Feasibility study
Biogas networks
Potential for biogas networks in the UK, funded by the Driving Innovation in AD round II programme
Project code: OIN001-010 Research date: Jan - May 2013 Date: November 2013
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Written by: Lucy Nattrass, Lucy Hopwood, and Michael Goldsworthy of NNFCC John Baldwin, Lee Firth, and Robert McKeon of CNG Services Ltd
Front cover photography: Biomethane upgrading facility, courtesy of CNG Services Ltd
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Executive summary
The report assesses the feasibility of establishing biogas networks, involving a number of biogas generating sites connected via a network of biogas pipelines to a centralised upgrading or combustion facility. The concept is proven in the Netherlands and Sweden, however due to different regulatory and political conditions within the UK a specific feasibility assessment is necessary to understand the potential scale and impact of the biogas network concept in the UK and any regulatory or technical issues that may arise. The feasibility study focuses on an opportunity identified in Crewe, in the North West of England, where the majority of farms are small to medium sized dairy farms with little arable land for growing crops as supplementary feedstocks. The intention for the subsequent demonstration project is to install a biogas network connecting a series of biogas producers to a centralised biogas upgrading or combustion facility. The analysis included in this feasibility study is based on the specific conditions within this test region, including supplementary supply of biogas from a United Utilities waste water treatment works. A number of configurations for the biogas network have been developed and a risk assessment completed. These inform the draft design of a biogas pipeline network and a centralised biogas injection station for the specific test region. Estimated capital and operational costs for these elements are outlined. The economics of the biogas network test region are assessed, comparing on-site CHP generation with the biogas network, centralised upgrading and injection of biomethane to the grid. The capital and operational costs of the AD plant are excluded from the comparison as they will be the same regardless of the downstream uses of the biogas. The centralised upgrading facility modelled has capacity to process 630 m3/hr of biogas, and reflects current upgrading plant economics. Sensitivity analysis considers the impact of capital cost reductions in the biogas upgrading facility, which may be expected as progress is made with surrounding regulation and more plants become operational. On-site CHP is recognised as the most appropriate comparison to biogas networks for the majority of small-scale farm AD plants, and the analysis considers three representative farm scales with biogas flow rates of 29 – 111 m3/hr. Under a central scenario the potential revenue per unit of biogas in the network is estimated at 0.34 £/m3 rising to 0.49 £/m3 after the first seven years when the capital is repaid. The initial revenues are comparable to biogas CHP at all scales. Over the first seven year period, it may be preferable for a farmer to select on-site CHP rather than join a biogas network, where especially in the early stages before the biogas network is operating at full capacity, the revenues may be more attractive, and the business case less complicated. However, over a longer term period of 20 years, the minimum expected lifetime of the AD and biogas upgrading plant, the revenues are greater for the biogas network at 0.49 £/m3. A viable alternative would be to combine the most viable options, and develop a biogas network piping gas to a centralised CHP facility, for more efficient combustion, use and investment. An agricultural landscape appraisal identifies Devon, Cheshire, Cornwall, Dorset and Somerset, as potential regions for biogas networks based on cattle populations, followed by the East Riding of Yorkshire and Norfolk based on pig populations. Finally the report provides details of the practical demonstration and dissemination requirements necessary to stimulate the first biogas network and subsequent interest of the concept in the UK.
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Contents
1.0 Introduction ................................................................................................. 4 1.1 Background ............................................................................................... 4 1.2 Objectives ................................................................................................. 5 1.3 Driving innovation ...................................................................................... 5 1.4 Consortium ................................................................................................ 5
2.0 Methodology ................................................................................................. 6 3.0 Evaluation ..................................................................................................... 7
3.1 Configuration analysis ................................................................................ 8 3.1.1 Biomethane to grid .......................................................................... 8 3.1.2 Biogas pipeline ................................................................................ 8 3.1.3 Biogas input station ........................................................................ 11
3.2 Draft design............................................................................................. 12 3.2.1 Biogas input station ........................................................................ 12 3.2.2 Biogas pipeline .............................................................................. 13 3.2.3 Biomethane to grid ........................................................................ 14 3.2.4 Centralised CHP ............................................................................. 15
3.3 Risk analysis ............................................................................................ 15 4.0 Legislation .................................................................................................. 21
4.1 Planning policy ......................................................................................... 21 4.2 Environmental permitting .......................................................................... 21 4.3 Gas regulation ......................................................................................... 22
4.3.1 Gas Safety (Management) Regulations 1996 .................................... 23 4.4 Incentives ............................................................................................... 23
4.4.1 Renewable Heat Incentive .............................................................. 24 4.4.2 Feed-in Tariff ................................................................................. 24 4.4.3 Renewables Obligation ................................................................... 25
5.0 Cost Benefit Analysis .................................................................................. 27 5.1 Cost to industry ....................................................................................... 27 5.2 Business as usual comparison ................................................................... 28 5.3 Other associated financial benefits ............................................................. 30 5.4 Environmental cost benefit analysis ........................................................... 30
6.0 Options appraisal ........................................................................................ 32 6.1 Agricultural landscape .............................................................................. 32
6.1.1 Livestock estimates ........................................................................ 32 6.1.2 Manure estimates .......................................................................... 36 6.1.3 Feasibility for slurry-fed AD networks ............................................... 36
6.2 AD potential ............................................................................................ 38 6.3 IP issues ................................................................................................. 40 6.4 Commercialisation plan ............................................................................. 40
7.0 Conclusions ................................................................................................ 43 8.0 Phase 2: Demonstration ............................................................................. 44
8.1 Objectives ............................................................................................... 44 8.2 Methodology ............................................................................................ 44
8.2.1 Project outline ............................................................................... 44 8.2.2 Responsibilities and ownership ........................................................ 45 8.2.3 Detailed project plan ...................................................................... 46 8.2.4 Detailed project timeline ................................................................. 47 8.2.5 Milestones ..................................................................................... 49 8.2.6 Risk assessment ............................................................................ 49
8.3 Project cost and financing ......................................................................... 50 8.4 Key personnel .......................................................................................... 51
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8.5 Monitoring ............................................................................................... 53 8.6 Health, safety and risk .............................................................................. 53
Appendix 1 Manure estimates .............................................................................. 55 Appendix 2 Biogas network decision making tool ................................................ 58
Glossary
AD Anaerobic digestion BIS Biogas Input Station: the group of equipment needed to input biogas into a
biogas pipeline, including conditioning biogas to meet the specification of the biogas network, as well as any monitoring and metering equipment
BtG Biomethane-to-Grid CHP Combined Heat and Power CSTR Continuously Stirred Tank Reactor CTS Cattle Tracing System DIAD Driving Innovation in Anaerobic Digestion EA Environment Agency EMIB Energy Market Issues for Biomethane Projects EMR Electricity Market Reform EP Environmental Permitting FiT Feed-in Tariff GDN Grid Distribution Network GT Gas Transporter HDPE High Density Polyethylene HSE Health and Safety Executive NEA Network Entry Agreement NTS National Transmission System NUTS Nomenclature of Territorial Units for Statistics PLC Programmable Logic Controller: A computer used to automate electromechanical
operations PPC Pollution Prevention and Control RHI Renewable Heat Incentive RO Renewables Obligation RPI Retail Price Index RT Retention Time SR2012 The Standard Rule that outlines the necessary requirements for an anaerobic
digestion facility to process waste feedstock
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1.0 Introduction 1.1 Background There are over 20 thousand dairy holdings in the UK, plus 60 thousand beef herds and 10 thousand pig herds, all of which generate slurries and manures suitable for AD. However, uptake in the farming sector has been very limited to date due to high capital investment and typically low returns for the use of slurry and manure. The first round of the Driving Innovation in AD (DIAD) funding programme delivered a number of cost effective small-scale slurry-only technology options suitable for these types of farms, but issues around the efficient use of the biogas remain where electricity grid connection costs are prohibitive and insufficient on-site heat demand is available to efficiently use the gas for heat-only applications. To date, promotion of AD in the main livestock area has focused on electricity and/or heat generation as a result of typical biogas flow rates of under 100m3/hr. The main disadvantage of such small scale CHP are typically low system efficiencies due to insufficient use of the heat and difficulties associated with operating small-scale CHP plants on inconsistent or low quality and low volumes of biogas. With the introduction of the Renewable Heat Incentive (RHI) in November 2011 and good progress in reducing costs for grid injection of biomethane, as a result of the activities of the Energy Market Issues for Biomethane Projects (EMIB) Review Group, there is an opportunity to consider the development of biogas upgrading and biomethane injection or use in more remote areas of the UK. An alternative opportunity for networking facilities also exists for centralised CHP, locating the engine remote from and central to a number of biogas production units, to optimise grid connection potential and to make better use of heat from the system. This report assesses the viability of establishing biogas networks, involving a number of biogas generating sites connected via a network of biogas pipelines to a centralised facility. The concept is proven in the Netherlands and Sweden, however due to different regulatory and political conditions within the UK a specific feasibility assessment is necessary to understand the potential scale and impact of the biogas network concept in the UK and any regulatory or technical issues that may arise. A report for Reaseheath Enterprise Delivery Hub in November 2010 considered a biogas network in the Cheshire area1. This report builds on the opportunity identified in the North West of England, where the majority of farms are small to medium sized dairy farms with little arable land for growing crops as supplementary feedstocks. The intention for phase 2 of the project is to install a biogas network connecting a series of biogas producers to a centralised biogas upgrading and biomethane injection facility, or a centralised CHP. A specific project opportunity around Crewe has been identified for the feasibility assessment. The analysis included in this feasibility study is based on the specific conditions within this test region, including supplementary supply of biogas from the United Utilities sewage works. However, the cost benefit analysis and commercialisation plan considers all regions to identify other potential biogas network locations.
1Rural Futures, SKM Enviros and CNG Service: Economic Viability of Farm Scale AD Biogas Production across Cheshire and Warrington: a report for Reaseheath Enterprise Delivery Hub, November 2010
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1.2 Objectives This feasibility assessment considers the applicability of the biogas network concept to the UK agricultural industry. Specifically the feasibility study aims to:
Develop a technical proposal for the test region, including a detailed design and
appraisal, capital and operational costs.
Develop a business case for the test region, including economic and environmental
benefits.
Identify the potential risks, including regulatory and policy issues.
Assess the number, size and distribution of suitable farms and other sites.
Quantify the scale of the opportunity within the UK.
Develop a detailed plan for the installation of a biogas networks demonstration.
1.3 Driving innovation Round 2 of the DIAD programme aims to identify technological innovations which will challenge costs and bring improvements in efficiency. The biogas networks concept is a market ready innovative technology solution that may provide a more cost effective and efficient use of biogas in rural areas not currently considered viable for AD. Indirectly the biogas network concept addresses the issue of heat use, by eliminating the need for each biogas producer to identify viable on-site heat demand, and process efficiency, by providing a solution for small-scale biogas producers to benefit from the economies and efficiencies of scale experienced by larger scale generators. In the same way that buying groups have been established for other renewable energy technologies and agricultural inputs, a buying group for networked AD projects could be established to reduce costs, spread risk, increase confidence and consequently improve access to finance for such facilities. Networking facilities may also encourage sharing of best practice between host farmers, especially if each has a financial stake in the centralised upgrading facility, to encourage maximum throughput for greatest returns. As a result, demonstration of the biogas networks concept may lead to the deployment and improvement of a significant number of AD facilities. 1.4 Consortium The feasibility study was completed by NNFCC in partnership with CNG Services Ltd. NNFCC is a leading strategic consultancy operating across the entire bioeconomy; offering expertise in biomass, biogas, biofuels and bio-based products. CNG Services Ltd supports the development of new AD projects, and designed and project managed the Didcot and Poundbury biomethane to grid projects. The partnership has a combination of AD, biogas, agricultural, engineering and regulatory background, knowledge and technical expertise. It was therefore well positioned to identify the challenges and opportunities in developing biogas networks in rural areas and to consider potential solutions and pursue the design and implementation of the biogas network concept in the UK.
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2.0 Methodology Phase 1 aimed to determine the viability of establishing biogas networks in the UK, including determining the practicalities, as well as the economic, environmental and social benefits. This has been delivered by four work packages as outlined in Table 1.
Table 1 Project work packages
WP1 Options Appraisal
Review existing literature and data sources to identify suitable parameters for a biogas network and to quantify the scale of the opportunity in rural areas. Including a review of the agricultural landscape across Great Britain, specifically the livestock sector; AD technologies targeted at small-scale slurry-fed systems, including those supported by DIAD Round 1; and the regulatory and policy framework, to identify any likely challenges or specific opportunities.
WP2 Scenario Analysis
Based on the options appraisal, develop a number of possible configurations for the biogas network considering location and ownership of the centralised facility, and roles and responsibilities. Design draft configurations accordingly for the test case in the North West of England using real data obtained from a collection of suitable farms. Critically assess the draft configuration designs identifying risks and mitigation measures.
WP3 Business Case Development
Develop a technical proposal for the test region, including a detailed design and appraisal of the technical ability, functionality and operational parameters of the proposed biogas network in the test region; and a subsequent business case. Based on the data and evidence collated in WP1, determine the potential for National deployment, and compare to the standard technology option of individual biogas plants with on-site CHP.
WP4 Final Report Prepare a final report with recommendations for future actions, and including a detailed implementation plan for the demonstration phase.
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3.0 Evaluation The biogas network typically comprises a series of biogas producers connected by pipeline to a central upgrading station as illustrated in Figure 1. The centralised facility may alternatively be a CHP unit, which would be less complex but more reliant of having a heat user available to optimise the economics and efficiency of this case. The network system requires biogas monitoring, removal of water and other contaminants, biogas pipelines, and potentially also biogas upgrading to meet the specification of biomethane required for injection to the grid. The biogas input station (BIS) is defined as the group of equipment needed to input biogas into a biogas pipeline, including conditioning biogas to meet the specification of the biogas network, and monitoring and metering equipment. Some of the processes included in the BIS are used to clean biogas prior to combustion in a CHP, although the specific application is not operational in the UK. Similarly biogas pipelines are not currently operated in the UK, and therefore the configuration analysis and draft design focus on these two elements of the biogas network.
Figure 1 Example biogas network2
A number of biomethane to grid plants have recently become operational in the UK, and several technologies and process designs are demonstrated. Biomethane upgrading and injection is therefore excluded from the draft design. However, due to the impact of the downstream biogas requirements to the BIS and biogas pipeline for this case, the biomethane upgrading and grid injection steps are included in the configurational analysis. The configurational analysis and draft design have been developed for a specific test region in the Crewe area. The plans include a large dairy farm, with approximately 1,200 cows and estimated biogas generation capacity of over 100 m3/hr, and the United Utilities waste water treatment works, which currently generates a significant but variable quantity of biogas. An additional farm owned by the same farmer may subsequently be added to the network, the second farm houses 400 cows. Five local farms have also actively discussed investing in AD and joining the biogas network.
2 KIWA Gas Technology, New Networks for Biogas, 2012
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3.1 Configuration analysis 3.1.1 Biomethane to grid The Uniform Network Code provides the legal and contractual framework for the supply and transport of gas across the UK. It governs grid balancing, network planning and allocation of capacity. Under the Uniform Network Code, the injection of biomethane into the gas network requires a Network Entry Agreement (NEA) between the biomethane producer and the gas transporter (GT), which specifies the technical and operational details of connection. The EMIB Review Group, convened by Ofgem and including each of the gas distribution networks (GDNs) and other stakeholders, made significant progress in simplifying the procedure for biomethane injection to the grid3 including standardising NEAs. The functional specification, referenced in all NEAs, sets out the requirements to be met at any entry point that is connected to a GDN, a generic functional specification has been developed by GDNs to ensure consistency, which site specific details may be added to. The connectee is responsible for determining the preferred provider for the entry facility. They may own and manage the majority of the entry facility, but Northern Gas Networks wish to retain responsibility for the addition of odour. Those connecting to the main gas network are expected to bear the full costs of works necessary to support the connection, both at the connection point itself and within the network where necessary. The Gas Safety (Management) Regulations and Gas (Calculation of Thermal Energy) Regulation place legal obligations upon the GT in respect of gas introduced into its gas system by a third party. Opening of the remote operating valve that enables flow of biomethane into the GDN must therefore be under the sole control of the GT. 3.1.2 Biogas pipeline Two general network layouts have been identified as illustrated in
3 Joint Office of Gas Transporters, Review Group Report: Energy Market Issues for Biomethane Projects, May 2012
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Figure 2. The decision between a star or fishbone layout will be influenced by the local geography and location of biogas producers. An important design aspect is to allow branches of the network to be isolated in case sectorisation becomes necessary due to technical or quality failures. Manual values may be incorporated into the design to accommodate this. Gas quality measurement is required at all producing nodes, including methane and carbon dioxide measurement, to support the later allocation of costs and incomes. Standard natural gas piping materials and methods are generally considered suitable for the below ground pipework comprising the network, therefore this will be primarily low cost polyethylene (PE). Stainless steel may be appropriate for short above ground pipework where the risk of corrosion or excess heat is greater. From a regulatory perspective, there are no specific biogas regulations in the UK. The natural gas regulations may be used as a reference with some specific biogas related risks considered. These specific risks include:
corrosion of pipes;
additional hazardous components in gas;
toxic components; and
emergency response capabilities.
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Figure 2 Biogas pipeline layout options In the UK, the Institute of Gas Engineers and Managers (IGEM) are currently developing a biogas pipeline standard. The 4th working draft of the IGEM Steel and PE Pipelines for Biogas Distribution was used to guide this design. The draft standard details the legal considerations, including planning and safety regulations, and provides guidance on the design, construction and commissioning of pipelines. It requests that a risk assessment should be carried out for each installation, considering:
location and routing of the pipeline with respect to occupied buildings;
management of gas escapes;
maintenance regime;
maximum allowed hydrogen sulphide content; and
gas detection needed.
A hazard and operability analysis should also been carried out on both the network design and operating procedures to:
confirm workability;
mitigate or remove risks arising; and
ensure routing is designed to avoid proximity/damage risks.
The results of the biogas network risk assessment for the test region are outlined in Table 2. The site specific conditions include a low risk, rural location without large numbers of people, and operating pressures of less than 400 mbar, reducing the hazard from any leaks. Risk assessment indicates that odorisation is unlikely to be needed for rural networks, but is perhaps more likely to be needed in more highly populated areas. If present, H2S may provide smell to biogas, and it may be necessary to educate the local community of the different smell and characteristics of biogas. However, high levels cannot be detected and can be fatal, therefore extra safety procedures are needed during pipeline works as H2S and CO2 are toxic components. Gas marks and sensor equipment are needed, as the dispersion of biogas is lower than natural gas due to its higher density.
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Table 2 Initial risk assessment for the biogas network based on expected site conditions
Hazard Consequence Control
Biogas release
Risk to human health from toxic H2S
Asphyxiation risk in confined or unventilated spaces
Human health risk due to CO2 mild toxicity and/or concentration
Flammable release, risk of fire or explosion
H2S removal to “safe” level prior to entering pipeline
Biogas analysis at input point: control system monitors H2S levels and can stop gas input if required
Operator training and awareness
Use of personal detectors
Operational procedures to include monitoring
Periodic leakage survey
Integrity tests at commissioning phase
Third party damage to pipeline
Uncontrolled escape Pipeline route marking
Marker tape at 300mm cover over pipe route
Extra depth of cover where activity may create additional risk
Pipeline physical protection at road crossings
Lodge the route drawing with landowner and local grid company
Escape of unodourised gas
Escapes not detectable Natural dispersion to air
Route pipeline away from potential confined spaces
Display contact numbers to report instance of damage
Control work in vicinity of pipeline
For the biogas pipeline design, operating pressures of less than 400 mbar are favourable, providing a balance between pipe size and cost associated with increased operating pressure. This reduces gas compressor complexity and costs, and would reduce leakage rates from a given hole size in the event of a pipeline rupture. Coarse drying of the biogas before entering the network is desirable as it reduces the risk of condensation in the pipework. Inclusion of condensate drop pots in the pipeline adds complexity to the design, as one is needed for every undulation in the land, and access is required to dispose of any condensed water. The gas should not, however, be so hot as to reduce the mechanical strength of pipeline materials. Therefore a gas input temperature of 10 - 38oC is recommended. A suggested rural biogas network entry specification is outlined in Table 3, based on the IGEM draft standard and the site specific risk assessment.
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Table 3 Suggested biogas network entry specification, based on the IGEM draft standard and a site specific risk assessment
Parameter Limit Limitations
Temperature 10 – 38oC Material selection to match pressure and temperature, may apply upper allowed temperature limit
Pressure ≤ 400 mbar Operating pressure approx.200 mbar due to economics, including low cost blowers
Odour No odorant added -
CH4 Expected range 50 – 70% vol
Information only
CO2 No limit Information only
O2 ≤0.2 – 0.5% Limit will be set by final biomethane grid entry level and the upgrading equipment selected
N2 No limit Information only
Water dew temperature
≤6 oC at atmospheric pressure
Prevent condensation in pipeline
Organo halides ≤1.5 mg/Sm3 Not expected
Hydrogen chloride ≤1.5 mg/Sm3 Not expected
Hydrogen fluoride ≤5 mg/Sm3 Not expected
Ammonia ≤20 mg/Sm3 Typical removal by dissolving in water
Xylenes ≤100 mg/Sm3 Activated carbon
Arsenic ≤0.1 mg/Sm3 Not expected
Radioactivity ≤ Bq/g Not expected
Siloxanes ≤5 mg/Sm3 Not expected
3.1.3 Biogas input station The BIS processes are similar to typical biogas cleaning prior to CHP. The purpose is to dry the biogas and then check the flow rate and quality before allowing it to enter the biogas pipeline. Specifically, the BIS must ensure biogas meets the biogas pipeline specification outlined in Table 4. Depending on the levels of H2S in the biogas, removal of some H2S may be necessary as it is toxic and may corrode pipes. The concentration of H2S in raw biogas is related to the AD feedstock, a typical concentration for slurry-only AD is 200 mg/m3. The exact level of removal is not clear and is likely to be driven by economics and the equipment selected for the centralised upgrading or combustion facility. As a minimum, crude removal of H2S to less than 50 mg/m3 is recommended at the AD plant, prior to injection into the biogas network. This may be achieved by O2 injection, biological process, or addition of ferric chloride. Fine removal to less than 5 mg/m3 is desirable for preservation of equipment, and may be achieved with impregnated activated carbon. Fine removal is included in the draft design.
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Table 4 Summary of biogas pipeline specification and biogas input station processes
Parameter Target Method
Dew point 3 – 5oC Heat exchanger cooled by a chilled glycol/water mixture.
Pressure 150 – 200 mbar
Temperature 30oC Temperature increased by a blower. At this temperature gas is no longer saturated.
H2S removal <50 mg/m3
Or <5 mg/m3
At a minimum level, crude removal of H2S may be achieved by O2 injection, biological process, or addition of ferric chloride. Fine removal to <5 mg/m3 is desirable, and may be achieved with impregnated activated carbon filters.
3.2 Draft design 3.2.1 Biogas input station The process, as illustrated in Figure 3, comprises:
drying carried out to a dew point of 3 – 5 oC in a heat exchanger cooled by a chilled
glycol/water mixture;
condensed liquid removed in a knockout pot and the liquid returned back to the AD; this
method of drying biogas is reasonably cheap and has low energy consumption;
gas pressure is then increased to 150 – 200 mbar; and
gas temperature is increased to about 30oC by a blower, so that the gas is no longer
saturated.
An engineering study was completed to estimate the capital and operational costs for a BIS processing 100m3/hr biogas. The study assumed a skidded assembly process and careful outdoor design to minimise need for more expensive ATEX equipment. Optional elements include crude or fine H2S removal and odorant injection. For the calculation of capital and operational costs fine H2S removal is included but odorant injection is excluded. The control system comprises a simple programmable logic control (PLC) based system with a secure locked control panel with passwords to prevent unauthorised changes. Full control and monitoring is available remotely at the AD site through cables installed with the biogas pipeline. The base model would be manually changed on capacity to match the gas produced by the AD, using a bypass valve. The water chiller, dryer and blower could be part of the AD control system rather than a separate unit which allows retrofit of CHP sites utilising existing equipment. A breakdown of the capital cost based on this process design is provided in Table 5. Capital costs are estimated to be £60,000 to £80,000 for systems with biogas flow rates of between 50 and 200 m3/hr. Costs exclude odorant injection which is not expected to be necessary for rural systems. This would add an additional £30,000 based on network entry systems currently being installed. Operating costs are estimated at around £9,000 per year, including maintenance, electricity demand, and the purchase and disposal of activated carbon, as illustrated in Table 6.
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Table 5 Initial estimation of BIS capital costs at various biogas flow rates4, £
Biogas flow rate 50 m3/hr 100 m3/hr 200 m3/hr
Heat exchanger 2,049 3,000 4,392
Water cooler 1,034 1,800 3,134
Manual valves/fittings 750 900 1,150
Carbon filters (with media) 3,415 5,000 7,320
Blower 1,366 2,000 2,928
Controls and analysers 18,000 18,000 18,000
Pressure transmitters 800 800 800
Temperature transmitters 800 800 800
Flow meter 1,800 1,800 1,800
Misc. instruments 2,000 2,000 2,000
Heat tracing lagging 1,000 1,000 1,000
Fabrication & material costs 7,000 9,000 11,000
Wiring costs 2,600 3,000 3,400
Flame arrestor 400 400 400
Design contribution 2,500 2,500 2,500
Software contribution 2,000 2,000 2,000
Installation & commissioning 3,000 3,200 3,500
Contingency (10%) 4,915 5,720 6,612
Profit (10%) 5,406 6,292 7,274
Total 61,122 69,212 80,011
Table 6 Key contributions to BIS operating costs, biogas capacity 100 m3/hr
£/yr
Maintenance 4,500
Electricity 2,250
Activated carbon 2,125
3.2.2 Biogas pipeline A draft biogas pipeline design for the test region has been completed and the route is illustrated in Figure 4. Pipelines in this region may be routed through rural farm land or may run alongside the road. Passing through rural farm lands will require the permission of the land owners, and although they may be cheaper to lay this may cause some issues with land ownership. Locating pipelines along roadsides removes ownership issues, although increases the cost of installation and may take more time to install as agreement with local authorities is necessary. Within the test region, the biogas pipeline will have to cross a railway track, this adds additional cost and may take more time as the waiting period may be months or years, discussions have been made with Railtrack and estimated costs are included accordingly. The capital costs of the biogas network have been estimated for total biogas flow rates of 400 m3/hr and 1,600 m3/hr, and are outline in Table 7. The maximum biogas pressure if opting to inject into the gas grid in both scenarios is 200 mbar at each injection point. The
4 Capital cost estimates are based on experience of building similar systems and do not represent vendor quotes. It is assumed several such plants are built to share engineering design and software costs.
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pipe diameter in the first scenario is 125 mm, and 250mm in the second scenario. The biogas pipeline distance for the test region is 5.8 kms, and the capital costs estimated between £309,000 and £601,000, this equates to a cost of £50 – 100 per meter. Pipeline costs depend on the volume of gas and also local geography; the proposed capacity should accommodate potential future extensions to the biogas network.
Table 7 Estimated biogas pipeline capital costs, £
Scenario 1 400 m3/hr
Scenario 2 1,600 m3/hr
Design 5,000 5,000
Pipe laying 239,000 518,000
Easements 7,500 7,500
Statutory payments 2,500 500
Railtrack 35,000 35,000
Directional drill (across railway) 15,000 20,000
Project management 15,000 15,000
Total 319,000 601,000
3.2.3 Biomethane to grid As illustrated in Figure 4, in the test case it is likely the centralised facility will be located at the United Utilities waste water treatment works. If opting for biomethane injection into the gas grid, two options for connecting the upgrading plant to the medium pressure grid have been identified and are illustrated in Figure 5. Option 1, is 1.25 km and crosses the rail track, and option 2 is 1.75 km and involves crossing the River Weaver. Investigations have shown that crossing the rail track is less costly and time consuming than a river crossing, and therefore option 1 has been selected. The maximum capacity at this grid entry point is 120 m3/hr, but this may be increased to 200 m3/hr with network analysis and reconfiguration. The biomethane piping, once completed, will be adopted by National Grid and become part of their network. The network costs for two scenarios are outlined in Table 8, and are calculated assuming installation in grass verges. The biomethane pipeline should be installed with consideration that additional capacity will be needed should new biogas producers wish to be added to the network.
Table 8 Estimated biomethane pipeline capital costs, £
Scenario 1 240 m3/hr
Scenario 2 960 m3/hr
Design 3,000 3,000
Pipe laying 69,000 148,000
Easement 5,000 5,000
Statutory payments 2,500 500
Railtrack 35,000 35,000
Directional drill (across rail track)
15,000 20,000
Project management 7,500 7,500
Total 137,000 219,000
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3.2.4 Centralised CHP An alternative option, where the economics or practicalities of centralised upgrading and gas grid injection are not viable, would be to centrally locate a larger scale CHP engine on a remote site close to a significant heat offtake. Such a location could be close to the edge of a village, town, industrial estate or rural business park, for example. The economics of this option have not been considered outright, but it is relatively straightforward, having fully costed the biogas network option, to comparatively assess upgrading and injection with biogas combustion via a CHP. This alternative option would be reliant on two factors; having a heat offtake and a suitable capacity electricity grid connection point in close vicinity. As a lower risk, lower cost option offering faster returns this could be most favourable. The focus of the subsequent design and configurational analysis is on the biogas network potential, with biogas upgrading and injection being considered as the conversion route to assess the worst case scenario when comparing to on-site CHP. 3.3 Risk analysis Table 9 outlines the risks identified in relation to developing biogas networks. The risk analysis was carried out alongside the configuration analysis and draft design for the test region, although not all of the risks identified are specific to the test region, and have implications for the wider roll out of the biogas networks concept in the UK.
Biogas networks 17
Figure 3 Draft design of biogas input station (BIS)
Biogas networks 18
Figure 4 Biogas network route design
Medium Pressure (MP) pipeline
Not drawn to scale – Use for indicative purposes only
Biogas Pipeline (400mBar)
Biomethane Export Pipeline
Rivers Reeseheathe College – Farm 1 Farm 1 – Farm 2 Farm 2 – Biomethane Plant
2,870 metres 860 metres 2,100 metres
Biomethane Export Pipeline 1,200 metres Option 1 used – no rivers
Biogas networks 19
Figure 5 Connection options to medium pressure gas pipeline
Biogas networks 20
Table 9 Risks identified in relation to biogas networks
Risk Severity Mitigation
Securing sufficient biogas flows to reach the economies of scale necessary for biogas upgrading and biomethane injection, or to justify centralised CHP. This relies on a number of independent farmers or AD developers committing to supply the network. The timing of these investment decisions must be coordinated to reduce the risk to each individual project.
High Where possible co-location with existing biogas producer, for example waste water treatment works in the case of United Utilities.
FIT degression for electricity production Medium/High If opting for a centralised CHP facility, any degression to the FiT from April 2014 is likely to impact negatively on the business case. Pre-acreditation before December 2013 would avoid this; however it is unlikely any networks will reach pre-accreditation in this timescale. For larger scale (>500kWe) facilities, degression is likely to be limited to 5%
The capital and operational cost for biogas networks and on-site CHP will be site specific and may vary over time. If the costs associated with on-site CHP reduced to a greater extent than biogas networks, biogas networks may be unattractive to a greater number of farms.
Medium/High Ensure maximum possible cost reductions for biogas network and conversion facilities. Farmers planning to network should form a buyers group and agree to use the same suppliers, to procure plant or components at a discounted rate for multiple purchases. Partly mitigated by the degression mechanisms for the FiT payable to power generated by CHP.
Land access issues, for laying biogas pipes from site of generation to the centralised facility.
Medium/High Need to ensure biogas transfer safety guidance is provided and clearly communicated; try to limit piping to participants land, or offer some form of incentive or involvement opportunity to other participating land owners – to be considered at point of ownership discussions.
Biogas networks 21
Risk Severity Mitigation
The risk assessment of the biogas network is not accepted and it is deemed necessary to inject an odorant into biogas prior to its injection into the biogas network. This would significantly increase the cost of the BIS.
Medium/High This is expected to be medium to low risk in rural areas.
Insufficient capacity in the gas or electricity grid, where biogas network plants are proposed.
Medium/High Early discussion with the relevant GDN/DNO to understand capacity limitations. Demonstration of in network compression is potentially needed to increase BtG capacity.
Attractive RHI tariff introduced for medium and large scale biogas combustion, following 2012 consultation on Expanding Non-Domestic RHI, leading to more plants considering on-site or centralised combustion and use.
Medium/Low Issues with lack of local heat users to make full use of heat generated on-site is likely to detract from this option; however, need to consider and promote wider efficiency gains and economies of scale as the benefit of biogas networks, as opposed to direct on-site combustion.
RHI degression for biomethane to grid Medium/Low Based on the current deployment pipeline, there is sufficient capacity within the proposed degression mechanism for biogas to preserve the current tariffs for a reasonable amount of time. Modelling has indicated, even with the introduction of a new tariff for greater than 200kWth following the current review, degression is unlikely to be triggered for biogas until at least 2015, if not later.
Planning permission is not granted for biogas networks, or severe delays are experienced due to lack of knowledge or proof of concept and „first of a kind‟ concerns. Risk of local opposition to piping gas through rural areas.
Medium/Low Ensure first network, demonstrated as part of phase 2 of DIAD programme, is clearly communicated to planners, public and local businesses. Once first network is passed, others should have a proven protocol to follow.
Environmental permitting issues with burning gas remote from site.
Low Early discussions to be held with Environment Agency as part of phase 2 demonstration, to clearly communicate intentions, risks and H&S requirements, to provide necessary reassurance.
Tighter biogas specification required than anticipated by the risk analysis.
Low BIS design and cost calculated assuming worst case scenario for H2S removal
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4.0 Legislation5 This section outlines policies and regulations relating to AD plant operation and the use of biogas, including the transmission of biogas and biomethane. There is currently no specific legislation for biogas networks, so the following is applicable for networks or on-site combustion. The incentives schemes for small-scale AD facilities are included, so that we may compare the business case for on-site CHP with biogas networks and central conversion. 4.1 Planning policy AD plants that are only sourcing material from the host farm, and have a footprint of less than 465m2 are eligible for permitted development and do not require full planning permission, as per the Town and Country Planning (General Permitted Development ) Order 1995 (as amended)6. Determined by feedstock type, the likelihood is that all farm-AD facilities connecting to the biogas network would fit within these restrictions. Any waste-fed facilities, farm- or non-farm based will require full planning consent and would be required to make an application to the local council as early as possible. 4.2 Environmental permitting AD plants are regulated by the Environment Agency (EA). Environmental permitting (EP) is a scheme in England and Wales for regulating business activities that could have an impact on the environment and human health. All AD plants will be required to obtain a permit or exemption to operate and to spread digestate. Operators must complete an application form with relevant technical information relating to the digestion process and biogas use, and also demonstrate they are competent to operate the plant. Unless eligible for an exemption, there is a charge for making an application and the process may take many months. Once a permit is received the EA will make annual checks to ensure compliance and make an annual subsistence charge. Small on-farm AD plants taking agricultural wastes and crops only fall under the T24 environmental permit exemption7. The plant operator has to register for an exemption but there is no charge for this process. To qualify for the T24 exemption, the plant must:
digest only slurries, manures and crops;
have a thermal input to the biogas burner of less than 400kW;
retain the input material in the digester for at least 28 days;
have a digester not larger than 1,250m3; and
the total quantity of waste treated or stored at any one time must not exceed 1,250m3.
Alternatively the T25 exemption8 allows the treatment of food and other biodegradable wastes by AD to produce a digestate which can be used for providing benefit to land. The gas produced must be used for generating energy. This exemption does not permit
5 At the time of writing the legislative information shown in the report is correct, but that over time it may be subject to change.
6Note: other restriction listed under Schedule 2 Part 6 Agricultural Buildings and Operations that may be relevant in particular cases
7 T24 (anaerobic digestion at premises used for agriculture and burning of resultant biogas) 8 T25 (anaerobic digestion at premises not used for agriculture and burning of resultant biogas)
Biogas networks 23
treatment of wastes that are animal by-products without an appropriate authorisation from Animal Health (AHVLA (Animal Health and Veterinary Laboratories Agency). Up to 50 m3 of waste may be stored or treated at any one time. The Standard Rule Permit SR2012 No129 "Anaerobic digestion facility including use of the resultant biogas" applies to England and Wales, and enables anaerobic digester operators to carry out anaerobic digestion of wastes and also combustion of the resultant biogas in gas engines. The rules also allow use of gas turbines, boilers, fuel cells and treatment and/or upgrading the biogas to biomethane. Permitted wastes include those controlled by the Animal-By-Products Regulations but do not include hazardous wastes. These rules are for facilities that have capacity of no more than 100 tonnes of waste or a combination of waste and non-waste in any one day. These standard rules do not allow any emission into surface waters or groundwater except clean water from roofs and parts of the site not used for waste activity including storage of wastes. They do not apply to installations with more than one operator. The Standard Permit has various additional requirements; the plant must have a means of capturing spilled or leaked digestate or waste and its operator must be recognised as competent through membership of an approved scheme. It costs £1,590 to make an application, with an annual charge of between £1,540 and £2,420 0 thereafter depending on which permit is adopted. If the conditions of the Standard Permit are not met, an application can be made for a Bespoke Permit. No specific permitting restrictions apply to biogas networks, so it would be advisable to check details with the EA at an early stage. 4.3 Gas regulation Gas Transporters (GTs) provide the pipelines through which gas is conveyed. Under the Gas Act 1986 (as amended) and The Electricity Act 1989 (as amended), GTs are licenced and must comply with the Gas Safety (Management) Regulations. They are regulated by Ofgem and operate according to the Uniform Network Code. National Grid own and operate the high pressure national transmission system (NTS), and GDNs transport gas from the NTS to end-users. There are eight GDNs across Great Britain, operated by four organisations: National Grid Gas Distribution, Northern Gas Networks, Scotia Gas Networks, and Wales & West Utilities. In addition a number of independent gas transporters operate downstream of GDN‟s networks. The Gas Act and Electricity Act prohibit certain activities unless the person carrying out that activity is licensed, or exempt from the requirement for a licence. These licenced activities are outlined in Table 10.
Table 10 Gas market licences
Transportation Licence
Allows the licensee to convey gas through pipes to premises, or to another system of pipelines operated by another gas transporter (GT). Cannot be held in conjunction with a gas supplier, gas shipper or gas interconnector licence.
9 There exists a corresponding standard rules permit 2012 No10 „On farm Anaerobic Digestion Using Farm Wastes Only, Including The Use Of Resultant Biogas‟.
Biogas networks 24
Interconnector Licence
Allows the licensee to participate in the operation of a gas interconnector which is defined as co-ordinating and directing the conveyance of gas into or through a gas interconnector; or making such an interconnector available for use for the conveyance of gas. Cannot be held in conjunction with any other type of gas licence.
Shipper Licence
Allows the licensee to arrange with a GT for gas to be introduced into, conveyed through, or taken out of a pipeline system operated by that GT. Cannot be held in conjunction with a gas transporter or gas interconnector licence.
Supplier Licence
Allows the licensee to supply to any premises gas, which has been conveyed to those premises through pipes. A gas supplier licence can allow for supply to either domestic and non-domestic premises, or non-domestic premises only. Cannot be held in conjunction with either a gas transporter or gas interconnector licence
Biogas and biomethane producers are not required to hold a licence in order to produce gas, and subject to European Union requirements, DECC intend to publish an exemption so that biomethane producers would not require a GTs licence to convey gas to an existing GT pipeline. Biomethane producers must however register with Ofgem in order to receive RHI payments. 4.3.1 Gas Safety (Management) Regulations 1996 These regulations detail the requirements relating to the composition and pressure of gas conveyed in a network, and the safety procedures relating to gas escapes from the network. It is prohibited to convey gas in a network unless a safety case has been prepared and accepted by the Health and Safety Executive (HSE). Those in control of gas processing facilities are required to co-operate with those conveying gas in a network and with network emergency co-ordinators to enable them to comply with the regulations. The regulation outlines requirements with respect to the characteristics and testing of gas, including hydrogen sulphide content, sulphur content, hydrogen content, oxygen content, impurities, hydrocarbon dew point and water dew point, and Wobbe Number. Although HSE may award exemptions from any specific requirement. Gas which does not conform to the requirements set out in the Regulation and is conveyed from a gas processing facility for treatment or blending to bring it into conformity, such as that transmitted via a biogas network, is not treated as part of a gas network for the purpose of these regulations. 4.4 Incentives There are a number of financial incentives available for generators of biogas. A generator can claim support under either the Feed-in Tariff (FiT) or Renewables Obligation (RO) for
Biogas networks 25
electricity generation, and/or the Renewable Heat Incentive (RHI) for useful heat generation or biomethane injection to the grid. 4.4.1 Renewable Heat Incentive The RHI is the principal mechanism to increase the uptake of renewable heat in England, Scotland and Wales. It supports a range of heat technologies by providing a subsidy per kWhth of eligible heat generation for 20 years, and is the incentive scheme for biomethane injection into the gas network. The Government is responsible for the RHI legislation and tariffs, while Ofgem administers the scheme on behalf of Government, including registering participants, making payments, and ensuring compliance with the scheme rules. From April 2013, the tariff for biomethane injection to the gas network at any scale and biogas combustion (CHP) at <200kWth is 7.3 p/kWh, excluding any heat used in the production of the biogas at the plant, where this has come from an external source. Under the RHI regulations biogas becomes biomethane at the point it meets all of the conditions required to be suitable for conveyance through pipelines in accordance with a licence under section 7 of the Gas Act 1986. Ofgem considers that where more than one entity is involved in the production of biomethane, the entity which bears the cost of carrying out the final production process necessary to bring the biogas within the definition of biomethane is regarded as the „producer‟ for RHI purposes. If a biogas producer contracts with a third party to upgrade the biogas, then the biogas producer is the biomethane producer for the purpose of the RHI. To register for the RHI Biomethane tariff, the biomethane producer must supply Ofgem with:
a schematic diagram showing the process of biomethane production from the biogas
plant, and point of entry on the network;
assurance that the biogas is derived from biomass, this may include a description of
where the feedstock came from and what processes the feedstock have gone through,
and may be subject to independent verification;
assurance that the biomethane meets or is expected to meet all of the HSE requirements
on gas safety, and consumer protection requirements regarding Gross Calorific Value;
and
extracts of contracts and a NEA with the relevant GDN.
Biomethane injection into the gas network must comply with existing regulation, and registration under the RHI cannot be regarded as verifying compliance with other legislation. 4.4.2 Feed-in Tariff The Feed-in Tariff (FiT) scheme was introduced in April 2010 with the aim of encouraging small-scale (<5MW capacity) low carbon electricity generation by businesses, communities and local developments. The FiT provides a guaranteed price for electricity generated and a guaranteed payment for surplus electricity exported to the grid. There are two elements to the FiT:
generation tariff: an electricity supplier pays for each unit of electricity generated; this
tariff is fixed at the point of accreditation for 20 years and is RPI linked; and
export tariff: generator may receive a fixed payment for exporting surplus electricity to
the grid, or may take the market value.
Biogas networks 26
FiTs cannot be claimed for installations where a grant has been made from public funds towards any cost of purchasing or installing the installation. The tariff rates applicable to end March 2014 are included in Table 11. From April 2014, a degression mechanism will take effect, and will apply to all tariffs on the 1st April each year. The baseline annual degression rate will be 5%, however this will vary depending on the deployed capacity in the previous calendar year and can range from 2.5% to 20%, as illustrated in Table 12 and Table 13. In exceptional circumstances where there has been markedly high deployment of new generation capacity during the first six months of a calendar year tariffs may undergo a contingent degression. This would occur on the 1st October, based on deployment between 1st January and 30th June that year. Tariffs are published at least two months before the start of the FiT year or in the case of contingent degression by 1st August.
Table 11 UK Feed-in Tariffs from April 2013
p/kWh
Generation Tariffs
250kWe or less 15.16
250 – 500 kWe 14.02
Greater than 500kWe 9.24
Export Tariff
All scales 4.64
Table 12 Feed-in Tariff degression to apply to small scale (<500kW) AD installations from April 2014
Total installed capacity of relevant installations, 500kWe or less
Degression rate
Not more than 2.3 MW 2.5%
2.3 – 4.5 MW 5%
4.5 – 9.0 MW 10%
Greater than 9.0 MW 20%
Table 13 Feed-in Tariff degression to apply to large scale (>500kW) AD installations from April 2014
Total installed capacity of relevant installations, greater than 500kWe
Degression rate
Not more than 19.2 MW 2.5%
19.2 – 38.4 MW 5%
38.4 – 76.9 MW 10%
Greater than 76.9 MW 20%
4.4.3 Renewables Obligation The RO is currently the main financial mechanism by which the Government incentivises the deployment of large-scale renewable electricity generation. The scheme is open to all generators of 50kWe and above, but is intended to support technologies not eligible for FiTs
Biogas networks 27
and is typically not favourable for installations below 500kWe capacity. The RO is not considered in the cost benefit analysis as the FiT is more applicable to small scale farm AD. The RO will close to new generation on 31st March 2017, when the Electricity Market Reform (EMR) will provide the main platform for support.
Biogas networks 28
5.0 Cost Benefit Analysis The economics of the biogas network have been analysed for the test region comparing on-site CHP generation with the biogas network, central upgrading and injection of biomethane to the grid. The capital and operational costs of the AD plant are excluded from this comparison case study as they will be the same regardless of the downstream uses of the biogas. The test region includes a United Utilities waste water plant, where the centralised facility will be located. The plant has existing biogas capacity which could provide a base load for an upgrading plant, this is potentially a very low-cost resource. The upgrading plant modelled has capacity to process 630 m3/hr of biogas, and reflects current upgrading plant economics. At this scale the upgrading process may be a water wash or membrane separation. Sensitivity analysis considers the impact of capital cost reductions in the biogas upgrading plant, which may be expected as progress is made with surrounding regulation and more plants become operational. Under the RHI, the biomethane injection tariff becomes payable at the point that biomethane meets all of the conditions required to be suitable for conveyance through a pipeline under the Gas Act. The party responsible for biogas upgrading is therefore eligible for the RHI payment. 5.1 Cost to industry The following cost benefit analysis is carried out from the perspective of the farmer. The biogas network and upgrading plant is owned and operated by a third party. The cost and revenues associated with the biogas network and centralised facility are used to calculate the revenue stream that a farmer may receive per unit of biogas input into the biogas network. The central scenario considers a fully loaded upgrading plant, with capital costs for the biogas network and upgrading facility of £4 million. The capital is assumed to be financed over 7 years at an interest rate of 10% APR. The gross revenue for the biogas network and upgrading plant is calculated in Table 14, the potential revenue payable per unit of biogas is calculated in Table 15.
Table 14 Estimated biogas network and upgrading economics, central scenario
£/year Revenues
Biomethane export 674,110
RHI 2,225,036
Total 3,012,146
Costs
Clean up and upgrade plant opex (156,554)
BtG unit opex (4,113)
Propane value loss (145,536)
Capital inc. finance (816,662)
Gross revenue 1,889,279
Biogas networks 29
Table 15 Estimated potential revenue per unit of biogas, central scenario, £/m3
First 7 years of
operation
After capital is
repaid
BtG revenue 0.54 0.54
Opex network and BtG (0.06) (0.06)
Capital inc. finance (0.15)
Revenue 0.34 0.49
Under the central scenario the potential revenue per unit of biogas in the biogas network is estimated at 0.34 £/m3 rising to 0.49 £/m3 after the first seven years when the capital is repaid. A second low scenario was calculated to demonstrate the impact of more favourable financing terms, with capital repaid over 12 years, at an interest rate of 7% APR. Revenue per unit of biogas increases to 0.40 £/m3 over the first 12 years, rising to 0.49 £/m3 when the capital is repaid. This and other scenarios are illustrated in Table 16.
Table 16 Estimated potential revenue per unit biogas, various scenario, £/m3
Central scenario
Favorable finance terms
Low biogas flow
Reduced capital costs
BtG revenue 0.54 0.54 0.54 0.54
Opex network and BtG (0.06) (0.06) (0.06) (0.06)
Capital inc. finance (0.15) (0.09) (0.16) (0.07)
Revenue 0.34 0.40 0.32 0.42
It is likely that in the initial stages of the biogas network operation, the network and upgrading plant will not operate at full capacity. The impact of this is illustrated in the low biogas flow scenario, which assumes a biogas flow rate of 350 m3/hr, representing the biogas network operating at approximately 55% capacity. This scenario assumes finance is repaid over 12 years at an interest rate of 7% APR. Under this scenario the biogas revenues are reduced to 0.32 £/m3, representing a 20% reduction on the comparable scenario. The impact of reduced BtG installation costs is illustrated in the final scenario; reduced capital costs. Under this scenario the capital cost of the biogas network and upgrading plant are reduce by 25% from £4 million to £3 million, the impact is a potential 5% increase in revenue per unit of biogas, compared to the comparable favourable finance terms scenario. This capital cost could be further reduced by pursuing a centralised CHP facility, dependent on grid connection costs, heat distribution and use costs and scale of operation. 5.2 Business as usual comparison On-site CHP is recognised as the most appropriate comparison to biogas networks for the majority of small-scale farm AD plants. Biogas CHP is an established technology and the operators may claim incentives under the FiT for electricity generation and the RHI for any useful heat. This comparison assumes no heat use outside of the process, and 40% electrical efficiency.
Biogas networks 30
The analysis considers three representative farm scales with biogas flow rates of 29 – 111 m3/hr, as illustrated in Table 17. A breakdown of the costs and revenues associated with biogas CHP for a medium-scale farm are presented in Table 18, and the potential revenues per unit of biogas generation for the three farm scales are presented in Table 19. Finance is structured over 7 years with an interest rate of 10% APR.
Table 17 Farm scale AD scenarios for the CHP economic analysis
Small-scale Medium-scale
Large-scale
Cattlea head 200 400 700
Biogas generation m3/hr 29 55 111
CHP capacity kWe 66 129 257 awith 20 – 25 % maize silage
Table 18 Estimated biogas CHP economics, medium-scale farm
£/year
Revenues
Electricity export 57,052
FiT income 152,485
CCL 5,187
Total 214,725
Costs
CHP Opex (15,560)
CHP unit (installed) (155,950)
Capital inc. finance (32,033)
Gross revenue 187,133
Table 19: Estimated potential revenue for biogas CHP at various scales, per unit of biogas, £/m3
Small-scale Medium-scale
Large-scale
CHP revenue 0.44 0.44 0.44
Opex CHP (0.04) (0.03) (0.03)
Capital inc. finance (0.09) (0.07) (0.05)
Revenue 0.31 0.34 0.37
The results imply that CHP can generate similar revenues per unit of biogas for small-scale farms as for large-scale farms. The advantages of this is that additional CHP capacity can be added as biogas generation increases, reducing the need to invest all capital at the start, this can aid cash flow and reduce the risk of project development. However, it must be noted that this analysis does not include the cost associated with building and operating the AD plant which will be the same in both biogas use scenarios. The initial revenues from the biogas network central scenario are comparable to on-site biogas CHP at all scales. Over the first seven year period, it may be preferable for a farmer to select on-site CHP rather than join a biogas network, where especially in the early stages
Biogas networks 31
before the biogas network is operating at full capacity, the revenues may be more attractive, and the business case less complicated. However, over a longer term period of 20 years, the minimum expected lifetime of the AD and biogas upgrading plant, the revenues are greater for the biogas network at 0.49 £/m3. The lifetime of a biogas CHP plant is estimated at 10 years and therefore this longer term benefit is not as significant. The impact of FiT degression is presented in Table 20. If the FiT degression triggers are hit in 2014, then the biogas network and gas to grid option provides greater revenues per unit of biogas across all farm scales analysed from the outset, provided the biogas network is operating at full capacity. The centralised CHP facility may still be more favourable than on-site combustion, again dependent on peripheral power and heat use and distribution costs.
Table 20 Estimated potential revenue for biogas CHP with FiT degressions, £/m3
Small-scale Medium-scale Large-scale
10% 0.28 0.31 0.34
20% 0.25 0.28 0.30
5.3 Other associated financial benefits The value of digestate has not been considered as an income stream. Although the digestate carriers a fertiliser value greater than the raw slurry due to the increased availability of nitrogen, spreading also incurs a greater cost and the cost of spreading currently outweighs the value of the digestate; this will be the same regardless of the downstream uses of the biogas. 5.4 Environmental cost benefit analysis The environmental a social benefits of biogas networks compared to other uses of biogas are illustrated in Table 21. The biogas network performs well in terms of energy efficiency, carbon savings and resource management, only being met by on-site CHP with 100% heat use. Biogas network to a centralised CHP is more favourable than biomethane injection in rural areas, due to heat provision and a more positive direct impact on the rural economy.
Biogas networks 32
Table 21 Environmental and social impacts scorecard, biogas combustion and upgrading
Biogas networks 33
6.0 Options appraisal 6.1 Agricultural landscape 6.1.1 Livestock estimates For this project, we intended to identify farm clusters in the UK holding substantial numbers of livestock as a means to establish potential sites suitable for development of farm-based biogas networks. However, due to issues regarding the potential for data protection infringement it was only possible to source suitably disaggregated livestock data at the county level of resolution (NUTS3)10. It also proved difficult locating the relevant livestock data for Wales and Scotland. This review will therefore concentrate on providing an analysis of the agricultural landscape across English regions. Additionally, dairy cattle11 and pigs will provide the main focus on account that slurry from these livestock is easily and regularly collected through existing on-farm practices. All livestock data was obtained from the Cattle Tracing System (CTS), kindly provided by the British Cattle Movement Survey, the June 2010 DEFRA agricultural census and from statistics available from DairyCo12. The spatial distribution of dairy cattle across England is heavily weighted towards the west of the country (Figure 6), most notably in the South West, the North West and an area to the North of the West Midlands.
10 Defra‟s agricultural census does hold livestock information for local authorities (NUTS4) although, crucially, the data held for cattle is not separated into beef and dairy herds.
11 For this report considered as a female dairy cattle over two years old with offspring
12 http://www.dairyco.org.uk/
Biogas networks 34
Figure 6 Dairy cattle livestock densities for NUTS3 regions (A) and 5 km2 areas (B)13 in England
The South West alone is responsible for over a third of the England dairy herd. Dairy farming is widespread throughout the region with high numbers of dairy holdings stretching from Cornwall to Wiltshire and South Gloucestershire. Devon holds the greatest total number of dairy cattle of any English unitary authority (Table 22). However, the county is one of the largest in the UK at over 6,500 km2 and consequently Cornwall, Somerset and Dorset all have higher densities of dairy cattle. A region comprising the North West Midlands (Shropshire and Staffordshire), West Derbyshire and Cheshire is responsible for a further quarter of the national dairy herd. Farming is particularly intensive in Cheshire where density of the livestock is nearly twice that of any other English county having almost 50 dairy cattle per km2 across the entire region. The North West (Cumbria and Lancashire) also contributes significantly to dairy farming in the UK and is responsible for around 15% of the dairy herd in England.
13 Defra, Agricultural Atlas, June 2010
A B
Biogas networks 35
Table 22 Numbers of dairy cattle and commercial dairy holdings for NUTS3 regions in England with the greatest dairy populations, 201014
County Number of livestock Number of Commercial holdings
Devon 130,279 920
Cheshire 93,368 566
Somerset 85,812 552
Cornwall 74,224 518
Staffordshire 72,318 565
East Cumbria 70,959 450
Shropshire 60,455 401
Dorset 58,702 337
West Cumbria 37,445 261
When establishing the potential for the development of biogas networks consisting primarily of slurry-fed digesters it is also important to consider herd sizes of dairy cattle. Dairy holdings with small numbers of cattle will be unable to provide sufficient slurry. It is far more likely that holdings comprising larger herds (>300 livestock) will show interest in the development of biogas networks. Smaller farms might be able to contribute to biogas networks comprising of a single, centralised, digester for which a number of surrounding farms provide feedstock, however this adds regulatory complexity. For England counties with greatest numbers of dairy cattle, holdings with herd sizes above 300 livestock constitute 6 – 10% of all holdings. Average herd sizes are greatest in Dorset with 174 dairy cattle per holding while are lowest in Staffordshire (Table 23). As might be expected, Devon and Cheshire have the greatest number of holdings with more than 300 dairy cattle with 72 and 89 holdings respectively.
Table 23 Numbers of dairy cattle holdings for given herd sizes in English counties with the greatest dairy populations, 201115
County <100 Livestock
101 to 300 Livestock
301 to 500 Livestock
>500 Livestock
Total Average Herd size
Cumbria 333 473 48 9 863 151
Cheshire 293 338 52 20 703 165
Shropshire 193 263 38 6 500 151
Staffordshire 320 284 43 4 651 128
Somerset 258 337 44 11 650 155
Dorset 154 235 26 12 427 174
Devon 478 528 65 24 1095 142
Cornwall 290 274 36 14 614 143
In contrast to dairy farming, holdings for pig livestock are more commonly situated in the East of England (Figure 7). The Yorkshire & Humber region and East Anglia are the two dominant areas of pig farming in the UK.
14 Defra, Agricultural census, June 2010
15 Cattle Tracing System
Biogas networks 36
Pig livestock holdings are widespread throughout Yorkshire; substantial numbers of livestock are present in North Lincolnshire and North Yorkshire (leading into South Teesside). North Yorkshire has more than 600,000 pigs in commercial holdings, more than any other English county (Table 24). However, the greatest density of pig livestock in this region, and indeed in all of England, can be found in the East Riding of Yorkshire. Cumulatively, this region is responsible for around one third of the national pig herd in England. Norfolk and Suffolk also have a substantial number of pig livestock holdings and together the two counties hold nearly 1 million pigs, amounting to almost one third of the English pig herd. Livestock densities are fairly consistent throughout the region although they are slightly greater in Suffolk than in Norfolk.
Figure 7 Pig livestock densities for NUTS3 regions (A) and 5 km2 areas (B)16 in England
Table 24 Numbers of pig livestock for NUTS3 regions in England with greatest pig populations, 201017
County Number of livestock
North Yorkshire 596,786
Norfolk 534,754
East Riding of Yorkshire 434,146
Suffolk 402,329
North Lincolnshire 70,420
16 Defra, Agricultural Atlas, June 2010
17 Defra , Agricultural census, June 2010
A B
Biogas networks 37
6.1.2 Manure estimates To establish the required number of livestock to feed a biogas network operating at a high enough biogas flow rate for the system to be viable, it was necessary to estimate manure production rates and collectible volumes. Calculations are based on average national dairy cattle and pig herds such that any potential differences in regional variation are not accounted for. An estimate of available volumes of manure for those counties where dairy farming is most extensive is provided in Table 25, and the counties in which pig farming is most extensive in Table 26, as calculated by the methodologies described in Appendix 1.
Table 25 Manure production by dairy cattle for NUTS3 regions in England
County Available manure (kt/year) Available manure (t/km2/year)
Devon 1,753 261
Cheshire 1,256 627
Somerset 1,154 335
Cornwall 999 280
Staffordshire 973 371
East Cumbria 954 202
Shropshire 813 254
Dorset 789 298
West Cumbria 503 246
Table 26 Manure production by pigs for NUTS3 regions in England
County Available manure (kt/year)
Available manure (t/km2/year)
North Yorkshire 888 111
Norfolk 756 141
East Riding of Yorkshire 626 252
Suffolk 588 155
North Lincolnshire 102 98
Combining the estimates for manure production by dairy cattle and pig livestock gives an indication of regions in England most likely to be suitable for establishing AD networks using primarily slurry-fed systems. The distribution of manure production is more heavily weighted to the West of the country on account of the larger volumes of slurry produced, in general, from dairy farming over pig farming (Figure 8). Greatest volumes of manure, per unit area, are produced in Cheshire while substantial quantities are also available in Staffordshire. Somerset, Dorset and Lancashire are also key regions where substantial volumes of slurry could be considered to be available. These regions are therefore those that are most likely to be suitable for targeting development of AD networks in England. 6.1.3 Feasibility for slurry-fed AD networks Slurry-fed AD systems generally produce in the region of 15 to 25 m3 of biogas per tonne of feedstock. In light of the high cost of capital for developing centralised biogas conversion facilities, it is reported that biomethane injection into the grid only becomes economically viable for systems capable of achieving biogas flow rates greater than ~400 m3/hr. The
Biogas networks 38
volumes of manure required to ensure a viable slurry-fed AD network is estimated at 175,000 tonnes per annum. This equates to around 13,000 dairy cattle (when 65% of manure is collected), 11,000 dairy cattle (when 75% of manure is collected) or 120,000 pigs.
Figure 8 Available manure from dairy cattle and pig farming for NUTS3 regions in England
At the level of resolution analysed in this study it cannot be discounted that there are areas in the UK where such numbers of livestock exist; each of the top eight counties where dairy farming is most extensive have a sufficient number of dairy cattle in herds above 300 livestock while the counties of Norfolk, Suffolk, East Riding and North Yorkshire each have a sufficient number of pigs. However, more detailed analysis of the location of the farms is necessary to determine if the farms are close enough to one another to consider a biogas network comprising of slurry only-fed AD units as a viable option. It is likely that, in order to make rural networks viable supplementary feedstocks would be required in the AD plants to increase biogas output, or additional non-slurry facilities, such as food waste facilities or sewage works, would need to join the network. Including 10% crop silage (by weight) could potentially reduce the required numbers of dairy cattle for achieving a biogas flow rate of 400 m3/hr to just over 5,000, with the network requiring 9,200 tonnes of silage annually. Assuming that all of the crop feedstock is provided by maize18, and that on average 45 fresh tonnes is yielded annually per hectare19, this would equate to the use of 205 hectares. Increasing the ratio of the silage to 25% (13,500 tonnes silage per year, 300 hectares) would reduce the required cattle numbers to around 2,500. When considering pig farming, achieving a biogas flow rate of 400 m3/hr
18 Other crops such as grass, wholecrop cereals and fodder beet are also expected to contribute but the data is not sufficiently
disaggregated discern relative contribution. Consequently, only a rough indication of required cropping area is provided. 19 Yields vary between 35 and 55 t/ha and are typically in the region of 40 to 50 t/ha.
Biogas networks 39
with a 10% silage feedstock would require 58,000 livestock while a ratio of 25% silage would require livestock numbers of around 28,000. It is very likely that clusters of farms exist in the UK which have the numbers of livestock required for a development of AD networks using a feedstock composition consisting of 25% silage and 75% manure. Whether these clusters will be viable for development of such networks will depend on the amount of land in the surrounding areas available for growing the necessary volumes of silage and political attitude to this approach. Concerns over using agricultural land for means other than food production are growing. However, by using lower grade land for cropping, break crops or excess silage, the risk for AD systems being impacted by any potential developments in policy is substantially reduced. As an alternate possibility to adjusting feedstock composition for farm-based AD plants, AD networks could be developed using slurry-fed AD plants complimented with a contribution of biogas from nearby sewage works or other facilities where such locations exist. While there are numerous sewage works already installed with AD systems and CHP engines, often these facilities generate surplus biogas as they are limited by the amount of electricity they can export to the grid or continuity of biogas they can generate. Therefore, some sewage facilities are looking to expand their AD portfolio and develop biogas upgrading and injection systems or supplement biogas production from external sources. Given that these facilities are likely to produce flow rates far greater than farm-based AD units, there is the possibility of developing AD networks with a partnership agreement formed between a sewage facility and nearby farms. 6.2 AD potential There are a growing number of AD technology providers with products specifically targeted towards small-scale farm-fed AD systems. Our market analysis identified six technology providers promoting AD systems in the UK that may be suitable for a diet based entirely or largely on animal slurries (Table 27).
Table 27 Small scale AD technology providers
Technology Provider
Details
Evergreen Gas Scale 25 – 50 kWe, 2 UK plants in operation Small scale modular AD plants designed for a variety of feedstocks including slurry-only systems. The partially buried, plug-flow digesters are based on a simplified design to minimise costs. Evergreen Gas design and build plants and offer on-going maintenance, monitoring and optimisation services. AD operators are trained by Evergreen Gas during the commissioning and hand over period. Minimal labour input is required once operational, a single 30 min daily inspection should be sufficient. Evergreen Gas is developing a small scale biogas upgrading for transport concept, funded under DIAD. A feasibility study was completed in 2012, and the demonstration plant is under construction. The demonstration plant will produce 5 m3/h of
Biogas networks 40
biomethane. Typical commercial scale is estimated at 40m3/h biomethane. This concept is complimentary as it progresses small scale biogas cleaning and upgrading, although it may also be a competing market for biogas generated in rural areas.
Biogas Nord Scale 75 – 2,000 kWe, more than 400 operational plants across Europe BiNoMiniMax is a small scale compact digester, including one or more concrete digesters through which the substrates are continuously pumped. Digesters are fitted with up to four stirring devices and double-membrane roofs for gas storage. Wall and floor heaters are installed inside the concrete walls of the digester. Biogas Nord design and build plants and offer technical servicing and maintenance contracts, and biological monitoring and optimisation. They also assist with project financing, providing contacts and assisting with the financing procedure or grant applications, and provide insurance.
AgriKomp Scale 30 – 2,500 kWe, more than 600 operational plants across Europe Offer customised plants range from 100 kWe to 2.5MWe, and may be designed to use a range of feedstocks or feedstock combinations. AgriKomp design plants using their own components and may install plants or provide technology for farmers to install. AgriKOMPAKT is a modular slurry-only system that may be integrated into existing slurry infrastructure with fast installation. Suitable for farms with 150 cattle or 200 pigs, with capacity of 30 – 70 kWe. Produce components, design, and build plants. Farmers may alternatively carry out a substantial part of the build themselves. AgriKomp also offer servicing, remote monitoring and diagnostics, maintenance, laboratory testing, and replacement parts.
CH4e Ltd Scale 50 – 250 kWe, first plant in commissioning phase Split phase AD system in horizontal tanks, modular design, unique heating and stirring system. Quick and easy to assemble Automated processes controlled remotely. CH4e plan to build, owner and operate the AD plant, leasing the land form the farmer who would also supply feedstocks and take digestate. Therefore minimum impact on existing operations, minimum requirement for farmer – no maintenance, minimum feed in.
BioWaz Scale 15 – 1,000 kWe, 5 operational plants across Europe Modular pre-fabricated turn-key units, developed in Scandinavia to digest animal manures and slurries supplemented with plant biomass. Digesters range in volume from 130 to 550 m3, may operate as a single tank or multiple tank process, and may be fully or partially
Biogas networks 41
buried. Containerised control rooms provided. Manure is pumped in and out of the digester by a predefined operating programme. BioWaz offer CHP units of between 15kWe and 1MWe capacity, and biogas upgrading and compression modules, to supply Bio-CNG (95% biomethane content). BioWaz provide and install standardised systems. 10 – 20 minutes daily supervision required.
Marches Biogas Scale 25 – 2,000 kWe, 6 plants in operation in the UK Each plant designed on an individual basis to meet the feedstocks and plant specifications. Continuously stirred tank reactor (CSTR) is suitable for on-farm use at 50 – 1,000 kWe. A conventional above ground steel tank with fixed roof and separate membrane gas holder. AGRIDigestore is designed for integration with farm slurry infrastructure. May be retrofitted to existing slurry tanks, at up to 50kWe capacity. Plug and play is a prefabricated modular system for on-farm slurry systems. Designed for quick installation and minimal disruption. Up to 50kWe.
The technologies reviewed for small-scale farm-based feedstocks were typically continuous, mesophilic processes and largely or fully automated. The systems were designed to minimise the capital and operational costs per unit output, whilst also minimising the on-going operational requirement, in terms of both time and expertise, and impact on farm operations and existing businesses. The majority of products are modular systems, which simplifies the design and build stages of project development, potentially reducing development times. Each of the systems included CHP, and range in scale from around 25 kWe output, equivalent to a biogas flow rate of 12.5 m3/hr. This analysis demonstrates that it is unlikely that access to appropriate AD technology will act as a barrier to the role out of biogas networks. Technology providers were largely supportive of the biogas network concept; the major concerns raised were meeting the heat demand of the digester, particularly for a slurry-only system with high moisture content and therefore high heat demand. 6.3 IP issues We have concluded that there are no intellectual property issues to consider regarding biogas networks. 6.4 Commercialisation plan This feasibility study has not developed a product for commercialisation as such, but rather an alternative business model for small-scale biogas production in rural areas, using established technology in an innovative way. Establishment of biogas networks could increase AD uptake in the agricultural sector by providing a market and attractive revenues for biogas for farms that may not otherwise consider AD economically viable. A decision making tool is provided in Appendix 2 to aid farm-fed AD developers in deciding whether to pursue the biogas network option.
Biogas networks 42
An economic analysis of three farm scale AD plants is outlined in Table 28 for the purpose of illustrating at what scale the installation of AD and connection to a biogas network may become attractive.
Table 28 Economic analysis for farm scale AD receiving biogas network tariffs
small farm
medium farm
large farm
Cows 200 400 700
Total slurry tpa 3,869 7,738 13,542
Maize tpa 967 1,935 3,385
Production t/ha/yr 40 40 40
Cost £/t 30 30 30
Land demand ha 24 48 85
Crop ratio % 20% 20% 20%
Biogas output m3/yr 270,830 541,660 947,905
m3/hr 31 62 108
ENERGY GENERATION
Losses 10% 10% 10%
Total Energy Generated kWh/yr 1,637,980 3,275,960 5,732,929
Parasitic Load
Electricity demand kWhe/tonne 5 5 5
Heat demand kWhth /yr 196,558 393,115 687,952
Biomethane to grid
Biomethane export m3/yr 214,497 428,995 750,741
Energy content of gas for export
kWh/yr 1,441,422 2,882,845 5,044,978
CAPEX
Retention time days 35 35 35
Minimum digester size m3 464 928 1,623
Capital AD inc. installation £ 450,000 850,000 1,300,000
Depreciation yrs 20 20 20
Total capital £/kWth 2,407 2,273 1,986
£/year 22,500 42,500 65,000
OPEX
Operational costs £/yr 4500 6,750 11,000
Maintenance costs £/yr 4,500 8,500 13,000
Feedstock costs £/yr 29,018 58,035 101,561
Total Opex £/yr 38,018 73,285 125,561
REVENUES
Biogas network tariff £/m3 0.415 0.415 0.415
Total revenue £/yr 89,016 178,033 311,557
Profit & Loss £/yr 28,499 62,248 120,996
Return on capital 6.33% 7.32% 9.31%
The calculations assume the AD plant has a heat demand equivalent to 12% of the energy content of the biogas produced. The biogas network tariff is taken as the mid-point between the initial revenue, calculated for the first 7 years and the revenue calculated after the capital is repaid, under the central scenario. The analysis illustrates that for a large dairy farm of 700 cattle, using mostly slurry supplemented with 20% silage, the biogas
Biogas networks 43
network model is beginning to become attractive, with a return on capital of 9.3%. The small farm case, which represents the scale of most dairy farms in the UK, and the medium scale farm achieve less attractive rates of return of 6.3% and 7.3% respectively. Where excess heat is available on farm, as a result of other processes, the rates of return for the small and medium scale farms increase to 9.0% and 10.2% respectively. Under such conditions, farms with greater than 400 cattle and some supplementary feedstocks may consider the biogas network concept attractive, provided the correct local conditions are met. The agricultural landscape appraisal identified five counties with greater than 10 dairy herds over 500 cattle; Devon, Cheshire, Cornwall, Dorset and Somerset. Each of these counties also has a greater number (26 - 65) of dairy cattle holdings of between 300 and 500 cattle as illustrated in Table 29. The selection of a site for demonstration will focus on these areas, and will investigate the proximity of farms, the capacity of the GDN or electricity grid, alternative uses of biogas, for example heat demands, and existing biogas producers. The second priority will be the counties of the East Riding of Yorkshire, Norfolk and North Yorkshire, which all have pig livestock numbers of greater than 400,000. The East Riding of Yorkshire and Norfolk in particular have areas of very high population density. Subject to successful demonstration of the biogas network concept and suitable dissemination it may be feasible to establish rural biogas networks in each of these counties. In order to estimate the potential roll out of biogas networks in England, we focus on the regions with greatest dairy cattle numbers. An estimate of the potential capacity for rural biogas networks in England is calculated in Table 29. This calculation is based on a capture rate of 10% of farms with a dairy herd of 301 – 500 livestock, and 30% of farms with over 500 livestock. Livestock numbers are calculated based on the lower boundary limit. The amount of slurry captured for AD is 364,000 tpa, supplemented with 25% silage, this results in total biogas production of over 25 million m3 per year, equivalent to 171 GWh per year. There is greater uncertainty over the potential for pig-slurry based systems, due to factors such as a lack of information on the distribution of herd sizes, therefore no estimate has been made for this sector at this time.
Table 29 Estimated potential capacity for rural biogas networks in England Slurry Silage Total biogas generation
Biogas Biogas
tpa m3/year tpa m3/year m3/yr MWh/yr
Devon 107,365 2,147,295 26,841 5,368,238 7,515,533 50,504
Cheshire 88,213 1,764,264 22,053 4,410,660 6,174,924 41,495
Cornwall 61,517 1,230,342 15,379 3,075,855 4,306,197 28,938
Dorset 49,910 998,202 12,478 2,495,505 3,493,707 23,478
Somerset 57,455 1,149,093 14,364 2,872,733 4,021,826 27,027
Total 364,460 7,289,196 91,115 18,222,990 25,512,186 171,442
Biogas networks 44
7.0 Conclusions As a result of the EMIB Review Group activities, good progress has been made in reducing the cost for grid injection of biomethane. However, the capital costs for biogas upgrading remain high meaning that certain economies of scale are necessary for biomethane injection to the grid to be possible. The biogas network concept could enable a greater number of biogas producers to make more efficient use of biogas by providing access to centralised biogas upgrading and biomethane injection facilities, or more favourably centralised CHP facilities, where a heat offtake and reasonable electricity grid connection point exists. The financial incentives (FiTs and RHI) provide attractive returns for efficient use of biogas operating at economies of scale, and activities such as the IGEM developing a standard for biogas pipeline, has assisted in the development of a draft design for a biogas network for biomethane injection in a test region in Crewe, in the North West of England. The engineering study carried out as part of this feasibility study provides estimated capital and operational costs for the biogas pipeline and the equipment required to condition raw biogas to the specification of the biogas network, the so called biogas input station. The cost benefit analysis demonstrates that initial revenues from the biogas network are comparable to biogas on-site CHP at all farm scales. Over the first seven year period, it may be preferable for a farmer to select on-site CHP rather than join a biogas network, where the revenues may be more attractive, and the business case less complicated. However, over a longer term period of 20 years, the minimum expected lifetime of the AD and network facilities, the revenues are greater for the biogas network. However, several risks have been identified in relation to developing biogas networks, the most severe being securing sufficient biogas flows to allow a biogas upgrading facility to operate at designed capacity. Due to the nature of the biogas network, with many biogas producers, the timing of individual investment decisions must be coordinated to reduce the risk to each individual. Demonstration activities to prepare and confirm the regulatory and political landscape for biogas networks, and effective dissemination would help to mitigate such risks. The possibility of FiT degression would further strengthen the business case for biogas networks to biomethane injection in the future; however in the short- to mid-term biogas networks to centralised CHP appear more attractive. Several regions have been identified as potential candidates for biogas networks, based on the density and scale of dairy and pig farms. These are Devon, Cheshire, Cornwall, Dorset and Somerset, and potentially the East Riding of Yorkshire and Norfolk. Further research is necessary to confirm this potential, specifically it would be advisable to:
determine the location of large scale dairy or pig farms, and their proximity to one
another;
determine grid injection capacity with the GDN or DNO;
identify local uses of biogas, for example heat demands that may favour biogas boilers or
CHP; and
identify any existing biogas producers that could provide a useful base load.
Biogas networks 45
8.0 Phase 2: Demonstration 8.1 Objectives Phase 2 is intended to deliver the UKs first biogas network connecting a number of farms and other suitable sites to a centralised biogas conversion facility. The objectives of Phase 2 are:
to demonstrate the viability of a biogas network in the UK;
to encourage uptake and improve efficiency of small-scale AD plants in other regions;
to encourage collaboration and sharing of best practice between farmers and other
businesses in rural areas for maximum economic and environmental gain; and
to prepare and confirm the regulatory and political landscape for biogas networks.
8.2 Methodology 8.2.1 Project outline An opportunity to demonstrate the biogas network concept has been identified in the South West of England. The network includes three farms each installing an on-site AD and small CHP to meet on-site heat and electricity demand. The three AD plants will be linked together by biogas pipeline allowing excess biogas to be piped to a centralised CHP, where the electricity will be exported to the national grid and heat will be used in poultry sheds. Each farm (named F1, F2 and F3) will host an on-site CHP of up to 499kWe, which will operate at full capacity in order to receive the higher FiT payment, and will supply their own on-site heat and power demand. Excess biogas will be transported via the biogas network from F1 and F2 to a further central 1MWe CHP plant at F3, which is located close to a potential grid connection point with capacity for up to 2.3MWe of generation. In addition to the biogas pipeline, it is proposed that the farms will also be connected by a feedstock or digestate balancing pipeline and a private HV cable, so that excess electricity generated by the on-farm CHPs may also be transferred to F3 and exported to the national grid at the one central connection point. Utilising pipelines will make the transfer of feedstock and digestate between AD plants possible, to ensure each facility continues to operate at capacity all year round, as well as economising on tractor and tanker movements which is a common planning concern. The central site (F3 Farm) also hosts a large range of poultry sheds, offering an offtake for the heat from the centralised CHP facility. This network allows each plant to optimise their digestion efficiency, producing maximum volumes of biogas whilst not individually requiring a large on-site CHP from which the majority of heat would be wasted. The 1MWe balancing CHP will accommodate all surplus biogas generated on each contributing site and will produce all the necessary heat for the poultry units. This system maximises individual digester capacity, optimises the use of the outputs and utilises all the calorific value in the biogas without the need for flaring any surplus. In addition to the physical development activities described above a programme of further research will be undertaken to identify other network opportunities for centralised CHP or upgrading facilities throughout the UK. A programme of outreach via written and verbal communications will run in parallel to the physical development activities, to further promote the concept and increase uptake of AD in rural areas across the UK. Such activities will include email and postal communications, presentations by the project team at external
Biogas networks 46
events, conferences and farmer discussion group meetings and coordination of dedicated meetings and workshops to further explain and promote the opportunity and to bring local networks together. The final activity will be the development of a Design Manual for the network concept. This will run in parallel to the design and demonstration activities and will include relevant standards, application guidance (for FITs, RHI, planning, permitting, etc), templates and useful supporting documentation for future developers and network participants. 8.2.2 Responsibilities and ownership The first network will follow a simple ownership model whereby each of the contributing farms takes responsibility for planning, design, procurement, construction, commissioning, maintenance and monitoring of their individual AD unit. Each farm is already in advanced discussions with their preferred technology provider and is committed to undertaking this development. All costs associated with the AD development, on-site CHP units, biogas cleaning and monitoring equipment will be covered by the individual host farmers. The farmers will also then benefit from the FITs and RHI payment which they are entitled to, for generation from their on-site CHP facility as their facilities will not be perceived as being grant supported. Summaries of each the farms contributions are provided below: F1 Large dairy farm with 1,000 cows providing 22,500 tonnes of slurry and 5,000 tonnes of FYM year round and 530ha of land. This site has little requirement for heat on-site and no electricity grid connection available; surplus electricity will be transferred via the HV cable to F3. The site also has existing storage available for digestate and any crops that may be required to supplement the slurry in the system as well as sufficient land available for spreading their own and any surplus digestate. Feedstock and land is guaranteed for 20 years. F2 Medium-sized dairy farm producing 6,000 tonnes of slurry and 2,000 tonnes of FYM each year with 80ha of land. This site has little requirement for heat on-site and no electricity grid connection available; electricity will be transferred via the HV cable to F3. Feedstock and land is guaranteed for 20 years. F3 Broiler farm with 1,000 tonnes of poultry manure available for digestion and a significant heat demand from the poultry sheds. This site has ample space available for the centralised development and associated infrastructure, including possibly a centralised digestate drying facility which may be introduced at a later stage. Feedstock and land is guaranteed for 20 years. The BIS, biogas pipeline and centralised CHP facility will be owned, operated, maintained and monitored by Greener for Life Energy (GfLE). GfLE will also be responsible for the planning, design, procurement, construction and commissioning of this centralised facility, with support from CNG services Ltd. Greener for Life is a specialist company devoted to sustainable food and energy production. Under the Greener for Life brand, it accredits food production to high welfare, environmental
Biogas networks 47
and social standards. It also deploys renewable energy systems such as Wind, PV and anaerobic digestion so that farmers and the supply chain can achieve true closed looped production of food and energy. Greener for Life Energy (GfLE) focuses purely on Anaerobic Digestion for the agricultural sector. GfLE has developed high rate of return AD systems for both CHP and upgrade for injection to grid. Full packages are available from feasibility, planning, finance, build, operate, maintain and energy sales. Under the Greener for Life model, attractive long term markets are sought and developed for the energy sales from the generating plants, renewable fertiliser is generated for farmers to grow Greener for Life food products and above all, profitable integrated farming and energy systems are developed. The cost of the biogas pipeline is calculated based on a maximum biogas flow rate of 600 Sm3/h and with a maximum pressure of 400 mBar. 8.2.3 Detailed project plan Each work package will have a clearly defined lead responsible for reporting to the Project Manager at the end of each month as a minimum. Project reports will highlight any problems or issues and allow close monitoring of delivery. At specific periods reporting to the Project Manager will be more frequent.
Table 30 Project decription
WP Description Outputs
1 Project management:
The project will be managed by NNFCC who will take full responsibility for work package coordination, task distribution, deliverables and reporting.
a) Kick-off meeting
b) Monthly written progress
report to WRAP
c) Quarterly progress meetings
with WRAP
This task will run for 18 months (Oct 2013 – Mar 2015)
2 Network Design & Planning:
Biogas network design and procurement will be performed by CNG Services Ltd. NNFCC will support CNG with this task by preparing „standard‟ documentation for the planning stage, supporting pre-accreditation applications to Ofgem for FIT/RHI and to satisfy HSE requirements for assisting this and subsequent networks.
a) Finalised designs and
network specifications
b) Design Manual for future
networks including guidance,
supporting documents and
templates
This task will run for 6 months (Oct 2013 –Mar 2014)
3 Network Construction & Commissioning:
Construction and full commissioning of the biogas network and centralised CHP facility, connected to a heat distribution network to supply heat to the poultry units.
a) Fully operational network, in
line with drawings and
design
b) Monitoring activities to be
confirmed
This task will run for 9 months (Apr 2014 – Dec 2014)
4 Further Research & Dissemination: a) List of other potential
Biogas networks 48
Further desk-based research to be undertaken alongside industry discussions, to identify opportunities for other networks in the UK. Written and verbal communications to be prepared including factsheets, web page, decision tree and PowerPoint presentation. Existing outreach avenues to be identified including exhibitions, trade fairs, workshops, conferences, breakfast meetings, etc. A series of networking workshops to be coordinated in key regions as well as a site open day to bring potential network partners together, and to share knowledge and best practice. Finally a joint event will be planned with the GDNs to promote the concept more widely than just CHP as a biomethane injection solution.
network facilities in the UK
b) Written communications to
rural networks, farming
groups and potential future
participants
c) List of suitable events for
promotion of concept
d) Workshops in 3 – 5 regions
where network potential is
evident
e) Joint event with Gas
Distribution Networks
(GDNs) to promote the
concept for biomethane
This task will run for 15 months (Oct 2013 – Dec 2015)
5 Monitoring
CNG Services will monitor network performance and capture lessons learned, to improve performance, efficiency and functioning of future networks. Interest in and uptake of subsequent networks will also be monitored by NNFCC.
a) Results of this activity will be
presented as part of the final
report
This task will run for 3 months (Jan 2015 – Apr 2015)
6 Reporting
A formal interim progress report will be submitted upon completion of the design & planning stage encompassing further research and an outreach plan. A final report will be submitted upon completion of the project encompassing outcomes from outreach activities and initial monitoring results.
a) Interim progress report
b) Final report
This task will run for 18 months (Oct 2013 – Mar 2015)
8.2.4 Detailed project timeline The entire project is expected to take 18 months from approval to commissioning. The AD facilities are likely to go ahead even without the demonstration support and in this instance would be restricted to smaller-scale and reduced efficiency on-site CHP only. Each owner has identified a preferred supplier and had draft on-site designs drawn up. Planning applications are expected to be submitted through the summer 2013 prior to demonstration phase funding approval. No planning issues are foreseen and therefore the timeline below should be applicable.
Biogas networks 49
Pro
ject M
anagem
ent (W
P1) a
nd O
utre
ach
Activ
ities (W
P4)
Figure 11 Proposed project timeline
Q3 2013
• NETWORK DESIGN & PLANNING (WP2)
• Planning consent awarded for ADs, and network approval
• Discussions ongoing with technology providers
• Permitting requirements discussed with EA
• Project financing arrangements confirmed
Q4 2013
• Contracts drawn up and signed for network committment
• Asset procurement for AD and network facilities
• Biogas network designs and specification approved
• Network Entry Agreement issued by GDN
• Pre-accreditation applications for FITs submitted (by 31st Dec)
Q1-Q2 2014
• NETWORK CONSTRUCTION & COMMISSIONING (WP3)
• Construction of ADs, network facilities and centralised CHP facility
• Grid connection made and HV cable laid for electricity transfer
• PPAs or alternative energy purchase arrangements made via GfLE
Q3 2014
• Permit applications made to EA for each individual site
• Biological commissioning of AD facilities
• Subsequent commissioning of on-site CHPs, network and centralised CHP
• FIT and RHI accreditation applied for
Q1 2015
• MONITORING (WP5)
• Ongoing monitoring programme on network performance and efficiency commences
• Ongoing monitoring of interest or uptake of additional networks following a series of outreach activities
Biogas networks 50
8.2.5 Milestones
As well as regular routine reporting, providing monthly written updates to WRAP, the following will form key milestones in the delivery of this project.
Table 31 Project milestones
Milestone Description Due
1 Kick-off meeting October 2013
2 Final designs & specifications December 2013
3 Design Manual & Interim report (incl. outreach plan) March 2014
4 Holding of 3 – 5 workshops and attendance at events October 2014
5 Network commissioning December 2014
6 Site open day March 2015
7 Final report March 2015
8.2.6 Risk assessment A key step in the feasibility study was to identify risks and suitable mitigation actions for the demonstration and subsequent roll out of biogas networks across the UK. The table below highlights risk and mitigation actions that will be taken to minimise and eliminate risks.
Table 32 Risk and mitigation actions that will be taken to minimise and eliminate risks Risk Likelihood Mitigation Severity
AD plant developments
refused planning permission,
delayed or cancelled due to other factors
Medium Finance options in place for each plant and
feedstock guarantees in place for 20 years.
Planning decision on F3 expected 25th June and planning applications for the remaining
farms to be submitted 1st July.
Planning consent for biogas networks not
believed to be required but will be discussed with Council at early stage.
High
Land access issues for laying
biogas pipeline
Low Land through which pipelines will be laid is
owned by either the host sites or neighbouring farmers – all of whom are
aware of the plans and have agreed in principle to provide reasonable access.
High
Risk assessment of the biogas
network is not accepted and it is deemed necessary to inject
an odorant into biogas prior to injection into the network
Low Evidence from EU and IGEM Standard will
be utilised to ensure designs adhere to pre-defined standards and the team will
work with the relevant regulating bodies throughout.
Medium/
High
Environmental permitting
issues with burning biogas remote from site of generation
Low Early discussions to be held with the
Environment Agency; however, no issues are foreseen.
Medium
Delayed delivery due to illness
or unforeseen circumstances
Low No task is entirely reliant on a single
member of staff; progress and delivery will be monitored by Project Manager.
Low
Biogas networks 51
8.3 Project cost and financing We expect capital costs associated with the AD and on-site CHP, biogas cleaning and measurement equipment associated with on-site use and the feedstock or digestate balancing pipeline will be funded by the farmers. Finance options are being progressed by the farms in question and Greener for Life Energy. The biogas network and centralised CHP facility will be owned and part-financed by Greener for Life Energy. However, as this is a first-of-a-kind facility we are asking for a contribution from WRAP to support the additional time and material requirements necessary to demonstrate the network „proof of concept‟ and to ensure standards, specifications and planning or permitting conditions are met or even exceeded. It is essential this facility is replicable yet highly successful and well respected in order to ensure good uptake and future roll out of additional networks across the UK. The costs are broken down in more detail below and details of the contribution sought from WRAP are clearly highlighted. As part of the Phase 1 activities NNFCC have verified with Ofgem that heat and power from this network concept will be eligible for FITs and RHI and as the contribution sought from WRAP focusses on the network components rather than the generating station or installation there is not expected to be any conflict regarding grant funding and incentives. Detailed cost breakdown Estimated total material cost of the biogas network is £310k, comprising:
biogas pipelines = £150K; and
biogas conditioning (blowers, chillers, H2S removal) - £80K at each of the two
contributing farms (F1 and F2) = £160k.
The contribution sought from WRAP towards the material costs is 35% of the total additional costs, over and above what would be incurred by the facilities should they proceed independently with on-site CHP only. The total contribution sought for this element is £108,500 + VAT; the balance (65%) would be funded by Greener for Life Energy and the contributing farmers. The costs have been split this way to ensure all network participants make balanced contributions, and are still able to operate a commercially viable plant with returns greater than those they would have generated by developing independently at a smaller-scale. The resultant impact on the wider industry in terms of energy contribution efficiency is significant, delivering excellent value for money. Additional funding is sought from WRAP specifically for identification of further possible network opportunities, the demonstration and project management activity and dissemination, so as to accelerate roll-out and uptake of the biogas network concept nationwide. This activity is detailed in the project plan above. The contribution sought from WRAP for the dissemination, further research and overarching project management activities (for design, build and dissemination) is £78,437.50 + VAT. The combined total sought from WRAP to enable this project to proceed is therefore £187,037.50 + VAT.
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8.4 Key personnel NNFCC will lead the demonstration project, in partnership with CNG Services Ltd. This partnership has the right combination of AD, biogas, agricultural, engineering and regulatory knowledge and technical expertise to pursue the design and implementation of the biogas network. NNFCC is a leading strategic consultancy operating across the entire bioeconomy, offering expertise in biomass, biogas, biofuels, biomaterials and biochemical. NNFCC works for both industry and Government to provide strategic and technical advice on technologies, feedstocks and supply chain integration within the bioeconomy. Currently 12 people work for the NNFCC, with skills and expertise in agronomy, sustainability and energy policy. The team at NNFCC has experience in the following areas:
Future market analysis
Feedstock logistics and planning
Sustainability strategy development
Technology evaluation and due diligence
Project feasibility assessment
Policy and regulatory support
NNFCC is a not-for-profit private company and trusted independent advisor, supporting Government to identify and overcome barriers to increase bioenergy deployment, as well as providing impartial information on a commercial basis to private organisations and other public bodies. NNFCC provide advice and signposting services to sources of technology and funding plus technical consultancy advice and support services to industry to help deliver deployment. NNFCC hosts the Official AD Information Portal, for England, Scotland, Wales and Northern Ireland (www.biogas-info.co.uk) and actively engages through commercial and Government activities with key industry stakeholders. NNFCC will be the lead partner in this project, responsible for project management, delivery and dissemination. CNG Services Ltd supports the development of new anaerobic digestion projects including a range of utilisation options for biogas:
use to generate electricity in good quality CHP;
clean-up of biogas to produce biomethane;
injection of biomethane into the gas distribution network;
compression of CNG/biomethane for use as fuel in road vehicles; and
support the introduction of CNG/biomethane fuelled vehicles.
CNG Services designed and project managed the Didcot and Poundbury biomethane to grid projects and has been promoting this concept since 2006. CNG Services Ltd will be a delivery partner in the project, responsible for design and installation of the biogas network, demonstration and ongoing evaluation and monitoring. The delivery team will comprise the following, all of whom have been involved in the Feasibility Study. Lucy Hopwood, Head of Biomass and Biogas at NNFCC Lucy is NNFCCs lead on biomass and biogas and her main expertise lies specifically in agriculture, feedstocks and AD. Lucy is responsible for actively engaging with the farming
Biogas networks 53
industry to raise awareness and promote the opportunities presented by bioenergy technologies. Lucy is an expert on biogas technology and applications and works closely with industry and Government to encourage uptake and to overcome supply chain barriers. Lucy guides producers and operators through change and implementation, identifying supply chain weaknesses and solutions, reporting evidence to policy makers in order to strengthen future activities. Lucy has been actively involved in a number of planned and operational AD facilities in the UK and has a well-established network of contacts in the UK and overseas. Lucy will provide guidance and input in relation to technical, policy and regulatory issues, and will oversee dissemination activities. Lucy Nattrass, Senior Consultant at NNFCC Lucy produces regular reports on the deployment, market barriers and challenges in the AD and Energy from Waste sectors and assesses market activity and technology development. Lucy has experience of organising and participating in stakeholder engagement activities including interviews and workshops and represents NNFCC at conference s and exhibitions. Lucy has been selected to work on this project due to her extensive knowledge of the existing AD industry and the barriers faced by developers, operators, regulators and policy makers, through regular monitoring and reporting to DECC. Lucy will lead this project; her responsibilities will include all project management, co-ordination, client liaison and reporting. Michael Goldsworthy, Consultant at NNFCC Michael joined NNFCC in October 2012 with undergraduate and postgraduate degrees in biological sciences from the University of Exeter and has notable expertise in the fields of biotechnology and microbiology. His PhD was funded by Shell and sought to evaluate the potential of microbial organisms to be deployed as industrial biocatalysts in the manufacture of advanced biofuels. Michael will contribute to the preparation of reports including standard documentation. He will lead on the preparation of dissemination materials. Since joining NNFCC he has collated and analysed data to support supply chain assessments and feasibility studies including securing stakeholder input and feedback. John Baldwin, MD CNG Services Ltd John joined British Gas as a graduate engineer in 1983 from Oxford University and worked in various design operational and maintenance roles on the National Transmission System (NTS). In 1990 he joined the commercial department of British Gas Exploration and Production where he worked in oil and gas sales. He returned to Transco as Transmission Commercial Manager in 1994 with commercial responsibility for NTS, Power Stations and the Interconnectors. John is a member of the Biomethane for Transport Steering Committee and is Chairman of the Renewable Energy Association (REA, www.r-e-a.net) Biogas group. John will provide guidance and input in relation to the issues associated with biogas pipelines across fields and will liaise with planners and HSE as part of the project. Lee Firth, Senior Process Engineer, CNG Services Ltd Lee was design engineer on the Poundbury biomethane to grid project and is expert in
Biogas networks 54
relation to biogas clean up and upgrading. He also understands the key design elements of H2S removal, drying and compression as a result of 20 years‟ experience with Air Products. Lee will be responsible for the process design and procurement activities and will also liaise with the contributing partners including the farmers and Greener for Life Energy (GfLE); Lee will be the project manager for the design and build elements of the project. Robert McKeon, Graduate Project Engineer, CNG Service Ltd Robert graduated as a mechanical engineer in 2009 and after an internship at Severn Trent‟s Renewable Energy Team enrolled on an MSc Course in Renewable Energy which covered all the renewable technologies in the market today, their applications and their issues, as well as UK regulation and financial incentives surrounding renewables. He specialised in biomass and biofuels, designing a CHP and tri-generation system for his MSc dissertation using biogas from a brewery waste fed AD to produce heat, electrical and cooling power to the brewery. After graduating in 2010 Robert took some time to travel before joining CNG Services in April 2012 as a project support engineer working on biomethane projects including Vale Green biomethane to grid project, Severn Trent Minworth and a TSB Funded Anaerobic Digestion AD R&D Project. Rob will be responsible for pipeline design and planning activities. 8.5 Monitoring The project aims to demonstrate the viability of a biogas network in the UK and to encourage uptake and improve efficiency of small-scale AD plants in other regions. Monitoring will therefore focus on the scale of interest with technology providers and AD project developers. Through its dissemination activities the project team will record feedback and monitor sites considering the biogas network concept and their progress over the time period of the project recording any additional barriers experienced and suggesting possible mitigation measures. 8.6 Health, safety and risk A risk assessment of the biogas network based on expected site conditions was completed as part of the Feasibility Study (Section 3.2.1) and includes the hazards, consequences and controls relating the installation and operation of the biogas network. Delivery of the first biogas network would expect to be complete within 18 - 24 months (Phase 2 would be expected to start in September 2013); initially connecting at least 2 rural AD plants, with subsequent plants to follow. A number of potential network opportunities are currently in discussion, located in the North West and the South West regions. The team are currently in discussion with National Grid for the „biogas network‟ element of the first demonstration unit. The Innovation Fund Incentive (IFI) scheme is a mechanism introduced by Ofgem to encourage GDNs to invest in appropriate research and development activities that focus on technical aspects of network design, operation and maintenance. The principle objective of the IFI is to deliver benefits to consumers, taking a longer term view, by enhancing efficiency in network operating costs and capital expenditure. National Grid have previously expressed an interest in the biogas network concept, but due to funding eligibility constraints could not be involved in supporting a feasibility assessment. Upon submission of the feasibility report to WRAP, National Grid will also get sight of the
Biogas networks 55
initial findings to provide the evidence that is necessary to confirm their interest in funding and the degree of support. Concerns have been expressed regarding receipt of grant monies for such activities, and potential conflict with RHI or FIT payments – further exploratory work is required on this prior to funding being committed. To allow this step to take place and discussions to progress, we have not yet completed the detailed project plan for Phase 2. This will be completed within 10 working days and submitted to WRAP as a separate document, for insertion into or annexing to the feasibility report in due course.
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Appendix 1 Manure estimates
Dairy cattle Various means for calculating manure production are available. DEFRA have previously published broad estimates for manure production rates of dairy cattle using milk yield as a basis for their calculations (Table ).
Table 33 Manure production by dairy cattle20
Milk yield (l/year) Manure production (kg/day)
Manure production (t/year)
<6000 64 23
6000 – 9000 53 19
>9000 42 15
The average milk yield for dairy cattle across the UK for 2011/12 was 7,617 litres per cow21. Using this figure it can be estimated that on average, a UK dairy cow produces 53.9kg of manure per day, equivalent to 19.7 tonnes per year. Meanwhile, a standard method for estimation manure production from dairy cattle was also developed by Nennich et al. using multiple data sets acquired from a variety of US universities22. The study again established manure production rates using milk yields (Figure 12) and concluded that the following equation can be used for this purpose: Manure production (kg/day) = 0.647 x Milk production (kg/day) + 43.212
Figure 12 Manure production by dairy cattle
Using this equation it can be estimated that UK dairy cows produce 56.7 kg manure per day on average, a figure in line with that calculated using information provided by DEFRA. On account of the transparency provided by the report of Nennich et al. this study used a
20 Defra, Guidance for farmers in nitrate vulnerable zones (leaflet 3), April 2009
21 DairyCo, Average Milk Yield, August 2012
22 Nennich et al., Development of standard methods to estimate manure production and nutrient characteristics from dairy cattle, December 2003
Biogas networks 57
standard estimate for manure production of UK dairy cattle of 56.7 kg manure per day, equivalent to 20.7 tonnes per year. Collected volumes of manure will vary from farm to farm although it is possible to apply assumptions to estimate the percentage of manure that in would in general be collected from dairy farms23. For a 150 head unit the cattle will be housed inside for 6 months during the winter period, for which time all manure can be easily collected. During the outside period it can be assumed that around 30% of manure can be collected during milking and yard movements. Therefore, around 65% of manure produced annually will be collected from a 150 head unit. For a 300 head unit the cattle will also be housed for 6 months. However, during the summer period the cattle are likely to be housed at night and will result in manure collection rates of around 50% during this period. Therefore, around 75% of manure produced annually will be collected from a 150 head unit. On account that around 90% of UK dairy farms are of a herd size below 300 head, we assumed a collection rate of 65% for calculating total manure volumes produced at the county level. However, it should be noted that those farms most likely to be interested in involvement with biogas networks schemes are those that are likely to have the higher manure collection rate. Pig manure Application of pig manure estimates is more troublesome than for dairy cattle. The data available from DEFRA‟s 2010 agricultural census only accounts for total pig numbers and does not segregate into type (e.g. fattening or breeding), type of feed or age/weight bands, all of which impact upon volumes of manure produced. To provide a standard estimate per head of livestock required analysis of the relevant distribution of pigs in the UK in regards to these factors. The outputs of this analysis is shown in Table and
23 Reaseheath Enterprise, Economic viability of farm scale AD biogas generation across Cheshire and Warrington, November 2010
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Table . Distribution and manure production data was sourced from the relevant documents cited in the tables, while conversion of volumes to mass was calculated assuming a density of 1.023 t/m3 for pig manure 24.
Table 34 Manure production by fattening pigs 25,26
Weight category Proportion (%)
Manure production (kg/day) (Dry-fed)
Manure production (kg/day) (Wet-fed)
Over 80 kg (finisher) 17 5.85 10.23
50 to 80 kg (grower) 25 4.38 7.31
20 to 50 kg (grower) 29 4.38 7.31
Under 20 kg (weaner) 29 1.43 1.46
24 Malley et al., Analysis of nutrients in hog manure by field-portable near-infrared spectroscopy, September 2001
25 Defra, June Survey of Agriculture and Horticulture: Methodology, 2011
26 Defra, Guidance for farmers in nitrate vulnerable zones (leaflet 3), April 2009
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Table 35 Manure production by breeding pigs , 27 28
Category Proportion (%) Manure production (kg/day)
Sows in pig 53 11.25
Gilts in pig 13.5 11.25
Other sows 12.5 5.12
Boars used for service 3 5.12
Gilts for first time breeding 18 4.43
By further assuming that fattening pigs are responsible for 85.5% of the national pig herd - with breeding pigs constituting the remainder20 - and that dry-fed to wed-fed fattening pigs are distributed in a 2:1 ratio (as estimated by pig nutrionists) it can be calculated that on average 4.39 kg/day of manure is produced per head of pig livestock in England. Clearly, the numerous assumptions made for the calculation mean that this is a very rough estimate but nevertheless, it should be suitable for application for determining manure production by pig farming at a county-level of resolution. Collected volumes of manure will again vary from farm to farm depending on the housing and husbandry system, but it can be expected that a collection rate of around 90% is generally achievable. This figure was therefore applied to total pig manure production to determine collectible volumes.
27 Defra, Guidance for farmers in nitrate vulnerable zones (leaflet 3), April 2009
28 Defra, Farming statistics - Livestock populations at 1 December 2012 in UK and England, March 2013
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Appendix 2 Biogas network decision making tool
Figure 13 Biogas network decision making tool
www.wrap.org.uk/diad
