 67.64% of the required power are compensated by transmission balancing market and local resources, which results in a reduction of 24.32% in balancing costs. • An optimal strategy for BSPs at distribution and transmission levels is determined. • A two-stage model is proposed for using local flexibility resources by BSPs. • A hierarchy model is proposed for coordination between DSO and TSO. [ABSTRACT FROM AUTHOR]

The increasing role of distribution networks as an active entity in the whole power and energy system, development of a unified power flow method to provide an integrated analysis of transmission and distribution networks becomes essential. Traditional methods have not addressed the challenge of voltage security in the coordination, while disconnecting the whole distribution network is considered as a solution for preventing major issues. This paper proposes a decentralised scheme for the coordination of transmission and distribution networks while maintaining the voltage security of the whole integrated system. At the transmission level, the transmission network operator (TSO) solves a centralised optimisation problem to minimise the system load curtailment while maintaining the system security margin. The TSO communicates the required set-points in the interface with distribution grids to the distribution system operators (DSOs.) At the distribution level, the DSOs utilise their available distributed flexibilities, such as conservation voltage reduction and feeder reconfiguration, to provide the required set-points and preserve the whole system security margin, with minimum load curtailment. This decentralised optimisation scheme preserves the system security with minimum information exchange between operators, as well as minimum physical load curtailment. The distributed flexibilities of all DSOs are utilised to meet the required security margin of the whole system. The proposed TSO–DSO coordination model is applied to the IEEE 118-bus transmission network, and the 83-bus practical distribution network of Taiwan Power Company and IEEE 33-bus feeder are considered as the connected distribution networks. The results show that the distributed flexibilities are capable of reducing the system demand to preserve the desired security margin, without any need for imposing direct load curtailment. • A decentralised approach is proposed for TSO–DSO coordination. • Loadability margin is introduced as the security criteria for TSO–DSO coordination. • Conservation voltage reduction and network reconfiguration for providing flexibility. • Coordination is provided with the minimum volume of data exchange. • Distribution network of Taiwan Power Company is used as practical test system. [ABSTRACT FROM AUTHOR]

This paper proposes a new methodological framework to support the decision of Brazilian distribution companies (DISCOs) when defining maximum demand contracts with the transmission system. The contract must be established one year ahead, and several uncertainties associated to loads, distributed generation (DG) and internal grid contingency events, should be considered. The optimal contracting decision should take into account the risk profile of DISCO's stakeholders and the interest of final consumers. To tackle these topics, an engineering-based approach is proposed in which a chain of four methods composes the final solution approach. To ensure realistic and tractable solutions, load and DG time series are decomposed into low and high frequencies to address the challenge of deriving long-term probabilistic forecasts for high-dimensional time series in high frequency. The proposed methodology considers exogenous long-term trend drivers (such as economic and climatic indices) in the probabilistic forecasts of loads and DG, as well as corrective actions to respond against contingencies in the power flow simulation. Results for a Brazilian DISCO show that the proposed probabilistic forecasts are adherent and tractable. Our case study corroborates the effectiveness of our approach to support DISCOs' decision and adjust their contracts based on pre-specified risk levels. • Four integrated methods to define long-term DSO-TSO demand contracts in Brazil. • A new method for simulating high-dimensional hourly load and DG time series in a long-term horizon. • A new array of quantile regressions to estimate and simulate conditional dynamic load curves. • A risk-averse optimization model to define the optimal demand contracting strategy of a distribution company. [ABSTRACT FROM AUTHOR]

The renewable energy generation (REG) integration has introduced a significant amount of uncertainties to power systems. This new trend requires power systems to have sufficient flexibility to mitigate the power imbalance between supply and demand. Demand response (DR), as a potential flexibility resource, has gained widespread attention in recent years. However, communication failures or customers' unexpected behaviors may result in DR uncertainties, leading to operational risks. To cope with the impacts of DR and REG uncertainties, this work proposes a stochastic programming-based risk-averse optimal dispatch model to reduce both electricity purchasing cost and potential risk cost through transmission network (TN) and active distribution networks (ADNs) coordinations. The risk-averse distributed optimal dispatch problem is formulated as two sub optimization models. One conducts the transmission-level risk-averse generation dispatch, while the other represents the distribution-level ADN market clearings. Moreover, the conditional value at risk (CVaR) is used to measure the potential risk cost caused by DR and REG uncertainties. Finally, the optimization model is solved by a distributed solution algorithm, alternating direction method of multipliers (ADMM), to preserve data privacy between multiple stakeholders and reduce communication requirements. The performance of the proposed approach is evaluated in T30-D2 × 33 and T118-D85 + D2 × 69 test systems, the results validate its effectiveness. [ABSTRACT FROM AUTHOR]