Results: Searching for 'Technology'

This document provides a road map for Photovoltaics (PV) research in the UK. It covers PV materials, cell and module design and manufacture and applications including BOS components. It is specific to the UK and reflects the strengths and weaknesses of the research base in the UK, although it is compatible with the roadmaps of other countries, particularly the one recently developed for the European Community. Its primary aim is to identify priority areas for UK PV research and assist the research funding agencies, particularly EPSRC, DTI and the Carbon Trust, in developing their research programmes, but it also considers the need to develop UK capacity, both in terms of expertise and research facilities.

Research cannot take place in a commercial vacuum, and although not its primary function, the road map will outline the context for PV research in the UK. The potential for market growth in the UK and more widely is outlined and the need for market stimulation in the UK discussed.

The road map reflects the outcomes of a two day PV road mapping exercise, organised by the UKERC Meeting Place, that took place in Edinburgh in July 2006, together with inputs from a number of the attendees over the following weeks and subsequently contributions from the wider researcher community in response to an initial draft. The road map has also been subject to international peer review, and we indebted to these reviewers for their input.

The role of the UK Energy Research Centre Marine Energy Research Network in developing a route map for marine renewable energy research is described and put into the context of previous and current marine energy research at a national and EU level. A summary of the route mapping process is given based upon the Batelle approach. Justification is provided for route mapping in terms of encouraging cooperation and collaboration within the community to develop a coherent reseach, development and demonstration strategy, which will be used to inform policy makers and funding bodies. Some preliminary outputs from the network are presented in the paper to encourage discussion.

• Energy System Analysis –the importance of CCS
• UK Power System –the value of CCS
• CCS in the UK –some recent history and development of the ETI’s current programme
• Addressing the credibility of the cost base: the ETI’s Thermal Power with CCS - Generic Business Case Project
• Conclusions and next steps

This report, commissioned by the Aldersgate Group and co-authored with Vivid Economics, identifies out how the government can achieve a net zero target cost-effectively, in a way that enables the UK to capture competitive advantages.

The unique contribution of this report is to identify the lessons from successful and more rapid historical innovations and apply them to the challenge of meeting net zero emissions in the UK.

Achieving net zero emissions is likely to require accelerated innovation across research, demonstration and early deployment of low carbon technologies. Researchers analysed five international case studies of relatively rapid innovations to draw key lessons for government on the conditions needed to move from a typical multi-decadal cycle, to one that will deliver net zero emissions by mid-Century.

The case studies include:

• The deployment of the ATM network and cash cards across the UK;
• Roll out of a gas network and central heating in the UK;
• The development of wind turbines in Denmark and then the UK;
• Moving from late-stage adoption of steel technology in South Korea to being the world leading exporter; and
• The slower than expected development of commercial-scale CCUS to date across the world. 

The report also sets out which low carbon technologies are likely to have wider productivty and growth benefits in other industries for the UK. These include carbon capture, use and storage (CCUS); heating, ventilation and air conditioning (HVAC); wind energy; biofuels and batteries. These areas should be prioritised by the government’s innovation strategy going forwards.

• NET Power technology has the potential to be a gamechanger.
• Modelling analysis confirms that NET Power’s supercritical CO₂ power cycle has the potential to deliver carbon capture at efficiencies higher than conventional amine solutions.
• Some unpublished innovations which NET Power are protecting as trade secrets are needed to make the technology as cost efficient as an unabated CCGT, which is still improving rapidly.
• The technology is immature and has multiple development hurdles to overcome and therefore it is likely to take several years before it is commercially available at scale. It is therefore likely to be best suited for deployment once other elements of CCS have been de-risked (i.e. transport and storage) rather than in a First of a Kind full scale development.

• UK-grown biomass can deliver genuine, system-level, greenhouse gas savings.
• Planting around 1.4 Mha of second generation (non-food) bioenergy crops, such as Miscanthus, Short Rotation Coppice (SRC) willow and Short Rotation Forestry (SRF), by the 2050s would make a signifi cant contribution to delivering a cost-effective, low carbon energy system. This is equivalent to ~7.5% of the total agricultural area of the UK.
• Steadily increasing the area of bioenergy crops in the UK (averaging around 30-35 kha/yr of new planting out to the 2050s) would allow the sector to ‘learn by doing’ and develop best practices, as well as monitor and manage impacts on other markets and the wider environment.
• Delivering a substantial energy crops sector whilst balancing the demand for land from other sectors will require an increase in land productivity and a reduction in food waste throughout the supply chain.
• The market for second generation energy crops is nascent.
• As the UK prepares to leave the European Union, there is an opportunity to restructure farming support in a way which provides long-term clarity and support to farmers and encourages the sustainable growth of the UK biomass sector

• All three case studies demonstrate that planting energy crops can increase the profitability of the land over a 23-year lifetime. Initial investment costs are expected to be paid back within the first six to seven years.
• When optimising the use of land across the farm, impacts on food production can be minimised or avoided. in two case studies, food impacts were minimised by using land which delivered poor arable yields, and by minimising the reduction in sheep numbers through higher stocking densities (the number of sheep per hectare). in the third case study, the crop was planted on unused land so no food production was displaced.
• Land which is less suitable for food production or grazing can be suited to energy crops as they can be successfully planted on poorer quality soils, and land which is more prone to waterlogging or weed problems. They are also suited to less accessible fields as they require less intensive management than arable crops.
• The farmers in these case studies chose to grow energy crops for a variety of reasons - making better use of difficult or underutilised land, diversifying income and reducing workload. In addition, all farmers cited the importance of obtaining secure fixed-term contracts with buyers in their decision making. This reinforces findings from previous ETI work on enabling UK biomass.
• Discussions with land agents suggest that land used to grow biomass crops should not be valued differently to other agricultural land, as land should be valued on its productive capacity. however, the specific price offered by a buyer will be affected by their objectives in buying the land and their understanding of bioenergy crops. The presence of a profitable contract for the crop and a willingness from the buyer to continue with bioenergy cropping may have a beneficial impact on the land value. If the buyer wishes to change the land use, is uncertain how to manage a bioenergy crop, or if there are limited market outlets for the crop, the land value may be lower than if it weren’t planted with a bioenergy crop.
• Qualitative evidence from the Miscanthus farmers indicate an increase in wildlife, particularly birds, since growing the crop. In the Short Rotation Coppice (SRC) Willow case study, the farm carried out an environmental impact assessment (EIA) before planting.

• Despite new entrants, the supply chain is very fragamented.
• There are a number of planned network logistics investments which have the potential to benefit the sector.
• There are lessons that can be learned from established supply chains in other comparable industries
• Confidence in the sector is much needed to attract further investment in supporting infrastructure and supply chain synergies.
• Rail is vital to the UK’s economic prosperity. Rail links with ports and airports are essential to support the transportation of goods
• The extent to which rail transport and freight specifically will be a constraint to the biomass logistics supply chain is dependent upon a range of factors; primarily the Government’s energy policy on biomass, willingness of the Government to protect capacity and promote rail freight growth on the network, the extent to which biomass will replace coal and the cost efficiency of using imported fuel sources and rail haulage, as opposed to local fuel supplies and other transport modes

• ensure a wider, more detailed representation of possible bioenergy pathways
• raise the overall data quality and level of confidence in the model
• improve the user interface
• increase the options for use cases and scenarios

This evidence is a joint submission by the UCL Institute for Sustainable Resources (ISR) and UKERC. These two institutions have worked together closely in the past, including on a report commissioned by the Global CCS Institute, on The role of CCS in meeting climate policy targets.

We are submitting evidence because we believe CCUS is likely to have a critical role as part of an overall decarbonisation strategy for the UK – and, perhaps more importantly, for the world. We are keen to take part in the debate as to how this can be achieved;

Executive summary

• Current modelling evidence suggests that meeting carbon reduction targets will be at best significantly more expensive, and at worst impossible, without CCUS.
   
• This is primarily due to its offer of emissions reductions in industrial sectors, and of negative emissions with biomass, rather than as a power sector technology per se.
   
• Attempting to pre-define a cost-reduction trajectory for CCUS in advance is difficult and uncertain.
   
• Rather, the government should establish a maximum subsidy level at which it would be prepared to contribute to funding CCUS, and commit to fund projects should they reach this level or go below it.
   
• It should then introduce competitive mechanisms to assist discovery of the lowest cost, similar to the Contract for Difference (CfD) auctions.
   
• It also needs to support the whole innovation chain, coordinating diverse actors across industry and power sectors, CO2 transmission and storage; supporting research, development and demonstration efforts of shared benefit; taking over whole chain risk; identifying synergies between industrial sectors.
   
• Although CCUS currently appears to be critical to industry decarbonisation, there are other potential options which may compete with or indeed complement CCUS in the longer term. A bottom-up, granular approach to decarbonisation challenges and opportunities within specific UK industry clusters will yield greater long-term benefits than a single-technology focus on CCUS alone.

• An assessment of materially significant changes from the previous CCGT benchmark, together with documentation of the assumptions used in development of the new benchmark;
• An assessment of appropriate EGR rates fulfilling the above criteria appropriate exhaust gas recycle (EGR) rates which could potentially be used in CCGTs with CCS;
• Presentation of the technical and economic performance and deliverables for each of the benchmark cases

• The base case consists of a CCGT plus ICP configured for 90% capture using an amine system but where the CCGT is unaffected by the capture plant. In this case the capture plant operates independently of the CCGT and is self-sufficient in steam and power;
• The first sensitivity case investigates the use of power import from the CCGT. The steam demand for the ICP is met with a package steam boiler;
• The second sensitivity case investigates the effect of importing both power and steam from the CCGT. This is considered to represent a retrofit scenario, where the ICP is built next to an existing CCGT.

The aim of the research is to assess the technical, economic, financial and social uncertainties facing carbon capture and storage (CCS) technologies, and to analyse the potential role they could play in the UK power sector between now and 2030. CCS technologies are often highlighted as a crucial component of future low carbon energy systems in the UK and internationally. However, it is unclear when these technologies will be technically proven at full scale, and whether their costs will be competitive with other low carbon options.

• Carbon capture and storage (CCS) could be a key technology to tackle climate change
• However, there are many economic, political, financial and technological uncertainties that hamper its development and deployment
• Comprehensive government policy support is needed to reduce these uncertainties sufficiently to enable further progress
• It is not necessary to resolve all uncertainties in order to make CCS financeable in the UK
• The UK CCS commercialisation programme needs to make rapid progress, with firm commitments to build several demonstration projects as soon as possible

This working paper is an output from a project funded by UKERC (the UK Energy Research Centre) that aims to identify and explore some of the key uncertainties that might have a 5 UK Energy Research Centre material impact on if and when large-scale CCS is deployed in the UK. In particular, this paper proposes a number of plausible pathways for CCS progress (or lack of progress) until 2030 and identifies key branching points where a particular trajectory for CCS development may be determined as different pathways diverge from each other. The effectiveness of different criteria to determine which pathway CCS development is following can then be assessed (see the Methodology section for a more detailed explanation of the approach).

Overall, the project aims to make useful contributions to efforts to determine how both the viability and maturity of CCS technology can be assessed more generally. In this context, viability refers to several factors that are outlined in more detail in later sections of this paper, such as whether independent assessments suggest that CCS technology is performing well enough to compete with other options for mitigating the risk of dangerous climate change. Although maturity is related to similar concepts it is more concerned with how far progressed CCS technology appears to be along a continuum of development, rather than the more yes/no assessment that might be expected if only viability is considered. It is, for instance, possible to envisage that a technology be mature in terms of its development but nevertheless not viable unless a set of economic, policy and regulatory conditions are met.

This paper is an output from the UK Energy Research Centre (UKERC) Research Fund project Carbon Capture and Storage: Realising the potential? (UKERC 2011). The project, led by the University of Sussex is undertaking an inter-disciplinary assessment of Carbon Capture and Storage (CCS) viability from now to 2030 involving a partnership from the Universities of Sussex, Edinburgh and Imperial College London (Markusson et al. 2011). The overall aims and objectives include helping policy makers understand the conditions for successful commercialisation of CCS and to contributing methodologies to inform policy decisions on whether CCS is proven.This paper is an output from the UK Energy Research Centre (UKERC) Research Fund project Carbon Capture and Storage: Realising the potential? (UKERC 2011). The project, led by the University of Sussex is undertaking an inter-disciplinary assessment of Carbon Capture and Storage (CCS) viability from now to 2030 involving a partnership from the Universities of Sussex, Edinburgh and Imperial College London (Markusson et al. 2011). The overall aims and objectives include helping policy makers understand the conditions for successful commercialisation of CCS and to contributing methodologies to inform policy decisions on whether CCS is proven.

• This report has been prepared in response to a specific request from the ETI; the additional full reviews of the 34 studies identified as adopting ALCA methodologiesis solely due to this request and not to any change in the original goal and scope that applies to all other aspects of the project.
• The 34 ALCA studies identified by the initial selection and screening process formed a sub-set of ALCA bioenergy studies likely to cover the scope of the project in terms of:biomass sources, being conventional forests (broadleaf, conifer and pine), plantation pine forests, short rotation forests (conifer and broadleaf),short rotation coppice (willow and poplar), miscanthus and wheat straw; geographical biomass provenance, being Canada, the USA and Europe; and specified conversion technologies.
• Due to the nature of the screening process, coverage of the value chains relevant to this project is less assured for the selected ALCA studies than for the CLCA studies in the main review; no supplementary screening was carried out to identify ALCA studies that would have been excluded from detailed review for a reason other than adoption of ALCA methodology (such as provenance of biomass).
• This report provides the results of each review as well as an assessment of the robustness of the evidence base provided by the studies (mainly in terms of coverage of value chains transparency of calculationsand methodologies adopted) and an examination of the differences and similarities between the studies.
• The mai nfindings from the review process were that, from the 34 reviewed ALCA studies, very few (11) of the potential (190) relevant whole bioenergy value chains were covered by 8 ALCA studies, and only 1 of these studies (a calculation tool with the potential to cover 3 of the specified value chains) had high transparency.
• Taking into account the analysis of the reviewed ALCA studies,which demonstrates the extensive variations in the methodologies adopted and the physical parameters used for results reporting, it is apparent that there are limits to findings on confidence and critical data that can be derived from them for the evidence base for the specified bioenergy value chains in this project.

• a critique of the robustness of the evidence base based on both data and methodologies used;
• a measure of certainty behind the data reviewed; and
• details of the confidence the reviewer may have in interpreting the data.

• how sampling consistency will be assured;
• the design for the planned database;
• the roles and responsibilities between all parties involved in sampling, data collection and lab analysis.
• the rationale for the experimental approach

• the findings from the 2016/17 investigations into the impact of harvest time on the properties of UK produced Short Rotation Coppice (SRC) willow and Miscanthus;
• the impact of variety on UK produced SRC willow properties, and;
• the impact of four different types of commonly used storage types over time on UK produced Miscanthus properties.

• a schedule of work detailing the list of feedstocks to be sampled;
• the type, number and source of samples to be collected;
• a plan for gathering the samples? provenance data;
• a planned schedule of laboratory preparation and testing to be carried out;
• a clear plan for delivering the ETI project objectives.
• rationale for choices made 
• list of laboratory tests to be performed
• list of provenance data collected
• sample site locations

• inclusion of leaves in biomass should be avoided. An exclusion might be conifer tops where the levels of most elements were sufficiently low to not exceed quality thresholds;
• harvesting time had a marked effect;
• while there were species differences between SRC willow varieties, no variety combined the best ranking in all parameters across all sites;
• there were major changesto Miscanthus quality during storage (decreasing fuel quality);
• for growers of Miscanthus, poplar SRF and spruce SRF, the key influences on many properties, i.e. season and storage, can be manipulated;
• SRC willow growers have a reasonable degree of control over some of the important feedstock characteristics by their choice of variety;
• for poplar SRF and spruce SRF, many properties can be adjusted by choice of plant part to market, and harvest time
• feedstock properties were relatively insensitive to the way spruce SRF as grown.

• The application of holistic relational models has been applied for the first time in wind turbines across a wide dataset.This capability shows promise to codify expert knowledge but would require further development and validation.
• The use of prognostic damage models provides additional information to support inspection and maintenance optimisation. However, there is a need to build more experience with these models.
• The introduction of SCADA fault algorithms into the system reflects current thinking in wind turbine fleets, and the models produced represent advanced examples of what can be achieved. These real time algorithms can be implemented in the control system or a data historian.

• HiPerDNO
• OpenNode
• NIST IR 7628 Smart Grid Cyber Security
• Prototype Island Smart Grid
• Autonomous Decentralised Transport Operation Control System
• Traffic Management System for Kyushu Shinkansen train
• Danish Cell Controller Pilot Project
• M/490 Smart Grid Information Security working group
• EU-Commission Smart Grid Task Force (SGTF)

1. Electricity costs need to be competitive with current (2010) onshore wind costs by 2020 and with conventional generation by 2050. This is illustrated in the Offshore Wind roadmap in Appendix D,
2. Increased yields: annual offshore farm availability to be increased to 97%-98% or better (currently 80% to 90%),
3. Reduce technical uncertainties to allow farms to be financed in a manner, and at costs, equivalent to onshore wind today.

1. This project has provided the ETI with valuable data on TLP floating foundation design and cost to inform the ETI Offshore Wind programme’s future work (2010 to 2015):
2. The Turbine and TLP are not afully integrated system. In the next phase (if taken forward), further work would need to be done on modelling the interactions between waves, TLP, the tower and the nacelle. Existing commercial software will need to be enhanced to meet this need.Currentcommercial software models support structures fixed to the seabed / ground.

1. Electricity costs need to be competitive with current (2010) onshore wind costs by 2020 and with conventional generation by 2050,
2. Increased yields: annual offshore farm availability to be increased to 97%-98% or better,
3. Reduce technical uncertainties to allow farms to be financed in a manner, and at costs, equivalent to onshore wind today.

• This project has provided the ETI with valuable data on TLP floating foundation design and cost. This information has helped shape the next stage of the ETI Offshore Wind programme.
li>Our analysis has concluded that the cost of energy from the deep water high wind sites is competitive with that of the typical Round 3 sites.
• Further optimisation of the TLP floating foundation design could further improve energy costs.

This workshop brought together a wide range of individuals and organisation with an interest in bioenergy for heat, power and liquid transport. This included researchers from universities and research institutes, Government Research Councils, Government Departments, stakeholders from industry and others. The meeting was convened to begin the process of developing a UK Bioenergy Research Roadmap, which will be completed before the end of 2007.

The aims of the workshop were:

• To prioritise research activity and overcome the gaps in knowledge in bioenergy
• To influence research funding strategies in energy research.
• To encourage closer collaboration between academic research groups and technology developers
• To seek funding for collaborative research from Research Councils, DTI, DEFRA, Carbon Trust EU, etc.
• To establish partner

The aims of this the workshop were:

• To prioritise research activity and overcome the gaps in knowledge in bioenergy
• To influence research funding strategies in energy research.
• To encourage closer collaboration between academic research groups and technology developers
• To seek funding for collaborative research from Research Councils, DTI, DEFRA, Carbon Trust EU, etc.
• To establish partnerships with the outside the existing bioenergy research community
• Create the Research Roadmap for bioenergy to 2020 and 2050.

• Design, manufacture and test blades that are the optimum size for the next generation of large offshore wind turbines (>8MW and ideally 10MW);
• Verify the blade performance predicted by the models developed at the design stage;
• Be in a position to supply realistic numbers of blades into First-of-A-Kind small arrays of the target turbines by end 2014 and demonstrate a plan thereafter to scale up the business operation to serve the market.

• With technology and supply chain development there is a clear and credible trajectory to delivering commercial offshore wind farms
• Floating Wind hasthe potential to be a cost-effective, secure and safe low-carbon energy source which could deliver a levelised cost of energy of less than £85/MWh from the mid-2020s
• To deliver improved costs, offshore wind needs access to good quality wind resource close enough to shore and the onshore grid system so that transmission costs are minimised and operations/maintenance costs reduced
• Floating technology can provide access to high quality wind resources relatively close to the UK shoreline and in the proximity of population centres
• In water depths less than 30m fixed foundations will be the prime solution, in water depths over 50m floating foundations provide the lowest cost solution – a mix of these technologies is likely to offer the lowest cost pathway to deliver large scale deployment in the UK
• UK wind resources are abundant and exploitable – and already supplied 9.4% of the UK’s electricity needs in 2014
• The UK has the world’s highest offshore wind capacity with over 4GW installed, from over 1100 turbines, average power rating 3.4MW. A further 1.4GW is in construction, 4.8GW has planning permission and the world’s largest in-service offshore wind farm is in the outer Thames Estuary

• Community scale biomass / biogas CHP
• LV Voltage control technologies
• Energy Management Services and advanced network controls systems.

• hybrid ASHP,
• High Density Thermal Storage (HDTS) and
• HEMS / HAN as high priority technologies.

• Hybridised ASHP with gas boilers for individual dwellings, optimised for the British conditions;
• High-density thermal storage for individual dwellings;
• Home Energy Management Systems (HEMS) and sensors for residential applications;
• Building Energy Management Systems (BEMS) and sensorsfor non-domestic applications.

• The current state of development of the technology
• The key areas of technical development required
• Non-technical market constraints for each technology assessed at a high-leve
• The timescales and key milestones in these development pathways
• The level of investment required to achieve the technical developments identified
• The opportunities for the ETI to accelerate technology development and commercialisation
• Impact of technology development on performance and costs
• Role of the technologies under different electrification scenarios

Welcome to the Energy Materials Availability Handbook (EMAH), a brief guide to some of the materials that are critical components in low carbon energy technologies. In recent years concern has grown regarding the availability of a host of materials critical to the development and manufacturing of low carbon technologies.

In this handbook we examine 10 materials or material groups, presenting the pertinent facts regarding their production, resources, and other issues surrounding their availability. Three pages of summary are devoted to each material or material group. A how to use guide is provided on the following pages.

This report aims to support informed debate about the amount of biomass that might be available globally for energy, taking account of sustainability concerns. It uses a systematic review methodology to identify and discuss estimates of the global potential for biomass that have been published over the last 20 years. The assumptions both technical and ethical that lie behind these are exposed and their influence on calculations of biomass potential described.

The report does not seek to determine what an acceptable level of biomass production might be. What it does is reveal how different levels of deployment necessitate assumptions that could have far reaching consequences for global agriculture, forestry and land use; ranging from a negligible impact to a radical reconfiguration of current practice. The report also examines the insights the literature provides into the interactions between biomass production, conventional agriculture, land use, and forestry.

• Bidders Pack deliverable D4, EnergyPath Networks Modelling Local Energy System Designs Report, incorporating:
• Bidders Pack deliverable D2 EPN Use-Cases Limitations and Uncertainty

• To provide a consolidated technical description ofthe EnergyPath Networks (EPN) Tool covering both its design and data architecture
• To provide a user guide for the EPN Tool.

1. How often studies requiring these functionality enhancements /data improvements have been requested bystakeholders.
2. How much the credibility of the model is affected by not having these improvements.

• The types of data that are needed, the sources from which it is available and any restrictions on use.
• The data processing required and associated costs.
• The assumptions, exclusions, limitations and value of data in supporting decision making.
• Other data that might be available and valuable for validation of modelling outputs and supporting local area energy planning in the future.
• Methods for gathering additional data and how these could be phased into local area planning

• Offshore Wind has a significant role to play in the UK 2050 energy mix
  • Provides proven capability if other technology deployment is constrained
• Potential to deliver costs competitive with lowest cost form of low carbon generation
• Deployment of 8 to 16 GW of floating wind (if 2050 total is 40GW) could make economic sense for the UK
• The larger the UK deployment of offshore wind, the more important floating wind will become

1. Electricity costs need to be competitive with current (2010) onshore wind costs by 2020 and with conventional generation by 2050,
2. Increased yields: annual offshore farm availability to be increased to 97%-98% or better,
3. Reduce technical uncertainties to allow farms to be financed in a manner, and at costs, equivalent to onshore wind today.

• The consortium indentified that sufficient improvements could be made through technology innovation to deliver energy costs that are comparable with current (2010) onshore wind costs: one of ETI’s objectives for this programme.
• This involves innovation in rotor aerodynamics, rotor diameter, drive train technologies and electrical systems.
• The consortium also indentified that theoptimum turbine size for offshore is significantly larger than the current ‘state of the art’.

• Report 1: CTO’s Overview of Work Package 2, Task 1. Prof H.J. Michels, Imperial College London.
• Report 2a: Ignition, turbulent deflagration and DDT potential of hydrogen / methane and hydrogen / carbon monoxide mixtures with air. Prof P.R. Lindstedt, Imperial College London
• Report 2b: Shock Tube Studies of the Ignition Delay Times of Syn-Gases. Prof. R. K. Hanson, Dr. D. F. Davidson, Stanford University.
• Report 3: Modelling of blast in hydrogen power generation systems. Dr R.Rosario, BAE Systems.
• Report 4: One-Dimesional model predictions of test rigs pressure distributions (deliverable One). Dr G. Munday, Information Search and Analysis Consultants.

• Refinery Fuel Gas
• Syngas
• Producer Gas from Biomass

1. Post combustion capture membranes
2. Molten carbonate fuel cells for post combustion capture
3. Cryogenic separation (refrigerated and supersonic inertial separation)
4. Bi-phasic solvent scrubbing (liquid-liquid and liquid-solid)
5. Potassium carbonate scrubbing (pressurised and precipitating)

• Comparison of assumptions with Baringa Reference Case
• Market modelling results for Scenario 3 and Baringa Reference Case
• Asset modelling results for Scenario 3 and Baringa Reference Case
• Key conclusions and next steps

• Plant operation
  • H₂ turbine is highly sensitive to gas and carbon prices (more so to gas price)
  • CCGT CCS generation is far less sensitive and provides baseload power most of the time across the scenarios tested
  • Note the £35.1/tCO₂ and 7.7 £/GJ case has an output subsidy on CCS hence load factor is slightly higher
• Power prices
  • ESME fleet capacity margin is tight
  • CM clearing price cap hit and significant scarcity/uplift in wholesale prices
  • Subsidies for low carbon generation not having material impact on power prices (limited impact on CCGT CCS LF)
• Choice of final wholesale market scenario and ESME fleet is important as this will form the basis for asset valuation
• Drives asset dispatch against market prices
• Impacts CM clearing price (combination of de-rated capacity and revenues from wholesale market impacting bids)
• Potential changes to ESME run for scenario 3, before re-running PLEXOS
• Suggest usingBaringa commodity prices in ESME (based on recent IEA WEO publication) as more recent than ESME
• Continue to use ESME output carbon price, but noting that real 2030 policy incentive could be significantly lower
• Initial CM analysis based on ESME fleet suggests capacity is ‘too tight’ pushing up CM clearing and wholesale prices, need to revisit peak margin constraint in ESME to ensure more capacity is built –two parts to this:
• De-rating factors in ESME more optimistic compared to GB CM factors (except for interconnectors), but haven’t been updated for a while, question about whether to use BEIS CM numbers
• Reserve margin constraint currently 15% above peak demand, but this needs to covers a range of factors which may not all be included or have different underlying assumptions
• Current constraint only against end-use demand -needs to include distribution/transmission losses ~6.5%-
• Account for mark-up between ESME timeslice blocks to ½ hour peak (~7% delta in current scenarios)
• Actual reserve margin target (3.4% current CM target, although this may change in future)
• Largest infeed loss (currently ~900MW but expected to increase to e.g. 1600 with new nuclear)
• Timescales
• Need to have fully finalised scenario 3 wholesale market run (potentially different spot years of same mix) by early in w/c 20th to ensure sufficient time for asset analysis, but ideally bring this forward

• A: Baseline Information and Assumptions
• B: Power Generation
• C: Surface Plant Process Design
• D: Cavern Storage
• E: Economic Viability
• F: Low Carbon Case
• G: Cheshire Case Study: Cavern Cyclic Loading Impact

• Baringa Reference Case assumptions
• Role of gas in the GB power sector
• Missing money for Gas CCS plant
• Capacity Assumptions underlying the work

• To improve the ETI’s understanding of the economics of flexible power generation systems comprising hydrogen production (with CCS), intermediate hydrogen storage (e.g. in salt caverns) and flexible turbines;
• To focus on the potential, economics and technical requirements for salt cavern storage and flexible turbines, to enable refinement of the ESME model in order to confirm or adjust ESME findings.

• Representative Gas Distribution Model: connecting networks to transport sitesat different capacities for different network lengths, in rural, semi-urban, urban and London contexts
  • Context is a strong influencer of costs, with costs increasing from rural through to urban and London. .
  • Pipe costs dominate the overall network cost, particularly for the longer network lengths.
  • Pipe capacity and hence size has some influence over cost at the longer network lengths where pipe costs are the most significant element.
  • Normalised costs (ie costs per km) fall with increasing network length.
• Generic decommissioning costs (transmission), 100km length at different capacities / pipe sizes, rural context
  • Decommissioning costs are of the order of £90k/km.
  • Decommissioning of the pipework comprises around 80%-85% of cost, with the remaining 15%-20% relating to decommissioning the conversion station.
  • Pipe size has a minimal impact on cost.
• Generic decommissioning costs (distribution)for different contexts and populations
  • Decommissioning costs range from around £250k/km in London down to £60k/km in rural areas.
  • The relative importance of the different Assemblies in terms of share of cost varies with context: decommissioning the LP network represents the largest share of cost in rural areas (60%) and decommissioning domestic connections represents the largest share of cost in London areas (58%)
• Generic operational costs associated withremaining part of apartially decommissioned network (distribution)
  • In each context, reduction in Opex with increasing decommissioning is linear.
  • Direct costs represent approximately 80% of the overall Opex for gas distribution infrastructure
  • Decommissioning (abandonment) costs make up a small share of overall cost
  • After partial decommissioning, NPV of the partially decommissioned network per connection served increases as the percentage of network decommissioned rises.
• Gas transmission network: repurposing to hydrogen for different network lengths in a rural context
  • Overall the innovation of repurposing existing natural gas transmission networks to carry hydrogen is roughly half the cost of abandoning those same networks and building hydrogen pipelines from scratch
• Gas transmission network: repurposing to carbon dioxide for single network length in rural
  • The task compared repurposing existing gas transmission pipelines to carry gas phase CO₂ compared with building new transmission pipelines to carry dense phase CO₂.
  • Although operational conditions of pressure and and semi-urban contexts were different, they maintain the same CO₂ capacity flow
  • Both first costs and NPV are higher for new build than for repurposing.
  • All costs are higher in a semi-urban context than a rural one
• Natural gas conversion: installation of Biomethane to Grid injection points with different network lengths and capacities in rural and urban contexts
  • The cost of installing Biomethane to Grid plant is higher in urban areas than in less dense rural ones
  • Normalised costs per km fall with increasing network length
  • Normalised costs per m³ gas decrease with increasing gas injection capacities

• Representative hydrogen transmission model: transmission pipeline of different lengths required to transport hydrogen from production facilities to power generation sites and vehicle refuelling sites
  • Pipe lengths (NTS 32”) modelled for connection to production sites were 5km and 10km without the need for a compression station; pipe lengths (LTS 16”) for connection to refuelling sites were modelled at longer distances up to 200km, with a compression station required for anything over 100km
  • NPV/km for connecting to power stations was £5.4m for installation in 2025
  • NPV/km for connections to refuelling sites was in the range £3.0m to £3.5m depending on network length with the higher cost relating to the need to add in a compression station
  • The additionalcost of the power station scenario was due to the need to use larger diameter and hence more expensive pipe
• Representative hydrogen distribution model: distribution pipelines (LP/MP) required to connect production facilities to vehicle refuelling stations at different capacities and contexts
  • Context is a strong influencer of costs, with first costs per km increasing from rural through to urban and London. This is due to the higher costs of installing pipework in more congested areas.
  • Pipe costs dominate the overall network cost, particularly for the longer network lengths.
  • There is a small increase in cost per km for the higher capacity scenarios
• Hydrogen transmission and the impact of including storage:
  • Connecting a single large storage site into the network is considerably less expensive than connecting multiple storage sites of the same capacity
  • As the pipe lengths modelled were relatively short (5-10km) the storage costs dominated the overall project cost
  • Costs per mcm are considerably higher for the multi-storage option
  • The main benefit of the storage options is the storage itself and not the first cost savings associated with it.
• Hydrogen transmission network and the impact of pipeline material change: comparison of stainless steel 316L pipe with conventional steel using same pipe diameter (32” NTS)
  • First costs per km are higher for the stainless steel innovation
  • There is a slight reduction in cost/km for the longer stainless steel pipe lengths