Power Responsive success stories: South Mimms battery storage and EV charging

At South Mimms Motorway Services, Open Energi own and operate a 250kW/500kWh Powerpack alongside one of Tesla’s largest and busiest UK charging locations. The project, which is one of the first of its kind globally, was selected as a demand side flexibility success story and showcased by National Grid at their 2018 Power Responsive summer reception.

The Supercharger site can charge up to 12 cars at one time, and since popular charging periods often coincide with peak periods of grid demand – between 4pm and 7pm, when electricity prices are at their highest – flexible solutions are needed to ease the strain on local grids and control electricity costs.

Integrating a Powerpack at the location has meant that during peak periods, vehicles can charge from Powerpack instead of drawing power from the grid. Throughout the remainder of the day, the Powerpack system charges from and discharges to the grid, providing a Firm Frequency Response (FFR) service to National Grid and earning revenue for balancing grid electricity supply and demand on a second-by-second basis.

Combining batteries and electric vehicles makes vehicle charging part of the solution to integrating more renewables without affecting drivers, unlocking vital flexibility to help build a smarter, more sustainable system.

Robyn Lucas, Head of Data Science at Open Energi explained “[the battery] provides a source of flexibility to what is otherwise a very inflexible demand. We do frequency response for most of the time, and over the peak period we use the battery to charge the car up, rather than them charging from the grid.

“Open Energi hope to repeat this blueprint with multiple other stationary storage assets next to EV charging stations. Having stationary storage assets used in this way allows both transport and electricity networks to be decarbonised and allows for greater renewable penetration.”

2017 in review: breakthrough tech and tumbling renewable records demand greater flexibility

2017 was a year of dramatic change in the UK electricity market. Overall, total UK electricity consumption fell 2.8% compared to the previous year: 264 TWh compared to 272 TWh in 2016[1]. This follows the long-term trend of decreasing peak and total yearly energy use, while the proportion of renewable generation continued to rise: 2017 smashed 13 clean energy records, low carbon generation exceeded fossil fuels, and the resulting trend for negative prices (as recent as last week in Germany thanks to high wind) looks set to continue.

Last year also saw a fall in the strike price for new offshore wind power to £57.50/MWh. Considering the government’s guaranteed price for Hinkley Point C is £92.50/MWh, it highlights just how competitive renewables, and particularly offshore wind, now are. However, the system must be able to cope with the intermittency that all this cheap, carbon-free power brings.

Figure 1 shows the huge variation in demand over the year: from peaks of nearly 50GW on winter evenings, to troughs of around 17GW on summer nights. Figure 2 shows the average daily profile of consumption. In 2017, the prize for peak demand goes to January 26th, which came in at 49.76 GW at 6pm. Compare this to the profile of June 11th, the day that the UK used the least energy: at 5am, it was 16.57 GW. This swing of over 30 GW presents many challenges for the system operator as more and more of the generation becomes intermittent and demand patterns shift: there is value in being flexible with one’s electricity consumption.

 

Figure 1. Daily demand over the year, and smoothed trend over the year.
Figure 1. Daily demand over the year, and smoothed trend over the year.

 

Figure 2. Peak and lowest demand of 2017, compared to the average daily profile.
Figure 2. Peak and lowest demand of 2017, compared to the average daily profile.

Historically, our electricity system has been built to cope with the peaks; and paying for this network accounts for around 30% of your electricity bill (and rising). What if, by being a bit smarter about when we use our electricity, we could flatten the swing out a little? Or better still, align it to renewable generation?

This is where demand flexibility comes in, empowering consumers and playing a vital role in providing the responsiveness needed to cope with huge swings in renewable generation as it makes up more and more of the UK’s generation mix.

Transforming the network

2017 will be known as the break-through year of batteries and electric vehicles (EVs). With the dramatic fall in battery prices we’ve seen a rush of parties buying up battery capacity, hoping to profit from what were lucrative flexibility markets. National Grid have seen batteries flooding into the Firm Frequency Response (FFR) market, attempting to secure profitable long-term contracts to satisfy investors. Market dynamics mean this is increasingly challenging. In a rapidly changing marketplace, a variety of revenue streams must be considered. Battery operation must encapsulate multiple markets to insure against future movements and maximise profits, while ensuring safe and careful operation of the asset such that state of charge, warranty, and connection limits are respected, an area where Open Energi has significant expertise.

EV take-up is accelerating more quickly than many estimated – UK sales of EVs and plug-in hybrids were up 27% in 2017 – and the need for managing this additional demand in a smart, automated way is crucial to alleviate strain on local networks. We have explored the enormous potential of EVs to provide flexible grid capacity and are working with a consortium to deliver the UK’s first domestic V2G trial.

While in the short term, as the big electricity players try to keep up with the changing needs of the system, flexibility markets present a degree of uncertainty, the long term need for demand-side response (DSR) and frequency regulation cannot be underestimated.

Grid Frequency and FFR

As the System Operator, National Grid must maintain a stable grid frequency of 50Hz. Generation and demand on the system must be balanced on a second-by-second basis to ensure power suppliers are maintained. Traditional thermal plant operates with physically rotating turbines, which carry physical inertia and act to stabilise the frequency. With the increase in generation from non-inertial sources (e.g. wind turbines, which don’t carry inertia in the same way, and PV cells), this stability is reduced. Larger deviations in frequency can result in the event of a power station, or interconnector trip, for example.

During 2017, the largest low frequency event (demand greater than supply) occurred on 13th July, when it dropped to 49.57Hz. Given that National Grid’s mandate is to keep it within 0.5Hz of 50Hz, this was rather close! Figure 3 shows the period, and we see a sudden drop in frequency which typically indicates the trip of a significant generator. In this case, the fault was at the French interconnector. Here, what usually functions to improve energy continuity and smoothen geographical variations in supply was the culprit for the biggest second-by-second imbalance in 2017!

The largest high frequency event (supply greater than demand), during which frequency reached 50.41Hz, occurred at the end of October, was much more gradual and seems to have been due to a combination of several effects. Demand typically drops quite steeply this late in the day, so large CCGT plants are reducing their output and on this occasion a sudden drop in wind-generation seemed to have been over-compensated by pumped storage.

Figure 3. Lowest and Highest frequency extremes in 2017.
Figure 3. Lowest and Highest frequency extremes in 2017.

As well as these relatively rare large frequency events, there are excursions that can last for several hours. Figure 4 shows two periods where the frequency deviated from 50 Hz. In general, the average frequency is 50Hz, and therefore any response to frequency regulation averages out to zero. However, over these medium-term time periods the average frequency is not 50Hz. For flexible assets like batteries, that are dynamically responding to correct grid frequency during such periods (performing FFR) the state of charge is affected.

For this reason, the state of charge of the battery must be actively, and automatically, managed – so that optimal state of charge is quickly recovered after such events. The battery is then able to continue to perform FFR, or other services such as peak price avoidance or price arbitrage in wholesale markets. The state of charge (bottom panels in Figure 4) can also have strict warranty limits set by the manufacturer.

Figure 4: Extended frequency events and impact on battery state of charge
Figure 4: Extended frequency events and impact on battery state of charge

Interestingly, 2017 saw an increase in both the number of frequency events (usually defined as frequency excursions larger than 0.2Hz away from 50Hz), and frequency mileage (defined as the cumulative deviation of the grid frequency away from 50 Hz), shown in Figure 5, particularly during the spring and autumn.

Could this be due to the large, somewhat unknown amount of PV on the system? It is distributed, meaning National Grid see PV generation as a fall in demand; they also have no control over it (unlike most other generation). PV efficiency is high in cold weather, so perhaps unexpectedly high and erratic solar generation on cold, sunny days in the Spring and Autumn led to a more unstable system this year, compared to 2016.

Figure 5. The grid has experienced more mileage and more events in 2016 than 2017, especially in March and October. Frequency “event” here is defined as a deviation of 0.1 Hz around 50Hz.
Figure 5. The grid has experienced more mileage and more events in 2016 than 2017, especially in March and October. Frequency “event” here is defined as a deviation of 0.1 Hz around 50Hz.

Figure 5. The grid has experienced more mileage and more events in 2016 than 2017, especially in March and October. Frequency “event” here is defined as a deviation of 0.1 Hz around 50Hz.

The rise of distributed generation, accelerating EV uptake, and plunging battery storage costs, are all driving a rapid transformation in the UK’s electricity system.  Managing these changes requires new approaches.  Demand-side response technologies, like Open Energi’s Dynamic Demand 2.0 platform, mean patterns of demand can be shifted in a completely carbon neutral way; enabling electricity to be consumed when it’s being generated: as the wind blows, or the sun shines. Rather than inefficiently changing the output of a gas fired power station to meet demand, we can make smart changes in demand up and down the country to meet generation, deliver local flexibility, and put consumers in control of their energy bills: delivering completely invisible, completely automated, intelligent DSR which paves the way for a more sustainable energy future.

By Wouter Kimman, Data Scientist, Open Energi

[1] For demand here and throughout this post we use INDO values as reported by ELEXON Ltd.

Faster Frequency Response: A Cost-effective Solution to Future System Balancing

open energi wind farm

Creating a sustainable energy future will take decades and the pace of technological development will lead to ideas and solutions that no one has even thought of yet. This innovation will come from the next generation of energy leaders, who are already conducting vital research at universities across the globe.

 Over the last year, we’re delighted to have been supporting Yifu Ding, who is studying for an MSc in Sustainable Energy Futures at Imperial College. Yifu has been assessing the value of faster frequency response times in power systems, and Open Energi’s Dagoberto Cedillos has been one of her supervisors. Yifu’s project was recognized as the Best MSc Research Project in the cohort, and we’re pleased to share a post from Yifu about her work.
Y_Ding_Headshot

What is System Inertia?

In a stable power system operating with a fixed nominal frequency (50 Hz in the UK) electricity supplies must closely match loads on a continuous, second-by-second basis. This is especially difficult during some special cases such as the power pick-ups after big football games or a royal wedding.

Undoubtedly, achieving such a real-time balance is not a simple thing, but there are many approaches. Large power systems have an inherent property which provides the quickest response for contingencies. In a conventional power plant like coal, gas and even nuclear, electricity is generated by a turbine, basically a large spinning mass of metal. The inertia stored in these rotating turbines provides an energy store which automatically stabilises the system and insulates it from sudden shocks. In an event of a generation outage or surge in demand, inertial energy is released which prevents the frequency from falling. Equally the inverse happens in the case of a sharp increase in electricity supply or decrease in demand.

After that, the system operator begins to manipulate power assets through an array of automated measures already in place (like different frequency response products) and by sending out manual notifications. In response to these, large-scale power stations adjust their outputs. Hydroelectric reservoirs release or pump water. Aggregators control loads or battery assets they manage to provide a response.

Challenges for System Balancing

In light of the decarbonisation trend, great changes have been undertaken in the UK power system. Old methods relying on fossil-fueled power plants to balance the system are challenged and we need to explore new options.

As a rule of thumb, we are losing the system inertia. According to the National Grid System Operator Framework (SOF) 2016, approximately 70% of the UK system inertia is provided by thermal power plants. Unfortunately, the rapidly increasing volume of renewable generation units with power electronics interfaces, including solar PV and wind turbines, are not synchronized with the Grid. Therefore they don’t contribute to the system inertia.

Fig1a synchronous coupling

Figure 1: Generators contributing (or not) to the system inertia (From National Grid SOF 2016)
Figure 1: Generators contributing (or not) to the system inertia (From National Grid SOF 2016)

In our research, we considered ‘Gone Green’ and ‘Steady State’ scenarios from National Grid Future Energy Scenarios (FES) 2017, to compare and contrast what could happen in the near-term future. We found out that the inertia of the UK system will fall from 198 GVAs in 2015 to 132 -155 GVAs by 2025, as large numbers of thermal power plants are closed to meet carbon reduction targets.

Figure 2: The future scenarios considered in this research according to National Grid FES 2017
Figure 2: The future scenarios considered in this research according to National Grid FES 2017

Why Faster Frequency Response?

From this point of view, our power system will become more ‘erratic’ than before due to lack of this self-stabilization property. To counter this we could use more Frequency Response (FR) services, or perhaps something else?

We can envisage a power system with a stable frequency as a large tank with a stable level of water. The current inlet and outlet represent the generation and demand respectively. If a sudden imbalance occurs between inlet and outlet, we need to respond quickly in case the water level becomes too low or overflows.

In this fashion, one of the effective solutions is delivering faster-acting response. In July 2016, National Grid launched and tendered a sub-second FR service called Enhanced Frequency Response (EFR). Currently it is provided by batteries which can respond fast enough to provide a similar level of security to the inertial response from conventional power generators.

Value of Enhanced Frequency Responses

A few statistics from our research and other documents give you an idea of the exact economic benefit from delivering this new FR service.

By developing an optimization mathematical model to simulate power generation, dispatch and balancing in a row, we estimated the economic benefits of EFR will reach £564 to £992 per kW by 2020. National Grid has already contracted 201 MW of EFR, therefore the total economic benefit is estimated to be up to £200 million. This result conforms to the estimation published by National Grid on 26 Aug 2016.

Figure 3: A screenshot of the daily power generation and dispatch outcomes from the optimization model.
Figure 3: A screenshot of the daily power generation and dispatch outcomes from the optimization model.

But this isn’t the whole story. Although the fast-acting FR service demonstrates many advantages, there are still obstacles when it comes to the implementation.  For the system operator, an issue which might arise is how to determine the optimal mix of those FR products. Otherwise some of them could be undersubscribed or oversubscribed as mentioned in System Needs and Product Strategy (SNAP) report from National Grid.

Stakeholders in the balancing markets, such as electricity storage operators, can make themselves invaluable by providing such a service. However, we should note that it is designed to be fulfilled continuously, meaning it’s unlikely to be delivered in combination with other network services. In this case, the operator can only obtain the single revenue from the asset, risky from an investor perspective. Providing such a service is technically challenging since it requires a sophisticated state of charge (SoC) control to meet the service specifications and manage battery throughput.

As we look into the future balancing markets, fast-acting FR services indeed provide a cost-effective solution towards the low-carbon power system. Planned streamlining of  procurement mechanisms and ongoing technology development will help to fully unlock its potential.

 

Making a success of batteries

Tech image

The surge in interest in battery storage projects has highlighted a fundamental change in the energy market, as commercially viable systems become progressively more available. We explore critical success factors, from choosing the right battery to managing state of charge.

The deployment of physical energy storage assets can broadly be separated into two project categories. The first kind of project consists of grid-scale assets in “front of the meter”, which are usually implemented by industry partners on large grid connections. The second type is “behind the meter” batteries which provide an added layer of flexibility to energy consumption patterns of sites already connected to the electricity network – and offer tremendous potential to unlock previously inaccessible revenue streams for industrial and commercial customers.

Both project types require different approaches to select the best battery type and optimise operational strategy and performance over time.

Selecting the optimal battery operating strategy

Battery flexibility has the ability to unlock several non-mutually exclusive revenue streams. For example, a battery can be used to reduce site demand (for “behind the meter” projects), or export to Grid (for “front of the meter” opportunities) during peak price periods, reducing costs associated with wholesale, Duos, Triads and Capacity Market levy charges. Outside periods of peak tariffs, batteries can participate in the frequency response market and earn a revenue from National Grid for helping to dynamically balance electricity supply and demand.

The characteristics of Battery Energy Storage Systems (BESS) differ widely between manufacturers, with important factors to consider including capital and operating costs, power rating, energy storage capacity, energy density, cell chemistry, operating temperature, round-trip efficiency, self-discharge, degradation profile and tolerance to various depth of discharge. All these parameters have an influence on the economic viability of the project, so it is important to select the appropriate technical solution for a given project.

Once the different parameters are known, the determination of the most economical operating strategy becomes an optimisation problem in response to an aggregated electricity price signal and a potential frequency response revenue, under several constraints such as the battery technical characteristics and the site operational constraints (existing demand/generation on site if any, and import and export capacity).

The operating strategy might change over time, for example because one component of the price signal has changed, or if there is a new opportunity for flexibility that is more financially viable than current revenue streams. In that case the optimisation process will be performed again and the operating strategy modified accordingly.

Battery State of Charge profile
State of charge profile of a BESS doing peak price avoidance from 4PM to 7PM and participating in the frequency response market the rest of the time. The energy stored in the system is maximised before 4PM in order to optimise arbitrage revenues.

Choosing the right battery

The next crucial decision is choosing a battery that is optimal for a given project and operating strategy. The goal here is to select the battery that will be commercially viable under the constraints of a given project. For a “front of the meter” BESS the main factors driving the battery characteristics are the Authorised Supply Capacity (ASC) for importing and exporting, the capital and operational costs and the electricity tariffs for import and export.

There are additional parameters for a “behind the meter” battery. As most of these projects are implemented in sites with no or a small export capacity, the battery would respond to a low frequency event by discharging power into the site, reducing its overall energy consumption. It is therefore crucial to forecast the demand on site to choose the optimal battery size and tender an accurate power availability in the frequency response market.

The same approach can be used for generating sites (like wind or solar farms) where there must be sufficient potential for export in addition to the generating activity on site. The potential energy savings are also dependent on the demand and the site constraints, which might in return drive the optimal power/energy ratio of the BESS.

Managing battery state of charge and maintaining performance

Once installed, the challenge is to manage batteries while ensuring high performance following the operating strategy selected. A requirement of entering the frequency response market is to be able to provide the power tendered for 30 minutes at a time, which highlights the need for a performant state of charge management.

There is an inherent efficiency in BESS, with average efficiency ranging from 75% to 90 % for conventional systems. When used in the frequency response market, successive cycles of charge and discharge will progressively cause a net discharge of the battery, and ultimately cause the battery to be fully discharged if no corrective actions are taken. Similarly, if several large high frequency events happen in close succession, a frequency-responsive BESS might reach a high state of charge at which it will not be able to respond to high frequency events anymore.

Battery charge management graph
State of charge of a 1MW/2MW.h frequency responsive battery. An appropriate state of charge management helps keep the energy stored in the battery at an optimal level over time.

A control strategy should ensure that the battery state of charge always stays within appropriate boundaries in order to meet its contracted obligations at any given point in time. It should also ensure that the total throughput of the battery (which is the cumulative sum of discharge processes over time) is minimised while in operation. A reduced throughput decreases the wear and tear of the battery, enhancing the BESS lifetime.

At Open Energi we are working with several customers to successfully operate batteries in the frequency response market, optimising their operating profile to maximise revenues, applying designed state of charge management techniques, while limiting the degradation of the battery lifetime to the lowest value possible.

 

 

IoT technology meets UK’s energy grid needs faster than power stations

Aggregate Industries Moorcroft quarry

Research has found that Open Energ’s Dynamic Demand technology can meet the UK’s crucial grid balancing requirements faster than a conventional power station. The paper published as a result of ongoing collaborative research by Open Energi, National Grid and Cardiff University, titled Power System Frequency Response from the Control of Bitumen Tanks, looked at the feasibility of DSR providing a significant share of frequency balancing services.

Bitumen tanks (containing the glue that binds our roads together) equipped with Dynamic Demand were used in combination with National Grid’s model of the GB transmission system to investigate the capability of industrial heating loads to provide frequency response to the power system.

The conclusion is that Open Energi’s Dynamic Demand technology, deployed at scale, can contribute to grid frequency control in a manner similar to, and, crucially, faster than that provided by traditional peaking power generation. Field tests showed that full response could be provided in less than two seconds, as compared to 5 – 10 seconds for a thermal generator. Large scale deployment of Dynamic Demand will reduce the reliance on frequency-sensitive generators and ensure that the grid stays balanced in a cost-effective, sustainable and secure manner.

While a lot of focus has understandably been given to tight capacity margins between supply and demand, the real threat could come from generators being unable to respond within the required window to balance instantaneous shifts in supply and demand. With more renewables and decreased thermal generation, ‘inertia’ on the Grid will decrease, making frequency more unstable. Dynamic Demand can help to counteract this effect by providing faster response, helping to future proof the Grid.

The paper was published in the IEEE Transactions on Power Systems Journal. Download a copy here.