Following the conventional design of the electricity system, the power from the large generators is carried to the transmission systems, while the distribution grid is responsible for the electrification of the loads connected to the medium voltage (MV) and low voltage (LV). The frequency and voltage are mainly controlled by the bulk generators by means of providing certain advanced services to the transmission system [1
]. However, this centralized approach is becoming outdated, since Distributed Generators (DGs) and, more specifically, Distributed Renewable Energy Resources (DRESs) are connected within the transmission and distribution system, causing the gradual decommissioning of the conventional synchronous generators (SGs). This trend results in stability and reliability challenges for grid operators. The problem is becoming more severe considering that the majority of the DRESs are converter-dominated—in some cases, with the absence of any rotational masses, and hence, do not have technical predispositions to provide Ancillary Services (ASs). Furthermore, the DRESs have a highly volatile and intermittent nature due to the dependence on weather conditions. As a result, the whole philosophy of the provision of certain services to the grid operators should certainly be revised.
Currently, ASs are services mainly provided by SGs in order to ensure the system security and energy supply with high quality standards [2
]. The Transmission System Operators (TSOs) are responsible for procuring and using ASs in their scheduling and dispatch of generation as well as during the real-time system operation. ASs are provided through the efficient procurement (when applicable) to the TSOs by third parties (generators, storage, and flexible loads). Through the liberalization of the electricity markets, the role of the ASs has been advanced, since Balancing Service Procurement (BSP) entities submit their bids for providing ASs to the TSOs. Specific requirements for the eligibility of the AS providers are set appropriately in the National Codes [3
], with the main target of keeping the frequency and voltage within specific safe bands and restoring their values to the normal range after an imbalance occurs. Accordingly, the main categories of AS refer to frequency response, voltage control and black-start capability [5
]. According to reference [6
], many differences are identified among the types of procurement of AS in several EU and non-EU countries, as well as the way of remuneration of the AS.
The common report by the ENTSO-E and several EU/DSO entities (E.DSO, Eurelectric, etc.) defines AS as services provided to DSOs and TSOs to keep the operation of the grid within acceptable limits for security of supply and delivered mainly by third parties (i.e., active power control for frequency control, reactive power for voltage control and black-start capabilities) or by the TSOs and DSOs themselves (topology changes and integrated network components) [7
]. However, similar to the ASs already referred to, some new ones can be provided by DRESs at both the transmission and distribution system level, as already proposed in the literature and prescribed in recently issued guidelines and standards. In many cases and especially in distribution grid level, these ASs are considered to be system support functions specified for DRESs [8
], meaning that these services are not remunerated but are considered as mandatory for the DRES connection at the transmission and distribution system level. Some examples are the Fault Ride-Through (FRT) capability and the voltage support through reactive power control. Other types of ASs, recently introduced or proposed according to the new operational environment, can be found in [9
In this paper, the current AS structure is analyzed, while new ASs procured by DRESs connected both to the distribution and transmission system are proposed. In the literature, the review papers are either focused on the system requirements for increasing the DRESs’ capacity, without elaborating the need for the provision of new remunerated ASs [10
] or deal with a specific AS from DRES, such as the provision of flexibility [12
], frequency [13
], and voltage AS [15
]. Other review papers provide a more market-oriented approach, such as references [17
], while in reference [19
], the coordination among the distribution and transmission systems are presented in a conceptual way. A more recent and mature review paper [6
] recognizes the importance of the provision of ASs; however, its focus lies on ASs from HVDC systems. On the other hand, this paper not only presents a more comprehensive review on existing ASs but proposes specific solutions for the engagement of new ASs from DRESs both at the distribution and transmission grid level in order to energize the modern grids with a high DRES penetration. In addition, the paper identifies the possible technical, regulatory and financial barriers that currently impede the adoption of these new ASs. Finally, the paper provides suggestions for lifting those barriers that will enable the procurement of emerging ASs from DRESs connected in a distribution grid.
This paper is structured as it follows: the existing ASs with the current market practice are analyzed in Section 2
, considering the different models in EU and indicative non-EU countries. From this comparison, certain differences are presented in order to highlight the different approach for the procurement of these ASs following the TSOs requirements. In Section 3
, new ASs, especially in distribution grids, are proposed, since the modern grids face the technical issues due to high hosting capacity of DRESs. These ASs include the inertial response, active power ramp, frequency response, voltage control, fault reaction, harmonics mitigation and their integration in the upcoming smart grid/microgrid concept. The role of the Energy Storage Systems (ESSs) by means of installing batteries and use of Electric Vehicles (EVs) is also considered. In Section 4
, an emphasis on the proposals on market mechanisms and tools are described, where the emerging role of the DSO as a central counterparty for the procurement of an AS is reflected. Finally, Section 6
investigates the potential technical, regulatory and financial barriers and obstacles for adopting the new ASs.
5. Obstacles and Barriers
This review paper outlines the introduction of novel ASs to the distribution system level along with the establishment of proper market schemes. However, several obstacles arise imposing the involved parties to act in a cooperative way in order to overcome them [127
]. Network operators, electrical/electronic manufacturers, policy makers, and specialized economists are among those parties that will carry the burden of the transition to a more decentralized, but still stable and secure network environment. The aggregation of the aforementioned AS and their secure and controllable provision to the upstream TSO, still remains an open research issue. In reference [7
], some recommendations are made with respect to the monitoring and Active System Management (ASM) through all voltage levels. Mostly the active power management, as a part of ASM is described and analyzed from the perspective of a close collaboration of TSOs and DSOs, for congestion management in both distribution and transmission grids and system balancing when such services are provided in a market-based approach by flexibilities owned and operated by third parties. In addition, reactive power management has been left out of the report. The reason to concentrate first on congestion management and balancing services provided by third parties is they have priority in the TSO–DSO coordination in order to ensure the security of supply. The urgent need for TSO–DSO co-operation to ensure efficient interaction with market parties is also identified and analyzed, and it is stressed out that DSOs and TSOs need a toolbox comprising different types of solutions for undertaking congestion management and balancing. These include (i) technical solutions using grid assets, (ii) tariff solutions, (iii) market-based solutions, and (iv) connection agreement solutions.
In this paper, a first categorization of further challenges to be addressed can be made between technical, regulatory and financial matters, which also suggests the most suitable parties that are going to lead the change in each case.
5.1. Technical Barriers
One of the most significant barriers is related to the current coordination level between the TSOs and the DSOs, which is regarded quite poor and cannot serve for the efficient provision of AS, taking into account their bottom-up approach. This is due to the following reasons: the first one is the fact that the numerous DRESs within the distribution systems are not “visible” and controllable by the TSOs. In this context, not even the DSOs know the dynamic capabilities of the DRESs within their own distribution grids, simply because this is not part of their business—at least, not until now. This situation is comprehensively presented in the recently published (April 2019) “TSO-DSO Report: An Integrated Approach to Active System Management” [7
]. The second reason is the absence of methodologies to determine the aggregated response of a whole active distribution grid at the PCC with the transmission system for given response capabilities of the individual DRES. For example, let us assume that the inertial response of all DRES within a distribution system is known. How is the aggregated in inertial response calculated considering also technical constraints within the distribution grid? The reverse case is also still unexplored, i.e., the assignment of certain AS-response characteristics to specific DRES within a distribution grid, so that the overall response is the one requested by the TSO. The third reason, which is a direct consequence of the first two, is the absence of methods for developing simplified yet accurate equivalent electric models of the whole distribution grid for both dynamic and steady state condition as the DRES and load mixture changes. Such equivalent models would be the main communication means between TSO-DSO enabling the former to evaluate the response of the whole grid taking into account the contribution of DRESs connected in the distribution system, i.e., not controlled by the TSO. Generally, the TSO-DSO coordination is a matter of particular interest within the Horizon 2020 project “SmartNet”, which further investigates the interaction schemes between TSOs and DSOs in order to facilitate the increasing DRES integration [132
]. Another project dealing with the coordination between DSOs and TSOs in order to procure grid services in a reliable and efficient way is CoordiNET [11
]. According to reference [136
], the exchange of information between TSOs and DSOs is considered limited, which is a serious issue for bridging the gap among DSOs and TSOs. In the upcoming decentralized systems with DRES penetration, each operator should reconsider the role to the energy systems and especially to the AS market. In reference [137
], it is proposed that the DSO will be in charge of collect the small-sized DRES and provide AS to the TSO in a coordinated manner. Another reason for the poor coordination between TSOs and DSOs regards the lack of establishment of a clear definition of the hierarchical procedures. To this end, common grid codes to distribution and transmission, with explicit focus on the cooperation is missing. Some solutions to this issue are proposed in reference [19
], where the coordination schemes for developing different market structures is emerged, based on the communication principles among the operators. Furthermore, specific guidelines for building a strengthened coordination are included in the EDSO report [138
]: the TSOs and DSOs should clearly define the data they need from each other, schedule the system planning, define the connection requirements for DRES and end-users, and develop coordinated networks codes.
A significant challenge is also the installation of a proper ICT infrastructure in order to exchange the necessary data for monitoring, accounting and control of the AS provided by distribution entities (e.g., DRES, flexible loads) to the transmission system [132
]. Some barriers in this regard include the not-so-clear specifications for enabling security while transmitting data through existing communication standards. In [62
], it is mentioned that standardized communication should be used for signal transmission between the DSO or TSO control centers and the DRES (e.g., EN 61850-7-4, EN 61850-7-420, IEC/TR 61850-90-7, as well as EN 61400-25 for wind turbines). In parallel, the standards need to consider the aspect of interoperability for various devices, operators, and services to exchange information in a seamless manner. As it can be deduced, since the aforementioned specifications are quite vague, the need for “visibility” [7
] of each individual DRES up to the transmission system cannot be met.
Another technical obstacle is the lack of validated and commonly agreed methods for the quantification of services at distribution system level. It is noted a service should be quantified in order to become tradable in a market. The quantification should be made both at the terminals of each DRES and at the transmission-distribution interface when an AS is offered to the transmission system in aggregated form. A first attempt to define metrics for some AS has been already done in references [51
]. Therefore, it is essential to establish new quantification methods that will reflect the actual provision of every service at the points of interest with relatively high accuracy. To this end, modern metering devices will also need to be installed being fully in line with the new measurement standards. The latter is emphasized in reference [105
], as one of the technical challenges that the DSOs are facing due to the increasing share of DRES. The current measuring systems installed in most distribution networks do not serve for the DSOs to gain access over particular key quantities, necessary for enacting any control over DRES units, such as instructing a particular active power reduction or adjusting reactive power in order to maintain the system balance. Currently, the measuring devices used in distribution grids include SCADA systems, distribution line measurement systems and smart meters [134
], and measure data related to the steady-state operation of the network [135
]. As a result, they cannot capture and quantify AS related to the dynamic network operation (e.g., inertia or harmonic mitigation). Moreover, according to the requirements for the interconnection of DRES [71
], their built-in metering infrastructure presents limited measurement capability with respect to dynamic phenomena, while they focus on the accurate detection of changes and not on the accurate calculation of absolute values [140
]. Phasor Measurement Units (PMUs) [141
] are mainly used at the transmission system acting on a fast timescale and can provide synchronized measurements. However, as it was proved difficult for the PMU manufacturers to comply with the strict limits [142
], an amendment of the IEEE Standard C37.118.1 was published relaxing these limits, thus introducing inaccuracies under dynamic conditions [143
Finally, the introduction of the new suggested AS imposes indirectly necessity in the update of the control strategies of the converter-interfaced DRES. Although recent standards and grid codes [61
] specify new functionalities for DRES (e.g., P-f
droops with variable slopes and settings) [24
], the DSOs “lock” the operational mode of the DRES according to the currently applicable grid codes. For instance, in most of the cases the operation mode is “locked” into “MPP Tracking” mode because the DRES got a connection permission just for injecting renewable energy. Thus, other functionalities, such as the exchange of reactive power, or contribution to PFR are disabled. Therefore, an aggregator for instance, needs to request for permissions to “unlock” the full DRES capabilities, and of course, assume the full responsibility on their operation.
5.2. Regulatory Barriers
Policy makers and regulatory authorities can have a major effect on the way ASs will be provided to the power system in case of increased DRES penetration, while they can certainly facilitate the establishment of an AS market at the distribution system level. However, until now, obstacles appear at the regulatory framework of most countries that discourage the establishment of new ASs and prevent the DRES operators from offering their services. This issue is particularly discussed in reference [144
], which analyzes the future scenario of AS provision by DRES and Demand Response (DR) at the distribution level. More specifically, technology and size limitations imposed by the present regulations are referred to as one of the main reasons why DRES units and loads are excluded from the AS markets, even though they could potentially provide the requested services. Additionally, minimum bid size requirements are usually set for individual units and aggregation of services is forbidden in many countries, hence preventing small generating and load units from participating in the market. Finally, some ASs are defined for both upward and downward regulation, which raises an obstacle to some providers.
In reference [145
], an overview of barriers that hinder the integration of PV units in the European distribution system is presented. Among others, the authors claim that the regulatory framework defining the network planning responsibilities of the DSOs does not promote smart grid investments. Although such investments are necessary for the development of AS markets at the distribution level, additional expenditures arise for the DSOs, which should be recovered by the establishment of a proper revenue scheme. Another obstacle emerges by the requirement of several regulations in Europe that PV units should continuously operate in their MPP, hence excluding their contribution to balancing, which results in increased costs for grid reinforcement. The absence of a particular policy and regulatory framework for PV units to provide AS is also described in reference [105
], which outlines the issues of the DSOs due to increased DRES penetration. The necessity for the DSOs to define the active and reactive power output of individual DRES in emergency conditions is also emphasized, as currently there is no legal provision for them to gain access to the units’ converters capabilities directly.
Another aspect highly investigated by the recent literature is the participation of BESS in the energy market along with their contribution to the AS provision within the distribution networks. Among others, [146
] presents and analyzes the main regulatory barriers that hamper their deployment and prevent them from entering the electricity market, resulting in their poor participation in the AS market as well. The classification of BESS as a generation asset rather than a flexibility provider by the current regulation imposes double network usage charges to their owners, hence discourages their extensive usage. TSOs and DSOs are also restricted from owning and operating storage facilities, in compliance with the unbundling obligations of the EU Directive 2009/72/EC (despite being best positioned for their optimal use), which leads to significant uncertainty for further investments. Finally, the lack of proper balancing and AS markets that would facilitate the increased use of BESS technologies, in order to provide their valuable flexibilities to the system, is pointed out as one of the main barriers to their development. In reference [147
], the authors recognize that the current perception of storage, as a supplementary asset to assist generation in balancing load, does not serve for the exploitation of its full potential in providing additional flexibility services. In particular, it is referred that the existing regulatory framework hinders the full development of ESSs, by setting limits to revenues coming from multiple market services, such as the AS market. This also stems from the fact that there is neither clearly defined storage-pricing policy nor specific tariff-regulation, until now. Therefore, it is proposed that effective regulatory and financial policies should be established, identifying storage as a distinct asset class, would it be for it to play a central role in the restructured electricity market.
Another barrier is the fact that the current market regulations treat the DSO mainly as market facilitator (or service requesting entity), leaving the offer of AS to third parties, like the aggregators. However, a number of technical constraints should be respected when offering ASs based on DRESs located within the distribution grid. Therefore, the DSO should be involved in the process of evaluating the technically feasible amount of each AS that can be offered at any time period, even in the cases an aggregator is responsible for the trading of these AS. This issue has to be considered in the modification of the respective AS market regulatory framework.
5.3. Financial Barriers
As more and more DRES are going to provide AS to both the distribution and the transmission system level, it is essential that a proper remuneration scheme is introduced, based on the value estimation of each service. According to reference [148
], the electricity markets should be developed accordingly, so that the value of the flexible resources is more visible in market prices and proper investment signals are sent. Currently, non-dispatchable DRES providers are excluded from the AS market, since, as previously referred, there is no financial policy to incentivize them to offer their services. Furthermore, these DRES are mainly favored by alternative remuneration schemes, which are implemented in most countries and guarantee much more beneficial prices (e.g., feed-in-tarrifs, net-metering, net-billing, feed-in-premium, etc.). On the other hand, conventional generating units and some types of dispatchable RES (e.g., biogas, hydro) mostly offer their flexibility resources in long-term bilateral contracts between them and system operators, at fixed regulated prices. The necessity for a more realistic definition of the AS value, based on a proper estimation of the related installation costs and benefits is also underlined in reference [149
], which proposes the development of efficient operational signals that should be sent via nodal energy prices, such as Distribution Locational Marginal Prices (DLMPs).
Another serious obstacle that prevents AS providers from offering their services, is relating to the timing of markets. According to reference [150
], the current scheme does not provide for the market participants to react faster in the changing conditions caused by the intermittent generation. However, the recent European Commission regulations recognize their need to adjust the imbalances in the intraday market time-frame, as close to the real time as possible [3
]. Therefore, a maximum time of one hour between intraday gate closure and real-time operation has been established, while a discussion is currently taking place between different National Regulatory Authorities (NRAs) in Europe in order to reduce the particular time window to half an hour.
Finally, following the aforementioned necessary investments regarding the ICT infrastructure and the measuring system that need to be installed at the transmission and the distribution level, an appropriate recovery scheme should be introduced so that the corresponding network operators can manage their costs. This is stressed in reference [7
]. However, according to reference [145
], the tendency of the current regulations to promote short-term cost reductions, especially for the DSOs, may not accommodate for this type of expenditures, leading to a climate of uncertainty for such investments.
5.4. Potential Barriers Regarding the New Emerging ASs
Inertial response: The quantification of the inertial response faces a number of challenges. (i) Inertial response is actually detectable only in cases of large ROCOFs, i.e., under major frequency events. Thus, for most of the time, the inertial response results in power deviations of the DRESs’ electrical power that are too small to be measured. On the other hand, inertial response is present all the time helping the system to arrest large frequency deviations. (ii) If we assume the realistic case where the various DRES within a distribution system have different inertia constants, the quantification of the aggregated inertial response, as seen at POI of the distribution-transmission system is still an open research issue. (iii) The term “inertial response” is currently used also for the action of FFR. Such a response is provided by DRES that are not associated with a fast ESS (e.g., supercapacitor or flywheel). Therefore, it is actually a late inertial response, for which the measurement of frequency and ROCOF is required. The latter, in turn, poses challenges with respect to the accurate quantification of this service.
PFR: Until now, SG units are paid for their capacity offers and in some cases for the energy injected when providing the service [22
]. A key challenge is highlighted in reference [151
], which examines the participation of DRES in PFR by proposing a novel procedure to design the frequency droop curves, in an attempt that every distribution feeder provides a guaranteed frequency response at the feeder head (transmission–distribution interface). However, a concern arises regarding the contribution of every single unit to the service so that they are not unfairly penalized and inject the required power to the system based on their ratings and their location in the distribution network. If such behavior can be achieved, an additional solution should be found in terms of remunerating the aggregated service provided to the TSO and distributing the payments to the individual DRES/BESS providers. Those payments should be based on the power output of every unit, as indicated by a proper measuring system, in accordance to what was previously referred.
Voltage regulation: Several technical problems during voltage regulation with reactive power are identified, such as (i) technical capability of providing the required reactive power characteristic; (ii) impedances of the DG plant components are not sufficiently considered during the planning operation of the DG; and (iii) the requested reactive power is provided at connection terminals of the DG units and not at PCC of the entire DG [150
]. Therefore, apart for deriving a proper definition and metric for the reactive power, the reactive power capability of the converter-interfaced DRESs should also be properly evaluated. Also, this particular AS adds costs to converter-interfaced DRESs, due to the active power losses within the converter and the step-up transformers (whenever they exist), leading to a reduction in the overall efficiency [76
]. These costs should be taken into account and compensated.
Power smoothing/ramp-rate control: Currently, power smoothing is not recognized as an AS by most grid operators. However, in some cases of islanded and RES-heavy power systems, grid codes define maximum variability level of DRES, typically in terms of ramp rates, hence regard power smoothing as a system support function [152
]. The development of this service highly depends on the deployment of ESS technologies. Therefore, any obstacle preventing their usage in order to provide additional flexibilities, especially within the distribution networks, can also be regarded as an obstacle for power smoothing. In reference [153
], the installation and control of ESS for reducing the variability of PV units is considered to significantly raise to their operating cost as well as the cost of their produced power. Such costs can be recovered only if power smoothing is provided as an AS and a relevant market is introduced. Also, since mainly TSOs are going to take advantage of the service’s benefits, because of the reduction in the number of units in reserve when power smoothing is provided, a relevant market needs to be introduced at the transmission system level, in parallel with the market for PFR procurement.
FRT and fault clearing: An important challenge of the fault participation of DRES units regards the fault current limitation, which is imposed in most of the converter-interfaced DRES because of the thermal limits of the switching devices. Therefore, the use of the conventional over-current protection techniques cannot be facilitated [154
]. Hence, the capability of the converter to provide fault-currents should be also evaluated. If converters are oversized to meet this demand, additional costs will arise for the producers that should be taken into account when providing the service. Finally, the benefit of making the DRES inject certain currents during the fault period so that the selectivity of the existing protection means is preserved even under very large DRES penetration should be accordingly evaluated.
Harmonic mitigation: The idea for the injection of certain harmonic currents in order to mitigate the voltage harmonic pollution at specific nodes within the distribution system is not applicable until now, since several international standards establish particular harmonic current limits to the connecting facilities, as a way to mitigate voltage harmonics. This may be required either directly, as in the case of IEEE Std. 519–2014 [154
] or indirectly, by setting voltage harmonic limits, which in combination with the system impedance lead to the respective current limits (e.g., IEC 61000-3-6 Std. [156
]). It is evident from the review conducted in the previous section that harmonic mitigation by DRES is already considered in the literature as possible ASs. Therefore, the particular standards need to be revised in order to allow some of the DRESs to act like active harmonic filters. Finally, the additional cost incurred for making a DRES operate as an active filter is not yet addressed.
6. Suggestions and Conclusions
This paper provides a detailed review of ASs currently provided and remunerated in several countries across the world as well as a comprehensive review of the existing market regulations with respect to the AS provision at the transmission system level. Moreover, an in-depth review with respect to new ASs that can be provided by DRESs is carried out for both distribution and transmission system level. Figure 6
indicatively shows the AS dealt with in the EASY-RES project [157
], together with the voltage level they are meant for. ICA stands for Independent Control Area, which is actually considered to be the distribution system.
These ASs are currently considered as system support functions that are mandatory for the DRES connection. A review of new market schemes with respect to AS remuneration at distribution system is conducted. Finally, the obstacles and barriers for the new ASs to be introduced in market schemes are identified. These obstacles are categorized as technical, regulatory and financial, while the barriers per each AS individually are also identified.
A general conclusion that can be drawn from the information presented in this paper is that ASs are currently provided only to the transmission system and mainly offered by large scale conventional units. However, the conventional units are gradually displaced by the increasing penetration of the DRES in the distribution system. It is well known that these DRESs, particularly those that converter-interfaced can provide a number of new functionalities which are currently considered as system-support functions. To transform the system-support functions into ASs, the following suggestions are presented:
Suggestion 1: Methods for the quantification of each service should be developed, validated and agreed among the interested stakeholders. The quantification should include specifications on the measurement approach and the associated accuracy. Moreover, in cases an AS is offered to the upstream transmission system (e.g., virtual inertia, PFR, reactive power support, ramp-rate control), measurements should be made in a synchronized manner on each DRES participating in the AS and on the POI with the transmission system in order to evaluate the actual amount of service that has been delivered at the POI and the contribution of each DRES to this. In this context, the measuring devices should be capable of capturing services offered under transient or dynamic conditions (e.g., inertial response, or dynamic reactive power support) and have access to measurement conducted within the DRES converters such as the tracked Maximum Power Point. The latter is necessary in order to verify that, for instance, a DRES is operating under an agreed headroom being, thereby, able to provide PFR in underfrequency events.
Suggestion 2: Methods need to be developed so that an aggregator is able to evaluate the aggregated amount of service that can be delivered to the POI based on the type, size and location of the DRESs within the distribution system under their responsibility. This is essential in order to be able to make offers of ASs to their respective markets. Methods for the reverse procedure need also to be developed: after an agreed amount of an AS with TSO, the aggregator needs to evaluate the optimum, with respect to cost, allocation of this service to the portfolio of DRESs he manages. The aforementioned methods should take into account a number of technical constraints imposed by the proper operation of the specific distribution grid. For this reason, these methods should be transparent to the DSO and the final amounts of service will be fixed after DSO approval.
Suggestion 3: For a number of ASs that are meant to be offered within the distribution system, such as contribution to fault-clearing and harmonic mitigation, the quantification methods need to define the starting and ending moments of each service. For instance, the start of a fault condition and its end, thereby its duration should be defined so that the contribution of a DRES with controllable currents can be quantified. The same is true for the harmonic mitigation ASs where the existence of background harmonic distortion should be evaluated and taken into consideration in the quantification process.
Suggestion 4: Apart from the development of measurement and quantification methods, the associated costs (investment and operational) for each AS need to be evaluated in order to enable the development of viable business models and, eventually, AS markets at distribution grid level. It is also noted that the provision of inertial response, falls in the same category despite the fact that it is offered to the transmission system. The reason is that currently inertial response is still considered as a system-support function also at that voltage level because it is inherently provided by the conventional SGs. Therefore, no additional cost is implied. However, when inertia is provided synthetically, additional investment and operation costs emerge and need to be remunerated.
Suggestion 5: A rather simple but highly secure ICT system is required for the coordinated control of the various DRES within the distribution grid and the accounting of the quantified ASs. The ICT can be simple since most of the ASs are based on the local control of the DRES converter while the role of the ICT is mainly the enabling/disabling of an AS in a DRES and the transmission of various set points in relatively large time intervals (of the order of minutes). Security is required because the measured ASs will be traded in an AS market and finally remunerated. For the same reason, the ICT system and the control and accounting platforms should be transparent and accessible to all involved stakeholders. The cost associated with the development, operation and maintenance of such an ICT system should be considered in the development of business models together with the aforementioned costs of the DRESs.
Suggestion 6: A registry containing all the properties of the DRESs within a distribution system should be made and be transparent to the TSO [7
]. This will form the basis for further development of methods for the estimation of the equivalent models (containing both the steady-state and dynamic behavior) of the distribution grid considering the technical constraints within it. The transparent registry and topology of the distribution grid will help in the validation and mutual acceptance of the equivalent models enabling the TSO to use them in the evaluation of the whole system response treating the distribution grids as VPPs. The equivalent models need to be regularly (every 5–10 min) updated to reflect the changing DRES penetration and load variation [157
To sum up, the main highlights of this review are listed below:
The DRES within the distribution grids can provide a number of traditional and new AS, thus enabling the decommitment of conventional SG, mostly driven by fossil fuels while maintaining the secure and stable operation of the power system.
A number of obstacles and barriers need to be overcome for the introduction of AS originating from the DRESs. First, a number of technical and economic issues need to be researched as mentioned in the four suggestions above, particularly the measurement and quantification of the new services so that they cease to be treated as system-support functions and start to be treated as tradable ASs.
Each of the aforementioned suggestions presents a research topic that involves, apart from researchers, regulatory authorities, and standardization bodies.
The list of the ASs presented in Figure 6
is not exhaustive but simply presents those ASs treated in the EASY-RES project. Additional services may be defined (for instance, congestion management) which however need to be properly delimited in order to be treated as future ASs.