Building a new nuclear power station is a major undertaking. Because modern nuclear power plant are generally larger than old fossil fuel or nuclear facilities they replace, new reactors often require the construction of new or additional transmission infrastructure to link into the grid. Penny Hitchin looks at the challenges and how they’re being addressed.
High voltage ‘motorway’ transmission networks carry electrical power from generation plant to regional or local electricity distribution operators where the power is needed. Generally transmission system operators (TSOs) provide the infrastructure while the role of local distribution companies is to step the voltage down and supply the electricity to the market.
Determining the most appropriate route and technology for new transmission lines, the vital backbone for electricity supplies, is complex. Establishing the routes and building the new infrastructure can take every bit as much time as building the reactors. Technical, environmental, socio-economic and economic factors must be considered. The longer the transmission route, the greater the number of landowners, local residents and other stakeholders likely to be affected.
The 21st century shift to low carbon generation is seeing fundamental changes to transmission networks as countries move away from fossil fuelled generation built near to centres of demand to accommodate outlying sources of intermittent renewable energy. Inter-connectors are linking electricity supplies across borders, introducing additional flexibility and market liberalisation. In May 2014 the power grids and exchanges in southern and Northwestern Europe connected nearly three quarters of European customers
Building new nuclear power stations will also require major transmission developments. One consideration in adding nuclear capacity to the generation portfolio can be the size of their grid system as it is not desirable to have any generating unit contributing more than about one tenth the capacity of the grid, due to the implications when the plant has to be taken offline.
Developments in transmission technology
Transmission grids are normally alternating current (AC), which can readily be transformed to higher or lower voltages. Direct current (DC) links are increasingly used for undersea interconnector cables linking countries or offshore wind farms to onshore grids via converter stations. High-voltage DC links (HVDC) are becoming more important for efficient long-distance transmission.
During the transmission of electricity, some energy is ‘lost’ from the transmission system, usually in the form of heat. The US Energy Information Administration estimates that electricity transmission and distribution losses average about six per cent of the electricity that is transmitted and distributed annually in the US. Transmission loss percentages can be reduced by using higher voltages.
The easiest and cheapest way to move electricity from the source of generation into the network is through overhead lines consisting of the conductor, transmission tower and insulator. Transmissions towers must be sufficiently tall that the clearance between each conductor and the lowest conductor and the ground prevents electricity jumping across. The distance between transmission towers depends on tower height, conductor capacity, landscape topography and changes in direction. A typical distance between towers is 360 metres.
A standard steel lattice electricity transmission tower has been in use in the UK since 1928. A new award-winning single-pole T-Pylon design enters service this year. The Danish design uses a novel diamond ‘earring’ arrangement to carry the cables off one arm in a much smaller space than the three arm arrangement of the lattice transmission tower. The T shaped cross arms enable the overall height to be reduced from the 50 metres used by the lattice tower to 36-metres for the T-pylon. The modern design will also enable overhead cables to be better routed along the contours of the land instead of the more angular changes in direction of lattice towers. The T-pylon is being offered for the first time for the new transmission line for EDF Energy’s proposed nuclear station at Hinckley Point C in Somerset.
Six prototype T-pylons, manufactured in the UK, were trialed at a test centre in Nottinghamshire in 2015. The new design must be able to cope with all the stresses placed on a transmission tower. Complex analysis and physical loading tests were carried out to simulate climatic conditions such as winds of more than 80mph and ice loads. Investigations were made into the dynamic performance of the structure under simulated vibrations. The training line was used to demonstrate the five different types of T-pylon, each designed to perform different functions on the transmission network, and a second model of the standard suspension pylon for carrying cables in a straight line.
Environmentally sensitive or built-up areas can be problematic for transmission which is usually routed underground. Underground cable currently makes up about 10% of the existing transmission worldwide.
Installing underground cable is more expensive than overhead lines. It can be installed by direct burial or by tunnelling. Build costs depend on terrain, route length and power capacity. Direct burial is normally the cheapest method for the installation of underground cables where restrictions on land use are not an issue. However, it involves disruption to traffic, excessive noise, vibration, visual intrusion and dust generation. Direct burial involves excavating a trench around 1.5m wide and 1.2m deep for each single cable circuit. The cables are installed on a bed of sand and backfilled with cement bound sand to ensure thermal conductivity around the cables. Sheet piling or timber is used to support the sides of the trenches. Reinstatement of the excavated trench is then carried out using approved backfill material placed directly around the cables with protection covers placed above the cables in the excavation. Bays at intervals of 500-1,000m allow for the jointing of the individual sections of cable.
The underground conductor has to be bigger than its overhead counterpart to reduce its electrical resistance and the heat produced. Special insulation is needed to maintain the cable’s rating. However a study of the costs of new electricity transmission infrastructure by the Institute of Engineering and Technology (IET) found the cost of operation, maintenance and energy losses over the 40 plus year life of the connection are broadly the same for undergrounding and overhead lines.
Tunnel installation is used in urban areas where direct burial of cable would cause unacceptable disruption. Tunnelling has the advantage that underground services such as water and sewerage are unaffected and river or railway crossings can be made, however it is more expensive than direct burial.
Gas-insulated transmission lines (GIL) is a technology developed at Tokyo University in the 1960s. It consists of pipes that house conductors in highly insulative sulfur hexafluoride (SF6) gas. GILs are much less flexible than cables and not capable of accommodating a displacement of terrain. The technology has only been deployed on short, straight transmission lines. The longest is a 1km installation in Frankfurt Airport.
The technology could be one to watch for future development.
High voltage direct current transmission
Electric power is normally generated, transmitted and distributed as AC. For long distance transmission HVDC transmission may be more appropriate.
The capital costs of HVDC installations vary from project to project depending on factors including technology used and route length. Bulky and expensive DC converter stations must be installed at each end of the HVDC system where it links into AC infrastructure. Generally HVDC is more cost effective when installed over long distances. HVDC is used for subsea interconnectors and increasingly for far flung North Sea offshore wind farms.
Over 300GW of new HVDC transmission capacity is expected to be added to world grids by 2020. Much of this will be in China which is using HVDC to connect its western hydro sources to eastern coastal load centres.
Costs of different technologies
‘Electricity Transmission Costing Study’, a 2012 report by Parsons Brinkerhoff for the Institution of Engineering & Technology (IET) sets out to provide the best estimate of the relative costs of the various technologies currently available for high voltage network enhancement at significant power levels.
The study says no one technology is appropriate in every circumstance, thus financial cost cannot be used as the only factor in the choice of one technology over another in a given application. In general, costs per kilometre, for all technologies, tend to fall with increasing route length and rise with circuit capacity.
Overhead line (OHL) is the cheapest transmission technology for any given route length or circuit capacity, with the lifetime cost estimates varying between £2.2 million and £4.2 million per kilometre. However, OHL losses are the most sensitive to circuit loading.
Underground cable (UGC), direct buried, is the next cheapest technology, after overhead line, for any given route length or circuit capacity. It is the least expensive underground technology with the lifetime cost estimates varying between £10.2 million and £24.1 million per kilometre.
For options using a deep tunnel, the largest single cost element is invariably the tunnel itself, with costs per kilometre ranging from £12.9 million to £23.9 million, depending upon overall tunnel length.
Undergrounded gas insulated line (GIL) technology is generally estimated to be a higher cost ranging between £13.1 million and £16.2 million per kilometre. However GIL equipment has a higher rating than the comparable UGC.
A 75km high voltage direct current (HVDC) connection is more expensive than the equivalent overhead or direct buried transmission options. Estimated cost is between £13.4 million and £31.8 million per km. However, HVDC connections come into their own on longer distances where they are proportionally more efficient than short connections, with less transmission losses.
Putting in place transmission infrastructure for Hinckley Point C
Hinckley Point C could be the UK’s first new nuclear reactor since 1995. The project will consist of two 1.6GW European Pressurised Reactors (EPRs), adding 3.2GW to the grid.
Hinckley Point, on the Somerset coast, is the location for two earlier generation stations. The earliest was the twin 250MW Magnox reactor station, Hinckley Point A, which ceased generation in 2000 after 35 years of operation. Hinckley Point B was the UK’s first Advanced Gas-cooled Reactor (AGR) station which started generating in 1975 and is currently expected to operate until 2023. It has a capacity of 955MW which is served by the existing transmission capacity.
Getting transmission infrastructure in place for a large nuclear plant can be expected to take at least ten years, so applications must be submitted well in advance.
In the UK the national transmission network is owned and maintained by three regional transmission companies. The entire system is operated by National Grid Electricity Transmission (NGET) which is responsible for ensuring the stable and secure operation of the whole transmission system. Power generators who want to connect to the transmission network must apply to National Grid for a connection and will be offered a date by which the connection will be available
Work on preparing the transmission infrastructure for Hinckley Point C started in 2007 when British Energy, who owned and operated Hinckley Point B, applied to National Grid for a future 3600MW grid connection for the site. At this stage a change in government policy on nuclear power was under discussion and it was widely believed that new nuclear would soon be given the go ahead. In January 2008 the UK government took a policy decision which effectively gave the go-ahead for a new generation of nuclear power stations to be built. Later that year EDF Energy acquired the Hinkley Point B site from British Energy. In March 2009 EDF nominated Hinkley Point as a site to build a twin unit EPR nuclear power station.
The last nuclear power station to be built in the UK, Sizewell B, was the subject of a lengthy and wide-ranging site-specific public planning inquiry. It started in 1982, took over 16 million words of evidence and it was not until 1987 that the project was approved. The honours for the longest planning inquiry go to Heathrow’s Terminal 5. This inquiry cost £80 million, generated 100,000 pages of transcripts and took eight years from first application to government approval in 2001.
The Planning Act 2008 process was introduced to streamline the decision-making process for nationally significant infrastructure projects. It substantially reduces the time taken to obtain consent to major projects in the fields of energy, transport, water, waste and wastewater. New transmission lines of at least 132kv and 2km in length and onshore power stations of greater than 50MW are subject to this planning regime.
Before applying for planning consent, the developer – in this case National Grid – must develop detailed plans and carry out extensive consultation on the proposal. Preparatory work on the Hinckley Point C Connection Project started in 2009 and ran through to 2014. During this time National Grid looked at all possible options including subsea and underground cables and concluded a new 56km connection between Bridgwater and Seabank substation was the best option.
Engagement and consultation are keys to identifying route
The TSO then consulted for 22 weeks on two route corridors – broad bands of land where the connection could be built. Statutory consultees included local government and environmental organisations. Local landowners, residents and others were also consulted.
Following consultation, a preferred route corridor emerged. National Grid said the connection would be mainly overhead line but underground cable would be considered where it was justified. At that stage detailed technical and environmental studies began. A preferred route was identified and consultation on this followed. The route included an 8km section of underground cable through an Area of Outstanding Natural Beauty and the use of the new low height T-pylons.
In spring 2014 the plan was submitted to the Planning Inspectorate for examination and decision. After a three-month ‘pre- examination’ period, The Planning Inspectorate has six months to carry out the examination. During this stage people who have registered to comment are invited to provide more details of their views in writing. The Planning Inspectorate must prepare a report on the application to the Secretary of State, including a recommendation, within three months of the six-month examination period. The Secretary of State will make the decision on whether to grant or refuse development consent within a further three months.
In January 2016 the project was approved. Construction will take around six years. The investment decision to build the nuclear plant has not yet been taken, so construction of the transmission infrastructure will not start this year. In the meantime National Grid is continuing with ground investigations and other activity in areas along the route.
National Grid says that introducing the new T-pylon means there will be 105 fewer transmission towers. Despite extensive consultation, the decisions about the transmission route have been greeted with local dismay. Those opposing the towers argue the entire route should be underground or subsea, regardless of the additional costs.
North West Coastal Connection
The National Grid’s UK NorthWest Coastal Connection (NWCC) is a multi billion pound project to build new transmission infrastructure to provide grid connection to link the proposed 3.4GW new nuclear power station at Moorside, Sellafield with the north- south transmission spine which lies over 50km to the east.
Balancing technological, economic and environmental factors to establish a route for the connection is a challenge as the Irish Sea lies to the west and the Lake District National Park to the east. An offshore cable route would have to pick its way round a Ministry of Defence live firing range and existing offshore wind farms, oil and gas pipelines and cables. The narrow coastal strip means there is a shortage of suitable land area for cables to come onshore to connect to the existing network. The onshore route is subject to Holford Rules which state that routeing through major areas of highest amenity value should be avoided even if this increases total mileage.
National Grid’s work on identifying the route started in 2009 after it received the application for the grid connection. Preliminary engagement with local organisations took place before the TSO set out alternatives for a public consultation in 2012. Two strategic options – one entirely onshore and one involving offshore cable – were taken forward. Work then focused on studying different locations, technologies and designs and appraising them against a range of environmental, socio-economic, technical and cost factors to identify route corridors for the new connection.
By autumn 2014 the options had been refined into four route corridors. National Grid’s ’emerging preference’ was for an onshore route following the path of existing distribution transmission lines combined with a 22km tunnel 35m below the shallow, sandy Morecambe Bay. A 12-week public consultation followed.
The TSO is currently working to find the exact line the new connection will take within its chosen route corridor. Further consultation will follow. The application for planning consent is expected to be submitted in 2017. Construction could start in 2019, ten years after the grid connection was awarded in 2009.
The 2014 consultation documents included cost estimates for the different technologies. Estimates for an overhead cable on the NWCC project are between £2.52 million and £3.02 million per kilometre. The unit cost for underground cable is between £13-32 million per kilometre based on a double circuit while the unit cost for HVDC is £2 million per kilometre plus up to £33 million per pair of converter stations. The cost of the tunnel could be up to £3 billion.
Putting in place transmission infrastructure for new nuclear power stations is often a complex process. While every project has considerable technical challenges, getting agreement and approval for a route requires a patient and iterative process of engagement and consultation. Achieving a balance between socio-economic, environmental, economic and technical aspects is unlikely
to satisfy all stakeholders, but there is no argument but that transmission upgrades are essential to keep the lights on.
More information on the Electricity Transmission Costing Study can be found at www.theiet.org/factfiles/transmission-report.cfm