UK Power Networks installs Lithium-ion battery storage system on a distribution network.
Energy storage is becoming increasingly important as electricity networks evolve into smarter systems that integrate power generated from intermittent renewable sources, such as wind and solar, and supply to emerging new loads, such as electric vehicles and heat pumps. The scene is set for a significant increase in the number of storage installations worldwide in the near future. So far, established storage technologies have included the use of pumped storage, and lead-acid and nickel-based batteries. The next generation of grid storage technologies is now being trialed in a number of pilot projects with Lithium-ion batteries, flow batteries and flywheel storage installations.
As a result of the European Union (EU) directive in 2009, the UK government has agreed to an overall target of generating 15% of the energy supply from renewable energy sources by 2020. UK Power Networks, which owns three networks distributing electricity to a quarter of the UK's population, has invested £1.8 million (US$2.9 million) in developing a site and energy storage technology in partnership with the global engineering company ABB.
At the site in Hemsby, near Great Yarmouth, UK Power Networks has commissioned a pilot project where Lithium-ion batteries store energy generated by the locally sited wind turbines when the power generation exceeds the demand on the distribution network. One possible objective of this pilot installation is to regulate the variable nature of the energy generated by the wind turbines. The storage device can provide more than this single service, with a range of voltage control and power-flow management capabilities ready for implementation, to benefit the operator and users of the network.
Pilot Project Network
UK Power Networks' pilot project formed part of the Engineering and Physical Sciences Research Council (EPSRC)-funded Autonomous Regional Active Network Management System (AuRA-NMS) project undertaken in collaboration with ABB, Scottish Power Energy Networks and six universities. UK Power Networks wanted to investigate whether the benefits derived from the energy storage system (ESS) that were predicted actually could be realized. Hence, the site was selected such that the maximum number of benefits could be evaluated from a single installation.
A rural 11-kV distribution network in North Norfolk was chosen with 2.25-MW wind generation connected to it. The ESS was installed at a normal open point between two existing 33/11-kV primary substations. Installing the ESS in an existing primary substation would have removed any benefit to the 11-kV feeders, also limiting the benefits to the 33/11-kV transformers and 33-kV circuits supplying the primary substation.
Durham University has undertaken a series of modeling and simulation studies to evaluate the most effective way to operate the ESS on a distribution network. The simulations were designed to improve multiple concurrent network performance metrics while ensuring no negative impacts are experienced in comparison to normal operation of the 11-kV network. The capacity of the ESS installed was determined by the cost that could be reasonably justified as a proof-of-concept project.
ABB's DynaPeaQ (formerly known as SVC Light with Energy Storage) is an innovative technology that converts energy into a form where it can be stored in batteries. It uses a fast pulse-width-modulation-controlled insulated gate bipolar transistor (IGBT)-based converter for tasks such as flicker mitigation and active filtering. The system provides fast-acting reactive power compensation in high-voltage electricity networks.
This new technology enables dynamic control of power in the distribution network, improving grid voltage and stability, leveling out power fluctuations in the case of energy generated from renewable resources. The rated power and storage capacity is typically about 20 MW for approximately 15 minutes to 45 minutes, but the technology can be scaled up to 50 MW for 60 minutes and longer.
The ESS was designed and built as a turnkey project by ABB. It is an enhancement to ABB's established SVC Light product. The Lithium-ion batteries, manufactured by Saft for this project, are configured as eight stacks of battery modules housed in a 25-sq m (269-sq ft) modular substation building. The total installation is capable of storing up to 200 kWh of electrical energy, which is sufficient power to keep 200 houses supplied for an hour. The modules are continually charged and discharged, and the design could be scaled up to store more energy in the future.
Lithium-ion battery technology was selected for a calendar lifetime of 15 years charge/discharge of 3,000 cycles, more than adequate for the five-year operational life of this project, with 80% depth of discharge and high round-trip efficiency on the order of 90%. Safety and protection is ensured by interlocking, supervision and control from cell to system level.
In common with most UK 11-kV distribution networks, instrumentation is limited to current and voltage analog measurements at the primary substation. Therefore, to receive maximum benefit from this project, relays were installed at strategic locations on existing equipment at 11-kV substations on the network. The relays increase the visibility of the network state for two functions:
To provide inputs to the control algorithm used to govern the ESS operations
To understand changes in power flows and voltages across the network due to ESS operation.
The relays transmit their measurements over a general packet radio service (GPRS) network to a substation computer at the primary substation. This data is archived for later analysis, and the key measurements are used by the control algorithm hosted on the substation computer to determine ESS setpoints.
ABB's MACH2 control system manages the ESS plant. Interaction with the wider electrical network is implemented through ABB's COM600 substation computer at the primary substation. Measurements are processed by IEC 61850-compliant REF615 relays.
The ESS plant is able to operate in an automatic mode where the MACH2 control system uses local voltage measurements to determine the required injection of reactive power to stabilize the voltage at the ESS. To make control decisions, a wider range of measurements taken from across the network is collected and processed by algorithms on the computer. These decisions are then issued as ESS setpoints for real and reactive power settings. Algorithms that were developed to deliver a series of objectives in the planning phase simulations are now being used during the operational phase of this project.
Energy Storage Deployment
The first deployment of an ESS on a UK electricity distribution network brings with it considerable challenges in the approval of this new technology for connection to an operational network. Primary among the challenges is the use of power electronic devices, as flexible AC transmission systems (FACTS) are uncommon on UK distribution networks. Operational staff members are more familiar and experienced with passive equipment such as transformers, cables and so forth, all of which have predictable performance characteristics.
In contrast, the voltage source converter uses IGBT valves to control the power flow to and from the ESS, and can maintain the point-of-common-coupling voltage at a particular level throughout a range of real-power import or export conditions. Therefore, new modeling methods have been developed to predict the behavior of the ESS using time as an important variable.
It also is essential for staff to understand how the control system operates to ensure customers continue to receive a safe and reliable electricity supply with the ESS installed. When a fault occurs on the distribution network that requires the ESS to trip, the control system quickly disconnects the device from the network. It monitors the network and blocks the IGBT valves after a few milliseconds to prevent the ESS from supplying energy in an island mode. There is a redundant computer ready to seamlessly take over control should the computer controlling the system fail. In the event of the second computer failing, there is backup protection that disconnects the ESS from the network.
The ESS was commissioned in March 2011. The monitoring and evaluation phase of the project — conducted by Durham University, which was responsible for the modeling and simulation studies — is now ongoing. Funding for this work has been secured from the Great Britain regulator Ofgem's Low Carbon Network Fund Scheme.
The deployment of energy storage onto electricity distribution networks is a new and potentially difficult proposition for distribution network operators. This is the first time an electrical energy storage device using Lithium-ion batteries has been installed on an 11-kV distribution network in the UK. Its performance is now being monitored by experts from Durham University and, if this project proves successful, the design could be replicated and scaled up for future applications throughout the UK.
The authors wish to thank Peter Jones (ABB-UK) and Tomas Larsson (ABB-Sweden) for their support and help in the preparation of this article.
Peter Lang (firstname.lastname@example.org) holds a bachelor's degree in electrical engineering from Southampton University, is a chartered engineer and a member of the Institution of Engineering and Technology in the UK. He has worked for UK Power Networks and its predecessor companies for 21 years. He currently leads the network design and operational practices workstream in UKPN's Low Carbon London project. He has represented UK Power Networks on a number of European Commission-funded projects such as ADDRESS, FENIX and HiPerDNO.
Neal Wade (email@example.com) holds a bachelor's degree in engineering and a doctorate degree in physics, and is a member of the Institution of Engineering and Technology and a member of the IEEE. As a lecturer at Durham University, he is studying and contributing to the changes beginning to take place across distribution networks that will enable the transition to a low carbon future. He has developed modeling and simulation software that is being used to assess the benefits gained by stakeholders from the addition of energy storage systems to electricity networks.
Phil Taylor (firstname.lastname@example.org) holds a bachelor's and doctorate degree in engineering, and is a chartered engineer in the UK, a senior member of the IEEE, a fellow of the Institution of Engineering and Technology, and a fellow of the Higher Education Academy. His research focuses on the challenges associated with the widespread integration and control of distributed generation in electrical distribution networks. He has significant industrial experience as an electrical engineer, including a period working in the transmission and distribution projects team at GEC Alsthom. He is the deputy director of the Durham Energy Institute and the director of the Multi-Disciplinary Centre for Doctoral Training in Energy.
Durham University www.dur.ac.uk
Scottish Power Energy Networks www.scottishpower.com/EnergyNetworks.htm
UK Power Networks www.ukpowernetworks.co.uk