Grid Flexibility

Assessing Europe’s future transmission system requirements

Over the past few years, the European Union (EU) has been making concerted efforts to shift towards cleaner energy by setting ambitious targets and formulating supporting policies. To achie­ve its goals of becoming carbon neutral by 2050 (under the European Green Deal) and reducing its greenhouse gas emissions by at least 55 per cent by 2030 (with support of the Fit-for-55 package), it is looking to integrate large-scale variable renewable energy (VRE) into the grid. Un­der the Fit-for-55 package, the share of renewable energy is proposed to be inc­r­eased to at least 40 per cent by 2030 (from 32 per cent previously), along with the introduction of sector-specific measu­res for increasing the EU’s contribution to the final energy demand. For this, the EU will need 451 GW of wind capacity by 2030 (up from about 180 GW in 2021) and will have to double its planned annual ca­pa­city addition in the coming years.

This shift towards greater renewables integration comes with its own set of challenges for grid operators as it impacts gr­id resilience. Balancing supply and de­ma­nd at all times is critical given that even a small variation can disturb the frequency of the power system, and also affect system ope­ra­tions and reliability. The large-scale rene­wable energy penetration mea­ns large swi­ngs in power supply and de­mand, thus making a case for flexible po­wer systems.

In this backdrop, the European Network of Transmission System Operators for Elec­tri­city (ENTSO-E) recently released a po­sition paper on the “Assessment of Fu­ture Flexi­bility Needs” in Europe. The pa­per provid­es insights on identifying the fle­xi­bility ne­eds in generation, demand and storage.

Need for flexibility

Fundamentally, power system flexibility needs arise from variations in the power system due to uncertain and fast changing generation, demand and grid capacity. In terms of demand, the electrification of hea­ting, transport and industries has led to greater uncertainty and variation. For ins­tan­ce, lack of smart charging in electric ve­hicles (EVs) as well as larger electric loads, subject to temperature variations, difficult-to-forecast customer preferences and uncertain price responsiveness, can lead to huge fluctuations in demand.

On the generation front, the increased use of VRE and less despatchable generation (which can be despatched on grid opera­to­rs’ demand as per market needs) causes imbalances in supply.

In grids, variation and uncertainty are ca­us­­ed by VRE, distributed energy re­so­ur­c­es and inverters (devices that convert DC electricity into AC). With the large-sc­ale deployment of inverter-based generators, system inertia is expected to dec­rea­se and lead to increasing rates of ch­an­ge of frequency (RoCoFs), which can prese­nt a challenge in terms of frequency stability of the system.

Existing assessment approaches

The EU’s extant power system planning methods already assess flexibility needs, and the availability of solutions and produ­cts to cover flexibility gaps in many cases. These needs are addressed in the Euro­pe­an Re­so­urce Adequacy Assessment, the sy­stem operation, capacity allocation, con­g­estion management and electricity ba­lancing gui­delines, as well as the Electricity Re­gula­ti­on. For instance, in recent years, ENTSO-E’s Ten-Year Network Develop Plan has fo­re­cast decreasing inertia levels due to converter-interfaced renewables su­ch as solar photovoltaic (PV), wind and battery re­­so­ur­ces becoming dominant. Coupled with increa­sing RoCoF due to the rise in sudden disturbances, this may create de­mand for fast frequency respon­se capacities. In­dicators such as inertia, RoCoF, area control error and frequency restoration co­ntrol error quality need to be investigated.

Ireland’s transmission system operator (TSO), EirGrid, has illustrated the speed at which frequency response challenges can be met. Meanwhile, the adequacy and fle­xi­bility assessment study by Belgium’s TSO Elia provides examples of flexibility metrics that address unexpected generation and demand variations after the day-ahead time frame. Moreover, there are re­search and innovation (R&I) projects such as MIGRATE (Massive InteGRATion of po­wer Electronic devices), which have succe­ss­fully in­vestigated systems with high penetration of power electronics. Another ongoing R&I project is the European One­Net flexibility market project, which started in October 2020. It is funded by the Euro­pe­an Com­mis­sion’s Horizon 2020 progra­mme. Under this, various flexibility ma­r­ket so­lutions and complementary tools for el­ec­tricity network development and operations will be tested over a three-year perio­d. In addition, the project will carry out re­gi­onal studies on flexibility needs and studies on methodological development needs.

With all these developments, TSOs now need to identify which additional flexibilities may be needed at what time in the future and in which European regions, and also understand the possible negative effects of a flexibility gap in the power system.

Flexibility challenges

ENTSO-E’s position paper makes an ass­essment of future flexibility needs in the day-ahead time frame, that is, the flexibility needs arising from increasing variability in the balance of generation, dema­nd and sto­rage. It states that the increasing variab­ility in the forecasted demand and generation in the day-ahead time frame can possibly lead to two new flexibility challenges.

First, the periods when load is increasing and VRE generation is decreasing could require weather-independent generation to ramp up or down at a faster rate and wider overall MW ranges to compensate for the decrease in renewable energy supply. For instance, the increase in load co­uld become steeper due to the increasing penetration of heat pumps and EVs, while the  VRE fluctuations (for example, du­­ring sunset) would grow with higher VRE penetration. Second, the decreasing amount of weather-independent generati­on may become insufficient to cover the demand during extended scarcity periods with very low VRE generation, such as du­ring windless winter weeks.

ENTSO-E’s approach

ENTSO-E conducted a survey of assessment approaches being used by 22 TSOs for future flexibility needs and on inter­na­tio­nal examples of flexibility needs ass­e­ss­me­nts, metrics and products. Ba­sed on the re­s­ponses, ENTSO-E zero­ed in on two fl­e­xibility needs – ramping and sc­arcity periods.

To illustrate how flexibility needs for ramping and scarcity periods could evolve by 2025 and 2030, ENTSO-E considered the example of Germany, which is both one of Europe’s largest countries and has one of the highest VRE penetration rates, based on ENTSO-E’s Mid-term Adequacy Fore­cast (MAF) 2020 data. Though the Ger­man system displays sufficient system adequacy in both the 2025 and 2030 MAF analyses, its high amount of installed wind and solar capacities relative to both peak loads and installed despatchable capacities ha­ve star­ted posing challenges that are quite visible on ramping and scarcity periods.

Notably, the paper acknowledges that a simple analysis of residual loads cannot replace the complete and realistic chronological simulation of system adequacy, wh­i­ch includes forced outages, different cl­i­mate years, as well as imports and ex­por­ts. Therefore, ENTSO-E has proposed metrics that combine the strengths of detailed hourly results from chronological probabilistic simulations, with insights ga­ined from the simple residual load analysis focused on the two relevant and pre­valent variability challenges:

Ramping flexibility needs: The ramping fl­exibility needs approach is partly based on experiences from California Indepen­de­­nt System Operator and Eir­Grid. These metrics measure large daily residual load gradients, for example, at sunset in regi­o­ns with large PV generation capacities. Re­­s­idual load is the load left after subtracting VRE generation (such as wind, PV and run-of-the-river hydro) from the total demand, and is a useful indicator to show the flexibility and ramping needs for adequate power system operation. Expli­cit and implicit demand flexibility was considered a part of the despatchable capacity, and not in the residual load calculation. As per ENTSO-E, the treatment of th­e­­se capacities in the methodology cou­ld be further improved.

Consider the 2025 and 2030 maximum ramps in the residual load over one, three and eight-hour time steps, which reach a substantial fraction of the total despatchable capacity and even exceed it at times. Study that relates the residual load to des­patchable capacities indicates a serious ramping-flexibility challenge, especially for the 2030 data, as despatchable capa­city or other flexibilities would need to be im­ported from neighbouring countries, or renewable energy generation wo­u­ld need to be curtailed in a well-coordinated and anticipated manner to cover such ramps.

However, a key point to be noted is that residual loads do not acc­ount for imports and exports, which stron­gly contribute to ov­e­rall system adequacy, especially for st­ro­ngly interconnected countries such as Ge­r­many. Further, des­pat­chable capaciti­es, which in any case only provide a very ro­­­u­­gh reference for the interpretation of re­sidual loads, are ad­j­usted or derated to ac­c­o­unt for forced outage rates of coal, gas, pumped storage hydropower generation and other capacities, and include the MAF data for demand-side response (DSR).

Broadly, the highest annual residual load MW ramps (calculated as the difference bet­ween residual loads one, three and ei­ght hours apart) can be easily compared with market zones and years after they are normalised to the zone’s despatchable capacity, accounting for demand response and forced outage derations.

The proposed metrics for ramping flexibility needs are percentage of loss of load expectation (LOLE), expected energy not served (EENS), and curtailed surplus ene­rgy during the 5 per cent highest ramp periods. These indicate how the ramping iss­ue can pose an adequacy and econo­mic problem. They will be assessed separately for positive and negative residual load ra­mps and for one-, three- and eight-hour ramps as well as the corresponding prior hours for potential pre-emptive curtailment. Currently, hourly values for LOLE, EENS and curtailed energy are among the outputs of chronological probabilistic market si­mulations used by adequacy and Ten-Year Network Development Plans (TYNDP) studies. With the necessary fine-tuning of this indicator, the 5 per cent threshold can be addressed and the ramping capabilities of all resources can be modelled in market simulations, especially for demand respon­se and VRE curtailment.

Scarcity period flexibility needs: These are metrics focused on contiguous-day EENS issues during scarcity periods, when VRE resources are not available for extended and continuous periods such as windless winter weeks in northern Europe. This me­t­ric can indicate small sets of hours in a given year when flexibility is particularly ch­­­a­llenging. Meanwhile, market simulatio­ns can show quantified reliability risks fr­om detailed simulations of despatchable ca­pacity, demand response, battery use, and mutual support between countries, as well as weather and outage probabilities.

As in the case of ramping, LOLE and EENS percentages over the maximum 120-hour average residual load periods in­­dicate the fraction of overall adequacy concerns that arise due to seasonal sc­arcities involving extended periods of high residual load and low VRE generation. For further interpretation of scarcity periods, it may be useful to examine the climate years with high LOLE and EENS contributions during the identified 120-hour scarcity periods in market simulations, as well as the average generation as a percentage of the installed capa­ci­ties of all VRE resources during these periods. This will help understand which cli­matic conditions can lead to scarcity periods.

The necessary fine-tuning of this indicator will not only address the focus on the single worst five-day period, but also involve ex­amining how the availabilities of flexibility resources during scarcity periods are modelled in market simulations, especially implicit demand response and sector coupling resources such as vehicle-to-grid (V2G), or seasonal thermal or hydrogen storage.

Sector coupling and flexibility: Sector coupling can be an important source of flexibility in the energy system, ranging from energy storage technologies to demand response solutions. Sector coupling refers to the integration of energy consuming sectors – buildings (heating and cooling), transport and industry – with the power generation sector. It pr­ovides op­tions to absorb excess electricity supply from renewable energy sources, to store energy and provide backup supply in times of high demand and prices.

Sector coupling solutions such as power-to-heat with thermal storage and ele­c­trolys­ers using clean electricity combin­ed with gas storage seem relevant for mitigating sc­arcity period flexibilities, es­pecially for countries with high VRE shares. Mean­whi­le, power-to-gas, smart electrolysers, V2G and smart EV charging are solutions that of­f­er fast response fl­exibility and ramping flexibility – both before and during the st­eep evening ramp of the residual load.

Hydrogen-based sector coupling is also gaining traction and there is a growing in­terest in using hydrogen as a long-duration energy storage resource in a future el­ectric grid dominated by renewable energy generation. Recently, Denmark’s TSO En­erginet and pump producer Danfoss entered into an innovation collaboration to examine whether a plant that converts el­e­c­tricity into hydrogen can be used to help balance the power grid. The collabo­ra­tion is part of Energinet’s Open Door Lab, which examines how to enable more fl­exibility in the power grid.

Sector coupling as well as other flexibilities such as batteries and DSR involve load that is connected at the distribution level, implying that their usage for the ov­er­all system requires close cooperation between TSOs and distribution system op­­e­rators (DSOs). ENTSO-E suggests that to promote this cooperation between TSOs and DSOs, a joint assessment of flexibility needs should be developed for different use cases at the transmission and distribution level.

Challenges and the way forward

The introduction of flexibility in the power system on a wide scale is undoubtedly a co­mplex and significant challenge and he­nce the position paper is a step in the right direction. ENTSO-E is further planning to develop several additional flexibility need assessment methods related to st­able frequency, congestion mana­gem­e­nt, voltage stability and uncertain variati­ons or forecast errors after the day-ahead frames along with associated metrics in the coming years. Once developed, ENTSO-E may directly apply or recomme­nd to its member TSOs a fine-tuning and application of these methods, metrics and indicators on a national, regional and/or pan-European level.

With proper planning and execution, Euro­pe’s power system can certainly provide safe and quality power even in the face of an unprecedented energy transition.

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