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Final Report – Driving Innovation in AD – Small-Scale

Cost effective cleaning and supply of

biogas from small-scale AD plants

Integration of technologies towards cleaning, compression and bottling of biomethane

Project code: OIN001-501 Research date: March- April 2012 Date: April 2012

WRAP’s vision is a world without waste, where resources are used sustainably. We work with businesses, individuals and communities to help them reap the benefits of reducing waste, developing sustainable products and using resources in an efficient way. Find out more at www.wrap.org.uk Document reference: [e.g. WRAP, 2006, Report Name (WRAP Project TYR009-19. Report prepared by…..Banbury, WRAP]

Written by: Prab Mistry and Mike Pugh; Economic & Human Value Engineering Ltd

Front cover photography: Collage based on biogas cleaning, compression and delivery of biomethane from on-farm AD plants

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Cost effective cleaning and supply of biogas from small-scale AD plants 1

Executive summary

Small-scale anaerobic digestion (AD) systems provide livestock farmers with an opportunity to combine, in a single investment: effective slurry management; methane abatement; energy generation; and save on fertiliser costs. AD can be applied at wide ranging scales of operation, but at small scale (e.g. livestock farms with 200 dairy cattle, 750 intensive pigs or around 15,000 egg laying hens) cost-effective use of biogas is a key challenge facing the technology. EHV Engineering has been actively engaged in biogas technology in the UK at various levels – policy and strategy (Government) through to implementation for waste producers and biogas plant operators. EHV have established a strong team to translate current knowledge and experiences into a biogas cleaning, compression and bottling system that allows the biomethane to be used on-farm or sold off-site for use as compressed biomethane, a renewable energy source, to supply heat at the point of use. Our product is designed so that it can deliver biomethane to gas-fuelled heat boilers in the range between 50kWth and 200kWth of heat, which will attract the tariffs of 7.1p/kWh in 20121, under the Renewable Heat Incentive (RHI) scheme. We contacted Ofgem (on 15th February 2012) to seek their view on our scheme and about qualification under the RHI scheme. We have exchanged several communications about our product and have been informed that it is most likely to qualify. Ofgem does however need to seek a formal legal view which they will provide in writing in the near future. This will be forwarded to WRAP as soon as we have received it. The basic flowrate of biogas that we are considering is ~9m3/h; representing around 59kW of fuel and capable of delivering some 50kW of heat if burnt in a boiler. At this scale cost-effective biogas utilisation poses a key technical challenge, as any equipment is prone to corrosion and short life; this has restricted its market access. Our project has therefore focused on cleaning and containerisation of enhanced biogas, or biomethane, for delivery to off-site users. In doing this we have considered two quite different technologies for the scrubbing of CO2 and H2S from biogas: Option 1: Gas/liquid membrane contactor, based on a standard design filter unit

developed by the Pall Corporation and delivered in the UK by Pall Europe Ltd; and

Option 2: Downflow Gas Contactor (DGC), based on a novel reactor design developed

by WRK Design and Services Ltd. The potential use of membrane technology to enhance biogas is relatively recent. Pall Europe Ltd has developed this technology for humidifying gases and aerating liquids, but it has not been tested on biogas scrubbing. In contrast, the DGC technology has been tested at pilot scale, on biogas mixtures, as part of a Technology Strategy Board (TSB) funded project in 2011. We have therefore chosen this technology for taking forward in our biogas management system. The key aims of our work to date have been to simplify and reduce the cost of scrubbing and storage of biogas produced from low flow rate, small scale AD plants on farms. This will be

1 index linked for up 20 years


achieved by integrating a series of technologies that will run almost automatically, using the necessary controls for operation and safety. Our proposed product is depicted below.

All aspects of the proposed product have been investigated in this feasibility study. We are satisfied that the overall concept will result in a biogas treatment and cylinder filling facility that can be co-located on farms with small scale AD plants to produce compressed biomethane (CBM) that would be marketable. The scope for value engineering of this system suggests that the capital cost of a production version will be around £40k. Its natural competitor for biogas utilisation from farm-based AD plants is the installation of a CHP plant. At the small scale operation under consideration, the cost of a CHP plant has been assessed as around £34k, but the value of energy exported will be lower than the EHV system. All costs and benefits associated with the heat and CHP options have been analysed. An economic analysis around AD and biogas utilisation systems shows that the EHV biogas system, when linked with a commercial heat boiler, will provide a more attractive proposition than that comprising on-site CHP. This is achieved by significantly higher annual income. For small scale AD plant capable of producing around 9m3/h of biogas, the heat option shows an Internal Rate of Return (IRR) of around 8.5% compared to 5% for that with CHP scheme. If however there were to be 40% reduction in AD plant cost (a clear aim of the DIAD small scale programme) these returns rise to 16.7% and 11.2%, respectively. Phase 2: Demonstration Our product combines a well-researched and developed application of downflow gas contactor (DGC) technology to produce almost pure biomethane with established gas compression technology to deliver a portable supply of CBM that would be marketable in a wide range of commercial heating applications. WRK Design Services will undertake the task of fully designing and building the DGC-based system, and deliver, install and commission it at the first demonstration site. The rig will be mounted on a double axle trailer frame for ease of transport to subsequent demonstration sites. Several small-scale AD plant sites have been identified, two of which will be chosen, for demonstrating our product. Our market analysis shows that there is a potential of several thousand gas clean-up and supply units at £40,000 per unit and that the market may support a price up to £64,000 per unit within the UK. The small scale AD systems, of which the gas clean-up and supply equipment would be a component, will be based largely on farms. A two pronged approach to the market is envisaged:

Scope of EHV biogas system


Direct contact with specifiers, suppliers and installers of small scale AD plants and provision of technical and financial information on the benefits of the gas clean-up and supply system over the more conventional gas engine / CHP approach.

Provision of information to the many thousands of farms that might benefit financially from the installation of a small scale AD system. The marketing material would explain the benefits of on-farm AD and specifically the advantages of clean-up and supply of gas for use on or off-farm, as opposed to electricity generation on-farm.

The above two marketing campaigns would be very different in scale. There are only a few suppliers of small scale, on-farm AD systems (which include Biotech Services, Envar Ltd, Ever Green Gas, HIRAD Biogas, Kingdom Bioenergy and Marches Biogas) and these companies would be contacted, visited and provided with detailed technical and financial information on the benefits of the gas clean-up and supply system. EHV will provide a core team of four highly experienced professionals, who will be supported by technician grade staff to undertake the work programme described for Phase 2. We are proposing a realistic timetable (of 15 months) for the execution of Phase 2, with logical progress milestones that will enable WRAP to verify that the project remains on programme for successful completion. The project personnel that we would deploy to Phase 2 are fully proficient in the areas of expertise needed to deliver the project. The proposals for Phase 2 of this project have been outlined; these will lead to a robust demonstration at commercial scale of a novel technology that will fill the gap in the market for high energy recovery from small scale on-farm AD plants. We have clearly set out each stage of the demonstration project that needs to be considered to ensure a successful project. The total cost of the demonstration phase will be £248,175 (+VAT). 75% of this will be sought as grant from WRAP, due to the need for extensive testing and value engineering that will be needed. If the final equipment is to be donated for educational purposes, EHV will seek a greater portion in grant.


Contents

1.0 Abstract ........................................................................................................ 1 PART 1: FEASIBILITY STUDY ................................................................................. 2 2.0 Introduction and background ....................................................................... 2

2.1 Company/consortium ................................................................................. 2 2.2 Introduction to our technology .................................................................... 3 2.3 Proposal (technology/concept) background .................................................. 4

2.3.1 Where – origins of technology? ......................................................... 5 2.3.2 What – what has been achieved to date? ........................................... 6 2.3.3 Why this technology? ....................................................................... 7

3.0 Project Objectives ........................................................................................ 7 3.1 Feasibility study and aims for the demonstration ........................................... 7 3.2 Aims & Objectives of Phase 2 and Driving Innovation .................................... 8

4.0 State of technology ...................................................................................... 9 4.1 Development history of the technology ........................................................ 9

4.1.1 Gas/liquid absorption membrane contactor ........................................ 9 4.1.2 Downflow Gas Contactor ................................................................ 10 4.1.3 Associated Technologies ................................................................. 11

4.2 Previous use/evidence to support the use of the technology from other countries, sectors or industries where applicable ................................................... 12 4.3 Previous tests i.e. desk-based studies, lab-scale, on the ground ................... 12

5.0 Legislation .................................................................................................. 13 5.1.1 Standard Permits ........................................................................... 13 5.1.2 Exemptions ................................................................................... 13 5.1.3 ADR Regulations ............................................................................ 14

6.0 Detailed technical appraisal of technology ................................................. 14 6.1 Theory/process behind the technology ....................................................... 14 6.2 Operational parameters ............................................................................ 17 6.3 Comparison with ‘business as usual’ .......................................................... 17 6.4 Range ..................................................................................................... 18 6.5 Life cycle of technology ............................................................................ 19 6.6 Risk Analysis ............................................................................................ 19

7.0 Economic / Cost Benefit Analysis ............................................................... 19 7.1 Key Appraisal ........................................................................................... 19 7.2 Comparative Assessment .......................................................................... 20

7.2.1 Scope for further cost reduction ...................................................... 22 8.0 Overall Environmental Impacts .................................................................. 23 9.0 Principal Conclusions from Feasibility Assessment .................................... 24 PART 2: DEMONSTRATIONS (Phase 2) ................................................................. 25 10.0 Methodology for demonstration ................................................................. 25 11.0 Complete and detailed project timescale ................................................... 25

11.1 Project development and implementation plan ............................................ 25 11.2 Permitting & other approvals ..................................................................... 26 11.3 External contracts including commercial boiler operators ............................. 26 11.4 Project Financing ..................................................................................... 27 11.5 Construction ............................................................................................ 27 11.6 Install and commission product at first site ................................................. 27 11.7 Operation, Monitoring and evaluation ........................................................ 28 11.8 Decommissioning and transport of product to second site............................ 29 11.9 Re-commission, operate, monitor/evaluate product at second site ................ 29 11.10 Handover equipment to RASE appointed personnel ..................................... 29 11.11 Prepare final report for WRAP and sponsors ............................................... 30


12.0 Cost breakdown and milestones ................................................................. 30 12.1 Overall cost of Phase 2 ............................................................................. 30 12.2 Milestone payments ................................................................................. 31 12.3 Funding provisions ................................................................................... 31

13.0 Commercialisation of technology post demonstration ............................... 32 13.1 Market Size.............................................................................................. 32 13.2 Economic viability..................................................................................... 33

13.2.1 Gas engine / CHP ........................................................................... 33 13.2.2 Income streams ............................................................................. 34 13.2.3 Gas cleaning and supply ................................................................. 34 13.2.4 Income streams ............................................................................. 35

13.3 Approach to the Market ............................................................................ 35 13.4 Commercialisation Plan ............................................................................. 36

13.4.1 Intellectual Property Landscape ....................................................... 36 13.4.2 Standards and Regulation ............................................................... 39 13.4.3 Companies Likely to Deliver the Technology ..................................... 40

14.0 Key personnel ............................................................................................. 40 15.0 Evaluation and monitoring for the purpose of WRAP reporting ................. 42 16.0 Health and Safety ....................................................................................... 42 17.0 Conclusion .................................................................................................. 43 APPENDICES ........................................................................................................ 44 Appendix 1: Biogas Scrubbing based on Membrane Technology.......................... 44 Appendix 2: Biogas Scrubbing based on DGC Design ........................................... 55 Appendix 3: Biogas Scrubbing based on conventional absorber .......................... 67 Appendix 4: Compression and Bottling System Quote ......................................... 69

Glossary

AD = anaerobic digestion ADR = Regulations related to the carriage of dangerous goods. The acronym 'ADR' comes

from their French name and stands for 'Accord European Relatif au Transport International des Marchandises Dangereuses par Route'.

Bo = Methane potential of a substrate, expressed as cubic metres (m3) of methane per kg of VS

BOD = Biochemical oxygen demand (expressed as mg/l) CBM = Compressed biomethane (methane enriched biogas) COD = Chemical oxygen demand (expressed as mg/l) CH4 = methane (gas*) CO2 = carbon dioxide (gas*) d = days DF = Discount factor DCF = Discounted cash flow DGC = Downflow gas contactor EF = Emission factor FiT = Feed in Tariff, UK Government incentive for producing renewable electricity FYM = Farm yard manure GJ = Giga Joules GWh = Giga watt-hours HACCP = Hazard analysis and critical control points kg = kilogram(s) kJ = kilo joule(s) kW = kilo watt(s) kWh = kilo watt-hours


kWth= kilo watt-hours, thermal MWh =Mega watt-hours m3 = cubic metres of gas* MCF = methane conversion factors for each manure management system MCS = Microgeneration certification scheme Mesophilic = temperatures of AD between 35oC and 40oC MJ = Mega Joule(s) Ofgem = The Office of Gas and Electricity Markets, the government regulator for the

electricity and natural gas markets in GB RASE = Royal Agricultural Society of England RHI = Renewable Heat Incentive, UK Government for producing renewable heat SBRI = Small Business Research Initiative TSB = Technology Strategy Board Thermophilic = temperatures of AD around 55oC TWh = Terra watt-hours UKLPG = The trade association for the LPG industry in the UK VFA = Volatile fatty acids (intermediate compounds in the breakdown of organics by AD) VS = Volatile solids; i.e. degradable organic material in waste. WRAP = Waste and Resources Action Programme y = year * All gas volumes are quoted at 20oC and 1 atmosphere, unless stated otherwise.

** All costs should be read as those as at March 2012, unless stated otherwise.


1.0 Abstract EHV Engineering has investigated the technical and economic feasibility of a novel biogas cleaning technology, which has not been applied to field scale systems. The overall product will comprise this technology along with compression of methane-rich biogas and bottling in standard 50 litre cylinders. The product is designed for installation alongside farm scale anaerobic digesters as a revenue generating energy recovery system. The technology we have assessed is based on 9m3/h of biogas: a most challenging scale, and one that will allow wide-scale application of the AD/biogas technology on UK farms. The scaling up of the technology to handle some 40m3/h of biogas (i.e. up 200kWth heat that would still qualify for biogas heat generation under RHI scheme) will be straightforward. All aspects of the proposed product have been assessed in this feasibility study and it shows that the overall product would be easy to operate and competitively priced. It will use a downflow gas contactor (DGC) technology which has been developed and tested at pilot scale, on synthetic biogas mixtures, as part of a TSB funded project in 2011. The technology is owned and will be supplied by WRK Design & Services Ltd, exclusively for use at this scale range (i.e. up to 200 kWth), to EHV Engineering. Market analysis shows that there is a potential for several thousand gas clean-up and supply units at around £40,000 per unit (at the scale to be demonstrated), and that the market may support a price up to £64,000 per unit. The key route to the market will be by working closely with specifiers, suppliers and installers of small scale AD plants. The proposals for Phase 2 of this project have been outlined for a robust demonstration that will show the commercial attractiveness of this novel product and which will fill the gap in the market for small scale on-farm AD plants. The scope for export of this product is also excellent.


PART 1: FEASIBILITY STUDY

2.0 Introduction and background

2.1 Company/consortium Economic & Human Value Engineering Ltd (EHV Engineering or EHV) is the instigator of this project. Further information about the company can be found at: www.ehv-

engineering.com. EHV established a strong team to translate current knowledge and experiences (at the design stages) into a biogas cleaning, compression and bottling system as depicted below.

Figure 1: The project team

Prab Mistry of EHV Engineering is a qualified and Chartered Chemical and Biochemical Engineer. He has a wealth of knowledge from over 20 years at the forefront of the thinking and development of the UK AD market (while based at AEA Technology), but his engagement in AD Research and Development (R&D) goes back to the early eighties, which culminated in his PhD thesis that covered economics of bioenergy systems and pilot scale trials of a novel anaerobic fluidised bed system. Mike Pugh, an associate of EHV Engineering, with extensive experience in waste and environmental management, has also been part of the project team. All parties have brought their pre-existing knowledge to bear on this project:

Pall Europe Ltd, part of the Pall Corporation, is a global leader in the high-tech filtration, separation and purification industry;

WRK Design & Services Ltd. provides wide ranging design and process engineering services;

The Environment and Sustainability Partnership provides practical advice and support to private and public sector organisations in achieving sustainable change through projects and programmes.

http://www.ehv-engineering.com/

http://www.ehv-engineering.com/


2.2 Introduction to our technology EHV Engineering has been actively engaged in biogas technology in the UK at various levels – policy and strategy (Government) and implementation for waste producers and biogas plant operators. Biogas (or anaerobic digestion) plants are widely applied at large scales. They generally produce biogas with a composition of 50-70% CH4 and 30-50% CO2. The overall composition (as well as the yield) is a function of the feedstock as well as operating conditions (including pH) but it also contains small amounts of other compounds such as molecular nitrogen (N2), oxygen (O2), ammonia (NH3) and hydrogen sulphide (H2S) amongst others. As such varying degrees of cleaning need to be applied to the biogas, depending on its market outlet and use. The AD technology is already widely applied at larger scale (producing 350 to 1650 m3/h biogas) and medium scale (80 to 350m3/h biogas); see Figure 2. These are generally well integrated with a form of gas scrubbing and utilisation. However, the technology is not cost-effective at small scale – this is a key barrier to wide scale exploitation of small scale AD plants. By small scale we are referring to those with biogas production of around 9 m3/h biogas, representing up to 60 kWth of fuel or if used in a boiler then around 50kWth heat output. Small-scale on-farm AD plants would typically produce between 50 and 200 kW of biogas, which is the focus of our project. We are looking at biogas handling at this scale of operation – the focus of the competition under which this project is supported. Our work examines the feasibility of cleaning, compression and bottling of the enhanced biogas (biomethane) produced. Importantly, the scale we have chosen is 50 kW, a small but practical scale at which commercial scale boilers are found and which will also attract a Renewable Heat Incentive (RHI) premium at 7.1p/kWh2. The same concept and our product can be applied for larger scales up to the production of 200 kWth, the upper limit under the RHI scheme.

Figure 2: Illustration of the scales of operation with respect to biogas production

2 Official tariff rate for 2012, as published by Ofgem.


Our product will be available to meet the needs of the small scale AD plants, producing between 50kWth and 200 kWth of biogas. At this scale, one AD plant could serve one or more small-scale commercial boiler applications within the locality; i.e. within easy reach by road. We have consulted Ofgem about our product to understand if it will qualify under the RHI scheme, given that the heat boiler will be sited away from the farm digester. We have also sought clarification if the scheme would need qualifying and/or registering under the Microgeneration Certification Scheme and any monitoring requirements that will be essential to remain qualified for 20 years under the RHI scheme. Any approved scheme will need to have auditable records; otherwise the user may substitute natural gas in place of biomethane and still claim the RHI premium. The Microgeneration certification scheme (MCS) is designed to avoid any such corrupt practices. While Ofgem have informed us in conversation, that our scheme is likely to qualify, it needs to seek a legal view as the biomethane boiler is almost certainly to be situated away from the place of the AD plant. Full written response by Ofgem was expected by Thursday, 5th April 2012, but they have got back saying they will need more time to seek a full view of our product; the response is now expected around mid June 2012. 2.3 Proposal (technology/concept) background Small-scale anaerobic digestion (AD) systems provide livestock farmers with an opportunity to combine effective slurry management, methane abatement and energy generation in a single investment. Just as a recent report by RASE3 has drawn attention to the unexploited potential of livestock slurry and other agricultural wastes, there are many other reports (IBBK/REA(2008)4, SLR(2010)5, NNFCC(2008)6) that depict small scale AD as uneconomic for wide scale application in the UK or for that matter in Europe. There are several areas where innovation is needed to improve and simplify materials handling, fabrication of AD plants, digestate utilisation, biogas utilisation and process control and automation. Our project focuses on the integration of technologies towards cleaning, compression and bottling of biomethane to enable several thousands of small scale applications to be realised in the UK alone (see section entitled

3 Review of Anaerobic Digestion Plants on UK Farms, report produced by the Royal Agricultural Society of England (RASE), April 2011.

4 Economic modelling of AD/Biogas installations in a range of rural scenarios in Cornwall, report by IBBK and REA for Cornwall Agri-food Council (August 2008).

5 European experience of small-scale and on-farm AD, by SLR for Defra (July 2010).

6 A detailed economic assessment of AD technology and its suitability to UK farming and waste systems, report by the Andersons Centre for NNFCC (April 2008).


Commercialisation Plan). By small scale we mean around 5-10 m3/h biogas generation (containing 3-6 m3/h methane), which is currently seen as being too small for economic viability, though this is the scale required for very wide application of the technology based on the use of agricultural wastes that would otherwise remain unexploited. 9 m3/h biogas, or 50kWth heat, generation typically translates to biogas production from single (or a combination of) feedstock of either

200 dairy cattle;

750 intensive pigs;

15,000 poultry (assumed egg laying);

600 t/y of food waste; or

450 t/y of maize silage

The above feedstocks are best co-digested, where possible, so as to provide a more stable digestion substrate. Poultry manure for instance is generally not digested on its own due to the high Nitrogen (N) content, which would require control over ammonia generation or digesting with low N feedstock such as maize silage or purpose grown energy crop. We are also aware that increasing numbers of farmers are now required to invest in slurry management and storage capacity to comply with the Nitrate Directive (91/676/EEC) and Water Framework Directive (2000/60/EC). These slurry stores will have a tendency to produce biogas and our final product may also be suited to tapping this source to deliver bottled biogas (although this source of biogas is not included to be tested in this project). The figure below shows where the key package of biogas cleaning, compression and bottling that our technology focuses on.

Figure 3: EHV biomethane product focus

This will entail integration of three key steps connecting AD process to the final use of biomethane. We have assessed different technologies, including those applied in other sectors, to enable effective and economic use of low flow rate biogas ~9m3/h, which would be from small scale AD plants. This flow rate of biogas represents around 59kW of fuel, capable of delivering some 50kW of heat if burnt in a boiler. This is around a quarter of the maximum size heat boiler allowed under the Renewable Heat Incentive. 2.3.1 Where – origins of technology?


The competition being conducted by WRAP, in association with SBRI and RASE, is designed to bring about appropriate technology that will significantly reduce the costs associated with the biogas technology, in fact it could achieve some 40% reduction in the capital cost7 of the AD in order to serve the livestock farms (dairy in particular). The review by RASE, as referred to above, pointed to some 20 on-farm digesters in the UK, but most of these have come about prior to the introduction of the economic incentives (FIT or RHI), and mainly due to the ingenuity and enthusiasm of the farmers who also operate and maintain them themselves. This number is unlikely to increase without significant reduction in capital and operating costs as well as the complexity involved. As mentioned above, cost-effective biogas utilisation poses a key barrier when it is produced in small quantity. Our project has therefore focused solely on this: cleaning and containerisation of enhanced biogas for delivery to off-site users. In doing this we have considered two quite different technologies for the scrubbing of CO2 from biogas: Option 1: Gas/liquid membrane contactor, based on a standard design filter unit

developed by the Pall Corporation; and Option 2: Downflow Gas Contactor (DGC), based on a novel reactor design developed

by WRK Design and Services Ltd. The potential use of membrane technology to enhance biogas is relatively recent8. Pall Europe Ltd has developed this technology for humidifying gases and aerating liquids, but it has not been tested on biogas scrubbing. In contrast, the DGC technology has been tested at pilot scale, on biogas mixtures, and is chosen for taking forward in our biogas management technology; see also Appendix 1. The DGC (Downflow Gas Contactor) was initially developed as the CDC (Co-current Downflow Contactor) Reactor. The original work was done mainly for Gas liquid contacting and a Patent Application No 49385 was filed in Nov 1976. The Patent application was by Boyes A.C and Ellis SRM, which was finally published in Aug 1981– No. 1 596 738. Dr Raymahasay during his employment at the University of Birmingham worked with Dr Boyes using the CDC Reactor. However Dr Boyes discontinued his work at UoB in the early 1990’s and did not progress further with the reactor. Dr Raymahasay started WRK in 2002 himself and started developing and modifying the reactor further, for various applications. He renamed it as the DGC reactor and has, through WRK, used it for different projects mainly for feasibility studies and problem solving for various companies for different applications in gas absorption, reaction engineering and effluent treatment. 2.3.2 What – what has been achieved to date?

7 Applicants were invited ‘to tender for projects under the SBRI/WRAP/RASE Programme to develop technology enabled solutions addressing the need for more cost effective and less complex small scale AD technologies for farm scale installations.’ Background work to this competition has shown that 40% reduction in capital cost would be possible.

8 Agata Polak, Andrzej Chmielewski and Marian Harasimowicz, Biogas Separation, XXIII ARS SEPARATORIA – 288 Toruń, Poland 2008


Dr Raymahasay received a TSB grant to undertake some trials using the DGC reactor based on carbon capture from air; during this project he also undertook some trials based on mixed gases, including simulated mixtures of methane, carbon dioxide and hydrogen sulphide that represented biogas. This work has been published and is summarised in Appendix 2. An application for an UK Patent has been made for the technology developed for the process. 2.3.3 Why this technology? Conventional biogas scrubbing technology is widely applied on large scale applications. However, it has high relative costs at small scale application, as we have seen in a recent quote for this scale of application (see Appendix 3). It was the intention of this feasibility study to demonstrate that one or both of the novel technologies considered here lend themselves to smaller applications compared to conventional biogas scrubbing technologies that offer economies at larger scale. Application of the technology into the UK AD industry now and into the future To date the small scale AD plants have not proved economically attractive, due in part to the barrier related to cost-effective use of biogas, which this project addresses. This should not be mistaken with the biogas cleaning at medium and large scale AD plants, which is widely practiced. The scope of supplying the small scale biogas use, which can also take advantage of the UK Government’s financial incentives under the Feed in Tariff (FiT) is huge; see Section Commercialisation of technology post demonstration, on page 32. 3.0 Project Objectives 3.1 Feasibility study and aims for the demonstration The key aims of the feasibility study were to simplify and reduce the cost of scrubbing and storage of biogas produced from low flow rate, small scale AD plants on farms. Considerable reduction in the operational complexity will be achieved as we are aiming for a product based on a series of integrated technologies that will run almost automatically, using the necessary controls for operation and safety. The overall package will be designed to ensure that it focuses on cost-effectiveness, convenience, practicability, and safety of the operation, from the start of the testing and demonstration phase. The specific objectives of the feasibility study were to: 1 undertake preliminary examination of the technology parts and any IP issues; 2 design and optimisation of either membrane- or DGC-based biogas cleaning system for

~9m3/h of biogas; 3 review suppliers of specific technologies that will be integrated alongside the scrubbing

process to provide an overall package; 4 design the overall integrated package of cleaning, compression and storage of biogas; 5 develop the work programme for testing the integrated package in Phase 2; and 6 prepare the Phase 1 report.


3.2 Aims & Objectives of Phase 2 and Driving Innovation The prime aim of Phase 2 will be to demonstrate the use of the integrated package of biogas cleaning, compression and storage at AD plants producing around 9m3/h biogas, and to deliver it off site wherever there is an appropriate heat load demand. In doing this we will also test how lower or intermittent production of biogas could be harnessed using the demonstration product. The sequence of tasks that will take the project from its current stage to one where EHV Engineering can start to market it as a product includes: 1 Finalise the implementation plan 2 Obtain permits & other approvals 3 Let external contracts, including commercial boiler operator(s) 4 Realise project financing 5 Fabricate, assemble and test the product 6 Transport, install, commission, operate, monitor and evaluate product at first site 7 Decommission and transport product to second site 8 Re-commission, operate, monitor and evaluate product at second site 9 Handover equipment to RASE appointed personnel 10 Review performance and develop commercialisation, product manufacturing/assembly,

and sales plan 11 Prepare final report for WRAP and sponsors Descriptions of the work to be undertaken under each of the above tasks, are given in Part 2 of this report, which has been set out as detailed in WRAP’s guidelines. We are preparing a technology package which will be suitable for integration with low cost AD plants and its market is dependent on the low-cost AD plants becoming a reality. Our aim is to demonstrate that our product will be simpler and cheaper than the CHP, which is the natural option at this stage. Our product will be economically attractive only by considering the incentives offered under the RHI scheme.


4.0 State of technology 4.1 Development history of the technology Large scale biogas cleaning for use in heat or CHP generation is already well established, and more recent developments have focused on the production of biomethane for vehicles or gas grid injection. These technologies are suitable at much larger scale than that considered in this project. Small scale AD plants are basically those that take materials (livestock slurries, agricultural residues) from within the confines of the farm, which are capable of generating between 5 and 10 m3/h of biogas. Although there are well established technologies for biogas clean-up, there is considerable on-going development work to improve them and reduce their cost. As indicated above, we have undertaken feasibility studies on two possible technologies that we considered appropriate for small scale application:

Option 1 - a gas/liquid absorption membrane contactor, and Option 2 - a Downflow Gas Contactor (DGC).

4.1.1 Gas/liquid absorption membrane contactor Gas-liquid absorption membrane is a relatively new concept, where a membrane can be used to bring about G/L contact between the biogas to be scrubbed and liquid to absorb CO2 (and if required) H2S into. The key element is a micro-porous hydrophobic membrane at the G/L interface that allows molecules from the gas stream, flowing in one direction, to diffuse through the membrane to be absorbed by the liquid flowing in a counter current direction. As the system can operate at ambient temperatures, and using low pressures throughout, the material specification and therefore the cost of construction would be competitive with other membrane systems. The liquid phase can be made of various solutions. CO2 for instance can be removed using an amine solution, where the CH4 concentration in biogas can be raised from ~55% to over 96%. The amine solution can be regenerated by heating, and the CO2 released is relatively pure grade so it can be sold for industrial applications. If H2S is also required to be scrubbed then the solution will be sodium hydroxide (NaOH). H2S saturated solution will have to be managed so as to recover elemental sulphur (e.g. by oxidation of dissolved H2S). Pall Corporation has developed a pleated membrane filter pack module used for various gas/liquid exchange applications. At the time of responding to this WRAP project call, its US R&D facility was undertaking trials with a gas mixture of 21% v/v ozone in air, using a standard infuser module with 1m2 contact area. In the limited time and budget available for the WRAP project, it was not possible to undertake any trial dedicated to the absorption of CO2 from biogas. It has only been possible to interpret the results of the now completed trials for ozonation. The results of this interpretation are presented in Appendix 1. It may be seen in that appendix that in order to provide sufficient contact area for stripping CO2 from biogas at an input rate of 9m3/hr of biogas, it would be necessary to use at least six of these modules (each about 1m long and 75mm diameter) packed inside a vessel of minimum diameter 3m, height 1.5m, as indicated in Figure 4.


Figure 4: Outline sketch of a gas-liquid contactor vessel

Two such vessels would be needed, since a similar arrangement would be needed to disengage the CO2 from the liquid absorbent in the secondary loop. 4.1.2 Downflow Gas Contactor The WRK Downflow Gas Contactor (DGC) comprises a vertical column into the top of which is introduced biogas and adsorbent liquid, and out of the bottom of which emerges liquid containing preferentially adsorbed gases (CO2 and H2S) and entrained bubbles of CH4 (biomethane). For the biogas input rate of 9m3/hr, the DGC would need to be 200mm diameter and 3m tall. The gas and liquid stream are introduced co-currently through a specially designed entry section at the top of a fully flooded column. The liquid pressure at the point of entry into the specially designed inlet is between 2.5 – 4.0bar. The high velocity liquid jet inlet stream generates intense hydraulic shear [stress]. This shear causes the break-up of any gas pocket at the inlet and allows the formation at the top of the column, of a vigorously agitated gas-liquid dispersion with an enormously high interfacial area in a small operating volume; see Figure 5. To release the entrained biomethane the fluid is passed through one of two part-filled horizontal feed/receiver vessels, which are maintained at atmospheric pressure, which has sufficient retention time to allow the bubbles to rise to the surface, at which point the gas is drawn off to storage. On saturation of the absorbent liquid in one feed/receiver vessel the process is switched over to the other feed/receiver Vessel which has unreacted/regenerated absorbent liquid. The CO2 and H2S are disengaged from the absorbent solution in the first vessel by heat exchange from the duty feed/receiver Vessel, and vented to atmosphere, thereby regenerating the absorbent liquid in that vessel.


For the biogas input rate of 9m3/hr the feed/receiver vessels would each need to be 600mm diameter and 2m long. A detailed description of the DGC based system is provided in Appendix 2.

Figure 5: Schematic of diagram of the DGC

It should be notes that a UK Patent application is currently being made through Patent Agents (Marks & Clerk LLP) for ‘Carbon Entrapment from Air and Biogas Enhancement’ using a DGC Reactor, based on the work funded by TSB. At present, the Carbon Trust (through its Entrepreneurs Fast Track) is supporting this application and is helping Dr Raymahasay to develop a Business Strategy and Roadmap WRK received funding from Carbon Trust for the Detailed design of a 400M3/Hr Biogas upgrading plant. 4.1.3 Associated Technologies Biogas cleaning and storage on site (small quantities) has been applied at many locations in the UK and Worldwide. Our product relates to production of compressed biomethane (CBM) for supplying to a commercial boiler scheme to realise the full economic benefits under the RHI. As such transport of bottled gas will be required, together with any necessary adaptations at the host boiler to accommodate the cylinder supply of CBM. An on-site CBM storage system, based on standard 50 litre gas cylinders, is proposed, to be filled to a working pressure of 250bar. A bank of up to six cylinders would provide sufficient storage for 14 days’ production of CBM. An appropriately rated standard natural gas compressor would be incorporated in the facility to fill each cylinder in turn, with standard automatic switchover as each cylinder reaches its design pressure. We have also considered the scope for minimising the cost of compression and bottling, as well as transport, by examining this part of the product where multiple sales in a locality might be realised. This would involve the use of a higher capacity compressor, fitted on a


trailer, which would be capable of serving 2-3 AD plants of similar size, within an economic distance of each other. 4.2 Previous use/evidence to support the use of the technology from other countries,

sectors or industries where applicable Option 1: As indicated above, the use of membrane technology to strip CO2 from biogas does not appear to have been developed beyond contactor bench scale. Gas/liquid membrane contactors have, however, routinely been used for moving gases into and out of aqueous solutions. The mechanism of the process is essentially the same as it is with a conventional contacting column. However, the membrane provides both the contacting area and a barrier to direct contact of the two phases. Although the membrane is a barrier to direct contact of the two phases, it imparts little additional resistance to transport, the overall transport rate being dominated by the liquid film coefficient. The membrane contactor offers some advantages over the conventional gas/liquid contacting towers. Membrane contactors, devices in which hydrophobic membranes promote contact between phases, make important contributions to several useful process intensification methods: membrane reactors, absorbers, and degassers. They also find application in liquid/liquid extractions, scrubbing, stripping and other operations. Option 2:

At present there is no commercial use of the DGC reactors. To date, WRK has undertaken a

wide range of projects based on the application of DGC reactors, including:

Biogas upgrading – removal of Carbon dioxide, Hydrogen sulphide and Siloxanes

Carbon dioxide absorption in seawater for submarines

Oxygen transfer for Thiobacillus ferroxidans in river sludge for gold extraction

Carbonation

Vegetable Oil (Rapeseed, Soyabean) Hydrogenation

Catalytic Hydrogenation reactions in both slurry and packed bed form

Catalytic Oxidation of p-cresol

Treatment of industrial effluent wastes and landfill leachates – reduction in COD levels

Design of Reactors and Separators for Supercritical reactions

4.3 Previous tests i.e. desk-based studies, lab-scale, on the ground Option 1: As indicated earlier, Pall Corporation, as part of this feasibility study, has attempted to interpret the results of an R&D programme for ozonation of water, to establish design parameters for stripping CO2 from biogas. This is the only investigation into the use of membrane technology for stripping CO2 from biogas, known to EHV. Option 2:


WRK recently completed a project funded by the Technology Strategy Board to demonstrate that capture of CO2 from air and mixed gases could be effectively undertaken in a DGC reactor. A paper on this project is available on request.

5.0 Legislation The design, installation, and operation of our technology will be covered by the same legislation and regulation that applies to the AD plant, namely: 1 Environmental permitting and (Waste Management Licenses, in Scotland) 2 Animal By-Products Regulations (ABPR) 3 Duty of care 4 Hazard analysis and critical control points (or HACCP), including H&S regulations9. However, at small scale and particularly with AD plants dealing with simple feedstock, the above requirements are simplified. In addition it would be expected that the site would be accredited to BSI PAS 110 so that the digestate produced could be applied to any agricultural land without requiring a permit or licence. 5.1.1 Standard Permits Standard permits are issued for defined installations, provided they operate within published conditions. Here the information required is not very onerous provided the operator complies with the given rules and meets the generic risk assessment. There are three sets of standard rules for anaerobic digestion facilities for: 1. AD of mainly manures and slurries on farms, 2. AD of a wider range of food and biodegradable waste and 3. Storage of waste digestate at locations away from the AD site. These installations are limited to the use of 3 MW net rated thermal (as fuel input) systems and a maximum of 75,000 tonnes per year waste throughput is allowed. There are also distance limits from watercourses and housing/workplaces for any proposed site location. 5.1.2 Exemptions The Environment Agency allows exemptions for low risk AD activities, which simply requires the operator to register online, free of charge, and provide some information about the operator and the installation. There are two specific waste exemptions for anaerobic digestion:

T24 covers treatment of manures and slurries at premises used for agriculture, for waste up to 1,250 m3, which in effect means the total containment used by the AD plant.

T25 covers the treatment of a slightly wider range of waste including food waste, for below 50m3 capacity for storage and treatment.

9 Dangerous Substances and Explosive Atmospheres Regulations (DSEAR) 2002 under which ATEX (ATmosphères Explosives)

requirements, based on an EC directive by which all electrical equipment to be used in potentially explosive environments must be certified by the supplier as safe to use according to specific risk categories, are also included.


Both of these must not exceed a net rated thermal input of less than 0.4 MW. It is envisaged that no additional permit or fees will be required for the product envisaged in this project. 5.1.3 ADR Regulations As the output of the process (CBM) is to be transported to end users by road, the operation will be subject to The Carriage of Dangerous Goods and Use of Transportable Pressure Equipment Regulations 2009: the ADR regulations. The ADR regulations offer certain exemptions for ‘small loads’ (ADR 1.1.3.6). Small load exemptions relate to the total quantity of dangerous goods carried by the "transport unit" (usually a van or lorry, but also any trailer). The transport category (TC) of the dangerous goods determines the load limit (threshold). CBM would fall within the same TC as LPG. i.e. transport category 2, for which the "small load threshold" is 333 kg. As the density of 250bar CBM is around 0.35kg/litre, this small load threshold equates to around 950 litres of CBM, or nineteen 50-litre cylinders. The scheme envisaged for our project therefore would operate within the small load threshold. For vehicles carrying under the small load threshold, many of the requirements of ADR are not applicable. Some care needs to be taken, as "what is not exempted is still required". The remaining obligations would include:

General training for driver (ADR 1.3.2). A record should be kept (ADR 1.3.3)

Carry one 2 kg dry powder fire extinguisher or equivalent (ADR 8.1.4.2)

Stow the dangerous goods properly (ADR 7.5.7)

The UKLPG has published a code of practice for the transportation of LPG cylinders10 which would apply equally to the transportation of CBM. 6.0 Detailed technical appraisal of technology 6.1 Theory/process behind the technology Our feasibility analysis (Appendix 1) shows that the membrane system (Option 1) will require a great deal of work before it can be taken to the demonstration phase. As such we have turned to Option 2, the DGC based system, which has been shown to offer a high rate scrubbing system for biogas to remove both the CO2 and H2S. Other components covered in the proposed system, referred to as the EHV system, are depicted in Figure 6 below.

Figure 6: Scope of the EHV biogas system

10 Code of Practice 27 - Carriage of LPG Cylinders by Road (July 2009)

http://www.uklpg.org/shop/codes-of-practice/carriage-of-lpg-cylinders-by-road-july-2009/


Technical data relating to the design of the DGC-based biogas cleaning system are presented in Appendix 2. The process flow diagram is reproduced in Figure 7. The basic design parameters assumed in the conceptual design are as follows:

Biogas flowrate 9.0 Nm3/h

CH4 content 60 - 70%

CO2 content 30-40%

H2S concentration, incoming assumed 0.02%

Gas Pressure in incoming line 0.2 kg/cm2

The process requires the use of the following consumables;

Absorbent Liquid salts

Alkali- NaOH; and

Metal Oxide and Silica Gel (if the final stage requirement is for almost pure methane)

The consumption rates have not been projected, but an allowance has been made in the costings.

Figure 7: Flow schematic of the DGC biogas scrubbing system

Scope of EHV biogas system


The basic mass balance is depicted in 8

Figure 8 8

Figure 8: Mass balance around the DGC biogas scrubbing system


6.2 Operational parameters The DGC-based system illustrated in Figure 7 operates as follows: 1 Absorbent solution (mixture of NaOH and sea salts which mainly contain NaHCO3 and

Na2CO3) is fed by a pump into the DGC reactor from the feed vessel through a specially designed inlet at the top through which also the Biogas (at atmospheric pressure) is fed into the DGC.

2 Temperature of the solution is controlled by a jacket and temperature controller looped with heating/cooling water circulation. (During absorption stage cooling is effected and during regeneration of absorbent heating)

3 This absorbent solution, which absorbs the CO2 and H2S, is circulated through the DGC reactor at the required operating pressure and liquid flowrate.

4 Required rate of liquid circulation is controlled by a flow meter and flow control valve. 5 Pressures are monitored at three points by pressure indicators – (i) before inlet into the

DGC; (ii) reactor top after inlet into the DGC ; (iii) reactor bottom at outlet of DGC. Pressures at all these three points are logged.

6 The operating pressure of the DGC reactor is controlled by a flow control valve in the outlet line of the DGC reactor which is looped with the pH control.

7 The reaction pH is monitored as shown in Figure 7 8 The biogas is fed into the specially designed inlet of the DGC through a non-return valve

and a gas flow controller 9 The outlet reacted liquid with unabsorbed/unreacted methane gas passes into the

feed/receiver vessel No 1 and No 2 – as required - which is at atmospheric temperature and pressure, where the gas (methane) disengages.

6.3 Comparison with ‘business as usual’ No ‘business as usual’ alternative biogas enhancement/utilisation system operates at or near the ‘small scale’ at which we are focused. We have therefore compared our product with one which uses a CHP engine on the same site, so the export will be electricity and heat.


Figure 9: Overall system comprising EHV biogas system (AD-Heat) and that based on CHP (AD-CHP), for use in comparison

The same two options have been considered twice: once using the current estimate of AD plant cost and secondly using 40% reduction11. As such four options based on same quantity of biogas are considered in our later comparative technical and economic analysis, as follows: AD-Heat Our approach, integrated with a small scale AD and commercial boiler

application AD-CHP This option is similar to the above but considers CHP AD60%-Heat Similar to AD-Heat but with 40% reduction in AD capex12 (also one of

the aspirations set out in the briefing document of the DIAD competition)

AD60%-CHP This option considers CHP, but with 40% reduction in AD capex (please see section 7)

6.4 Range Our product can be provided flexibly at the small scale end of the AD market. In fact, it will be attractive for up to 200 kWth commercial boilers (the cutoff for entitlement to RHI).

11 This is the focus of the competition (under which this project is funded): to reduce the total installed cost of AD plant, by 40%.

12 Bringing small scale AD to UK farmers – the challenge. Prab Mistry & Ian Smith; presentation made at the European Bioenergy Expo and Conference (EBEC); Stoneleigh Park, Warwickshire, UK; 6 - 7th October, 2010 ([email protected])

Option: AD-Heat

Option: AD-CHP

mailto:[email protected]

mailto:[email protected]


6.5 Life cycle of technology At present we are considering the central DGC reactor to be made out of stainless steel as it will be scrubbing biogas with levels of hydrogen sulphide. The life span of the equipment, together with pumps and related vessels would be at least 15 years, based on regular maintenance of the system. Materials of construction for the final product are currently under review, with the aim of reducing the cost of our product to a minimum once the demonstration and monitoring phase has been completed. Full life cycle of the technology will then be available. i. Life span of equipment Materials and equipment selected in our design specification will have a design life of at least 15 years. ii. Commissioning / decommissioning This will require a period of four weeks initially, due to initial testing of the first installation, including HAZOP related testing. Subsequently, the units will be delivered, connected and commissioned within one day as part of a skid mounted assembly. 6.6 Risk Analysis A detailed HAZOP will be undertaken during the detailed design of the demonstration unit as required for HACCP preparation, as part of a regulatory requirement; see Section 4 on Legislation. The hazard analysis will cover leaks of biogas, pump or compressor breakdown, handling of chemicals, measurement sensor failures etc. 7.0 Economic / Cost Benefit Analysis As indicated above, we have chosen the DGC system to be used with biogas storage, compression and bottling, prior to delivering CBM cylinders to a commercial user. When packaged for multi sales, we expect the price of the DGC-based biogas cleaning system at the demonstration scale to be between £35,000 and £40,000. For the economic analysis below we have taken its price as £40,000. 7.1 Key Appraisal Biogas cleaning system: This is based on the DGC system as described above, at £40,000. Biogas storage: We have acquired quotations for various sizes of gas storage, from Vergas Ltd. and have chosen the smallest possible for use as buffer storage prior to compression. A 50 m3 storage to full spec, on their product will be ~£25-30k. However, for farm scale application, the same size storage can be made from a single skin biogas resistant fabric, in the form of a pillow tank, and tethered on a series of hooks13and would cost around £5-7000. This storage system will have a long life, equal to that of the DGC reactor, as the biomethane will not be aggressive to the fabric of the container. We have taken the value of £6,000 for biomethane storage in our analysis.

13 Personal communications with a biogas storage expert, Nigel Townly-Berry of Vergas Ltd


Compression and bottling: This will be based on a standard integrated system that SMP Ltd. will provide; its price will be £8,500. Based on the above capex, we have made some simply (but conservative) assumptions to present a comparison of the economics of the EHV system with a CHP system dealing with the same level of biogas use. The technical assumptions are given in Table 1.

Table 1: Technical and operational assumptions used in the techno-economic evaluation

Technical assumptions Value

Energy value of CH4 (MJ/m3) 39.50

Average biogas production rate (m3/h) 9.00

Plant availability 100%

Utilisation 100%

Operation hours/y 8,760

Dedicated, commercial boiler efficiency 85%

Electricity generation efficiency in CHP 35%

Heat generation efficiency in CHP 50%

Heat for export from CHP (as percentage of energy in methane produced) 25%

Electricity use, parasitic (% of generation) 10%

Output parameters, calculated Methane produced from digester (m3/y) 47,300

Energy in methane produced (kWh/y) 518,990

Rate of energy production as methane (kW) 59

Boiler output (kW) 50

Heat generated by commercial scale boiler (kWh/y) 441,140

Electricity production (kWh/y) 181,650

Electricity export (kWh/y) 163,490

Heat export from CHP plant (kWh/y) 129,750

Table 2: Energy prices and incentives used in the analysis

Parameter Value Units and comments

Electricity - wholesale price 0.0400 £/kWh (own use will be worth higher)

Electricity - FIT incentive 0.1470 £/kWh (current, 2012)

Natural gas - wholesale price 0.0200 £/kWh (conservative)

Heat – linked to wholesale price 0.0235 £/kWh (based on 85% boiler efficiency)

Heat - RHI incentive 0.0710 £/kWh (current, 2012)

Plant availability 100% Design capacity

Utilisation 100% Design capacity

Operation hours/y 8,760 Design capacity

All costs, unless stated otherwise, should be read as at April 2012. 7.2 Comparative Assessment In order to provide a comparative and overall economic assessment of AD plant, with our gas handling product and that based on CHP, we have shown this in two scenarios:


Scenario 1: labeled ‘AD-Heat’ and ‘AD-CHP’ are based on the capital cost of a small scale AD plant capable of producing around 9m3/h of biogas. Scenario 2: labeled ‘AD60%-Heat’ and ‘AD60%-CHP’ are based on 40% reduction in the AD capital cost14 – this is also the subject of the DIAD competition under which this project is undertaken. As such our economic analysis includes that which will apply should the competition reach its goal.

Figure 10: Comparison of capital cost components of heat and CHP options at current and low AD cost

£0

£50,000

£100,000

£150,000

£200,000

£250,000

£300,000

£350,000

AD-Heat AD-CHP AD60%-Heat AD60%-CHP

Capital cost components

Grid injection -connection

Biogas boiler - useful heat

generator

Compressor and bottled storage on site

Gas storage

Gas scrubbing

CHP plant

AD plant cost

Figure 11: Comparison of operating costs and income of heat and CHP options at current and low AD cost

-£50,000

-£40,000

-£30,000

-£20,000

-£10,000

£0

£10,000

£20,000

£30,000

Operating cost components

Electricity - FIT income

Electricity - wholesale export

Heat income -RHI

Heat - wholesale price

Operation & Maintenance

14 Bringing small scale AD to UK farmers – the challenge. Prab Mistry & Ian Smith; presentation made at the European Bioenergy Expo and Conference (EBEC); Stoneleigh Park, Warwickshire, UK; 6 - 7th October, 2010 ([email protected])


Table 3: Economic comparison of heat and CHP options using discounted cash flow analysis

DISCOUNTED CASH FLOW AD-Heat

AD-CHP AD60%-Heat

AD60%-CHP

Total Installed cost (£) £268,60

0 £308,000 £185,600 £225,000

Construction/commissioning time (y) 1 1 1 1

Plant's operating life (y) 20 20 20 20

Operating costs £13,500 £18,400 £9,300 £14,300

Forecast revenue (from heat/ele) -£41,800 -£42,900 -£41,800 -£42,900

Net operating cost (£) -£28,300 -£24,500 -£32,500 -£28,600

Payback time (years) 9 13 6 8

IRR 8.5% 4.9% 16.7% 11.2%

As can be seen from the analyses above, the EHV biogas system, when integrated with a commercial heat boiler, will provide a more attractive proposition than that comprising on-site CHP. This is achieved by lower capital cost and higher annual income. For small scale AD plant capable of producing around 9m3/h of biogas with the heat option shows IRR of around 8.5% compared to 5% for that with CHP scheme; however, with the reduction of 40% in AD plant costs, these returns rise to 16.7% and 11.2%. 7.2.1 Scope for further cost reduction It is possible that a business could be set up around compression and delivery of CBM to serve commercial heat boilers. It is possible that a 40-50 kWth boiler will be able to take biogas from one small scale AD plant. Clearly, not all small digesters will be producing biogas at this same rate; with some being larger and smaller. Our product can be tailor made using the same basic units. It is also possible to reduce the cost of compression and bottling by designing a system with sufficiently large compression capacity to serve more than one digester. This way the function of the biomethane storage becomes more important, as it will need to have sufficient capacity to hold biomethane until such time as the trailer mounted compressor and bottling system returns to site with empty cylinders; the same trailer would be able to serve the commercial boilers in the locality. The attractions of this approach are:

Economies of scale with the compression, bottling and delivery of biomethane after cleaning.

A greater volume of biomethane will be maintained, to ensure that the commercial boilers are fed with renewable fuel supply.

When CBM fuel is in short supply the boiler can switch to natural gas.

A possible disadvantage of such a system would be the lack of willingness of each farmer in the local collection arrangement to enter into agreement, in case the service is delayed, or worse – suspended.


However, such a multiple facility servicing arrangement could become a marketing opportunity to enhance sales of the product in localities where a number of small scale AD plants might be installed. 8.0 Overall Environmental Impacts We have undertaken an outline GHG balance on each of the four options outlined above. It assumes that the feedstock used to produce biogas is dairy cattle slurry, to assess avoided GHG emission as well as GHG saving due to N-benefits from the use of digestate as fertiliser. The figure below also gives the GHG savings due to the net energy export being used to displace fossil fuels. To undertake this analysis we have used the factors produced by REA and DECC, as follows:

GHG emission avoided using 57.0 kgCO2e/t of waste

GHG emission displaced by using digestate on land based on 5.100 kgCO2e/t of waste

GHG reduction based on electricity export, using the UK fuel mix, is 0.458 kgCO2/kWh; and

GHG reduction based on heat export, by displacing the use of fossil natural gas, is 0.224 kgCO2/kWh.

Figure 12: GHG balances of heat and CHP options

-350

-300

-250

-200

-150

-100

-50

-

AD-Heat AD-CHP AD60%-Heat AD60%-CHP

Heat export (tCO2/y)

Electricity export (tCO2/y)

GHG avoided due to Fertiliser-N saving (tCO2/y)

GHG emission avoided (tCO2eq/y)

As can be seen from the figure above, the GHG balance for any of the options considered above is almost equal. The difference is due to the options being considered: heat versus electricity; where heat generation shows a more favourable GHG balance than that for CHP. There are other more indirect environmental impacts of the scheme which stem from the manufacture of the various products used as well as any effluents and emissions that would be generated during the operation of the EHV gas handling. This is expected to be no different to any other scheme but will be investigated during the demonstration phase.


9.0 Principal Conclusions from Feasibility Assessment All aspects of the proposed product have been analysed in this feasibility study. We are satisfied that the overall concept will result in a biogas treatment and cylinder filling facility that can be co-located on farms with small scale AD plants to produce CBM that would be marketable. However, the level of research undertaken to date on the emerging technology considered here for biogas scrubbing, using the membrane contactor technology (Option 1) does not permit reliable, optimal extrapolation of costs for field scale operation in Phase 2. Option 2, the DGC based scrubber system, would however appear to offer a high degree of certainty in its performance, and although the initial estimate of cost of the Phase 2 demonstration unit (indicated in Part 2) is still high there are opportunities to reduce this through value engineering, as discussed in Part 2. Economic appraisal of Option 2 suggests that the capital cost of such a system in a commercial sale would be in the range £35k to £40k per unit. It may be seen later, from Part 2 of this report, that there is a market for several thousand such units in this price range, as the market may support a price up to £64,000 per unit. Its natural competitor for biogas utilisation from farm-based AD plants is the installation of a CHP plant. At the small scale operation under consideration, the total installed cost of a CHP plant has been assessed as around £34k. All costs and benefits associated with the heat and CHP options were analysed above. However, the analyses showed that the EHV biogas system, when linked with a commercial heat boiler, will provide a more attractive proposition than that comprising on-site CHP. This is achieved by lower capital cost and higher annual income. For small scale AD plant capable of producing around 9m3/h of biogas, the heat option shows an IRR of around 8.5% compared to 5% for that with a CHP scheme; however, with the reduction of 40% in AD plant costs, these returns rise to 16.7% and 11.2%.


PART 2: DEMONSTRATIONS (Phase 2)

10.0 Methodology for demonstration Our product combines a well-researched and developed application of downflow gas contactor (DGC) technology to produce almost pure biomethane with established gas compression technology to deliver a portable supply of CBM that would be marketable in a wide range of commercial heating applications. WRK Design Services will undertake the task of fully designing and building the DGC-based system, and deliver, install and commission it at the first demonstration site. The rig will be mounted on a double axle trailer frame for ease of transport to subsequent demonstration sites. Several small-scale AD plant sites have been identified, two of which will be chosen, for demonstrating our product. A principal route to the market for our product is through suppliers of small scale, on-farm AD systems. These include Biotech Services, Envar Ltd, Ever Green Gas, HIRAD Biogas, Kingdom Bioenergy and Marches Biogas. These companies will be contacted, visited and provided with detailed technical and financial information on the benefits of the gas clean-up and supply system. EHV will provide a core team of four highly experienced professionals, including the owner of the DGC technology, and supported by technician grade staff to undertake the work programme. We are proposing a realistic timetable (of 15 months) for the execution of Phase 2, with logical progress milestones that will enable WRAP to verify that the project on programme for successful completion. The project personnel that we would deploy to Phase 2 are fully proficient in the areas of expertise needed to deliver the project.

In the following sections we give a detailed description of the tasks for Phase 2, which will lead to a robust demonstration at commercial scale of a novel technology and will fill the gap in the market for cost-effective utilisation of biogas from small scale on-farm AD plants. 11.0 Complete and detailed project timescale 11.1 Project development and implementation plan We anticipate that from instruction to proceed with Phase 2 we will be able to complete the demonstrations and submit a Phase 2 report to WRAP within 15 months. Figure 13 provides a draft work programme, which we would finalise within two weeks of receipt of that instruction.


Figure 13: Gantt chart based on Phase 2 work programme Jul'12 Jan'13 Jun'13

M1 M2 M3 M4 M5 M6 M7 M8 M9 M10 M11 M12 M13 M14 M15

Project development and implementation plan

Confirm site(s) with relevant gas production

Prepare design specifications of integrated process units D1

Permitting and other regulatory approvals

External contracts, inclu commercial boiler operator(s) D2

Project Financing

Construction/Installation of EHV product

Fabricate

Assemble

Works test the product D3

Install and commission at first site

Operate, monitor and evaluate at first site

Decommission and transport product to second site

Re-commission, operate, monitor and evaluate product D4

Handover equipment to RASE appointed personnel, as appro

Review performance of the two sites

Develop commercialisation, manufacturing and sales plan

Draft final report for WRAP and sponsors D5

Final report D6

Project management (communication & reporting)

Project tasks

11.2 Permitting & other approvals Our demonstration plant deals with gas cleaning, compression and bottling which needs to integrated with an existing AD plant. Our system will be delivered to, and installed at each site on a trailer, and will be straight forward to connect. Any permitting or authorisations will be undertaken as variation to such permits and connected with the AD plant. Given the temporary nature of the demonstrations at each site, it is viewed as unlikely that any planning consent will be necessary. We will nevertheless consult with the respective planning authorities to confirm this. We have held discussions with the Royal Agricultural Society of England (RASE) about siting our demonstration plant at their site at Stoneleigh Park for our second demonstration. The scale of our unit is such that it lends itself for educational purposes. This necessitates a small scale AD plant near or at the RASE site. We are due to hold further discussions to finalise this. 11.3 External contracts including commercial boiler operators Our technology package links to the AD plants directly and hence there will be supply agreements with those who own and operate the host AD plants. The contracts will specify how, when, where and by whom service connections will be made (power, water supply, drainage, and of course biogas supply). It will be necessary for safety reasons for the AD operator to maintain the existing biogas utilisation system, including any flare, to deal with any unforeseen need to shut down the demonstration unit at any time. Similar contracts would need to be entered into with potential commercial users of the CBM. However, given the cost of provision of the necessary storage and connection facilities, and the fact that CBM will only be generated for a two month demonstration period from each site, we do not propose to identify any such commercial outlet. For the demonstrations, therefore, we propose to arrange with the host AD plant operator to re-introduce the CBM into the biogas supply line to its energy recovery system (gas engine).


Other supply contracts will be let with materials and equipment suppliers as soon as detailed specifications have been prepared and issued, and acceptable quotations received. 11.4 Project Financing The total cost of the demonstration phase is shown later (see Section 12) to be £248,175 + VAT (or £297,810 total). 75% of this is sought as grant from WRAP, due to the need of testing and monitoring for demonstration purposes; it will incorporate more instrumentation than would be required for the standard biogas cleaning, compression and bottling system. If the final equipment is to be donated for educational purposes, EHV will seek a greater portion in grant. Terms of financing are a pre-requisite to this project going ahead, as EHV Engineering is at present a micro size company. We look forward to our engagement at the Investment and Sponsorship event, at Stoneleigh Park.

We understand that RASE15

may be interested in incorporating the demonstration plant into

facilities at or a farm near its site at Stoneleigh Park, on a permanent basis. We would welcome such an arrangement and as part of the negotiations with RASE on funding the project we would draw up terms and conditions for a non-transferable user licence to operate the plant. 11.5 Construction A high degree of work covering the design, engineering, fabrication and assembly, but including mounting on trailer will be done off-site and supplied by WRK Design Services Ltd. Works testing of the whole assembly, before dispatch and at the point of demonstration site will also be carried out by WRK; see Appendix 2. The trailer will be supplied by SMP Ltd, together with the compressor and 6 compressed gas bottles already installed (see Appendix 4). 11.6 Install and commission product at first site Once the equipment on the trailer has been Works Tested, it will be towed to the first site and located close to the AD plant.

Connections will be made to existing services, as indicated above. The 50m3 pillow tank will

then be carefully installed adjacent to the trailer and connected to the biomethane outlet from the receiver/feed vessel and to the compressor. The pallet mounted agricultural grade 1000-litre tank will be located on the ground adjacent to the trailer and the associated transfer pump connected to an inlet port in the receiver/feed vessel. If no suitable drainage connection is available nearby, we will provide an appropriate container to receive spent liquor from the drain in the receiver/feed vessel. Temporary arrangements will be made for re-introduction of biomethane into the biogas energy recovery system.

15 Personal Communications between Prab Mistry of EHV Engineering and Jef Tuyn of RASE; March 2012.


When the system is fully installed we will commission the plant in accordance with a Commissioning Plan developed at the time of detailed design. This will start with unit testing of each part of the system. At this time we will also test the correct operation of all safety features, such as alarms and unit shutdown. Integrated testing will follow, monitoring performance and simulating process actions, such as switching receiver/feed vessels on the pH monitor recording the set trigger level and automatic switchover of cylinder being filled on the pressure monitor reaching the design figure (250bar). In the reduced cost demonstration unit, which will not include the second receiver/feed vessel, the programmed response to the pH monitor reaching the set point would be to shut down the biogas cleaning operation, drain the receiver/feed vessel (timed drain function), and to recharge it with fresh reagent from the 1000-litre tank (level control in receiver/feed vessel) and restart the biogas cleaning operation. Integrated testing will also include testing for the correct operation of all safety features that trigger unit or system alarms and automatic shutdown of the plant, such as the events of excess pressure being recorded in the pillow tank and excessively high pressure in the cylinder filling equipment, due to, for instance, all connected cylinders being full. The commissioning exercise, which should be completed within two or three days, will be fully documented, in accordance with the requirements of the Commissioning Plan, and included as an appendix in a report to WRAP on the installation and commissioning of the demonstration plant at the first site (D2). 11.7 Operation, Monitoring and evaluation The plant’s operation will be demonstrated at each site for a period of two months. The demonstration plant will be designed for automatic operation. However, there will be a need for periodic inspections of the level of the reagent remaining in the 1000 litre reagent tank, and of the status of the CBM cylinders. Removal of full cylinders and connection to the existing biogas utilisation system, and return of empty cylinders to the demonstration plant will also be needed. If there is no convenient drainage system into which spent reagent can be drained, then periodically it will be necessary to transport the contents of the spent liquor container to the nearest appropriate disposal point. Although there is a cost associated with this it is thought to be negligible and has been considered inclusive to the demonstration costs. Our intention is to monitor its performance in the first few weeks by frequent visits from the project team, noting the monitoring and control system visual outputs (meters and status lights) and downloading detailed, continuously captured operational data from the data-logger, for evaluation between visits. During the remainder of the operating period, we will visit on a weekly basis to check on the continued automatic operation of the plant, and to undertake routine maintenance activities associated only with the low cost demonstration plant (re-filling of the reagent tank as necessary, emptying the spent reagent container if used)

The following parameters will be continuously monitored and recorded in the datalogger:

Flow and composition of biogas to the DGC scrubber

Flow and composition of biomethane led to the pillow tank


Pillow tank pressure

Reagent circulating pump operation (stop/start times)

Reagent transfer pump operation (stop/start times)

Drain valve actuator operation (open/shut times)

Compressor operation (stop/start times)

Compressor delivery pressure

Timing of cylinder changeover.

Other, discontinuous monitoring will be undertaken throughout the operating period, including:

Composition of the reagent, analysed from samples taken from the reagent tank

Composition of the spent reagent from a sample taken from each dump to container

Analysis of CBM, taken from randomly selected cylinders

Mass of reagent supplied/used

Mass of CBM produced, from weighing each cylinder full and empty.

Total power consumption during operating period, from consumer meter in power supply cabinet on trailer

11.8 Decommissioning and transport of product to second site On completion of the two months’ operation at the first site, the installation of the demonstration plant will be decommissioned and service connections removed. The trailer mounted plant will be towed to the second site and the pillow tank carefully dismantled and folded for transport, together with the pallet-mounted tank, to the second site. The site occupied by the demonstration plant will then be reinstated to the satisfaction of the AD plant owner. 11.9 Re-commission, operate, monitor/evaluate product at second site As indicated above, we are hoping to undertake our second demonstration at RASE’s site at Stoneleigh Park, utilising biogas from an AD plant to be established at that site. This would significantly simplify the various tasks that would need to be undertaken in setting up the demonstration plant and in subsequent commissioning, operating and monitoring its performance. The various related activities would be a replication of those undertaken at the first site. Being located at an educational facility, we would expect considerable interest from RASE in its operation, and have allowed for a limited amount of informal instruction of RASE technical staff in the theory and practice of biogas cleaning based on the downflow gas contactor. 11.10 Handover equipment to RASE appointed personnel On completion of the two month operation of the demonstration plant, we would hand over the entire plant to RASE, together with copies of all documentation provided to WRAP during Phase 2 of the project to that point in time, plus copies of any O&M manuals of bought in equipment incorporated into the EHV system. RASE would then be free to operate the plant, in accordance with the user licence agreed at the commencement of Phase 2 of the project.


11.11 Prepare final report for WRAP and sponsors As the project enters its second demonstration period we will start to prepare our Final Project Report, in accordance with guidelines issued by WRAP. As data from the second demonstration becomes available we will consolidate them with those from the first demonstration and undertake a full analysis of the findings. The report will present these data analyses, including mass and energy balances, and actual costs associated with building and operating the demonstration plant (albeit for limited periods). With the data available from the operation of the non-reagent recovery system we will be able to make firm projections of capex and opex for a similar plant that incorporates full reagent regeneration capability (twin receiver/feed vessels with heat exchangers). We will submit the report to WRAP as a Draft Final Report (D5), for its comments, on receipt of which we will finalise it and issue it to WRAP (D6) and, with WRAP’s permission, to each of our sponsors. We have allowed a period of two weeks for consideration of the Draft Final Report by WRAP and issue to us of its consolidated comments. 12.0 Cost breakdown and milestones 12.1 Overall cost of Phase 2 The cost estimates in Appendix 2 for the supply of just the DGC based system for the demonstration plant is £158,000 which excludes the costs for the gas compression system and the pillow tank, plus staff time, costs and travel and expenses associated with operating and monitoring the demonstration project. We are concerned that the indicated level of total cost for the Phase 2 work may be perceived as unacceptably high for the WRAP programme. We have therefore considered modifications to the scope of supply in the demonstration plant. That would significantly reduce the cost of the demonstration version of the DGC-based element, and improve the overall cost of undertaking Phase 2 work. These modifications, centre on omitting the reagent regeneration capability of the demonstration. The impact of which will be investigated during the demonstration project. As such, the overall cost of acquiring the DGC based system, for Phase 2 testing and demonstration would reduce to £112,000 plus VAT. The overall cost of the project comes to is given below.


Supply DGC based equipments and commissioning of plant to first site (WRK Design Services Ltd)

£112,000

Trailer mounted compressor and bottled storage system £16,500

Biogas storage (50m3) £6,000

Host/AD operator payments (2 sites @£2500 each) £5,000

Consumables (chemicals, utilities, waste disposal) £15,000

Transportation of test rigs and equipment, insurance. (all stages) £4,600

Other costs (authorisation/variation fees etc) £3,000

£162,100

Other sub-contractor costs

Subcontractor - WRK £13,500

Subcontractor - E&Sp £7,475

Staff costs - EHV (PM, MP & technician) £61,600

Travel & Subsistence £3,500

£86,075

Total project £248,175

VAT (@20%) £49,635

Total price (inclusive VAT) £297,810

12.2 Milestone payments We have assessed the pattern of expenditure over the 15 month programme and propose the following milestone payments:

Delivery Milestone Price VAT Total D1 Report on final design and engineering £7,500 £1,500 £9,000 D2 Authorisations and contracts to proceed

with construction £10,000 £2,000 £12,000

D3 Completion of construction with any works tests

£155,000 £31,000 £186,000

D4 Report on biogas scrubbing, cleaning and storage trials

£35,000 £7,000 £42,000

D5 Submission of Draft Final Report £30,000 £6,000 £36,000 D6 Submission of Final Report £10,675 £2,135 £12,810 12.3 Funding provisions Considerable efforts have been expended by the team in planning our Phase 2 testing and demonstration project that will provide a novel biogas handling system for small scale AD plant. As mentioned above, the total cost of the demonstration phase is shown to be £248,175 + VAT (or £297,810 total). 75% of this is sought as grant from WRAP, due to the need of testing and monitoring for demonstration purposes as it will incorporate more instrumentation than would be required for the standard biogas cleaning, compression and bottling system. If the final equipment is to be donated for educational purposes, EHV will seek a greater portion in grant. We look forward to our engagement at the Investment and Sponsorship event, at Stoneleigh Park.


13.0 Commercialisation of technology post demonstration 13.1 Market Size The size of the market for equipment to clean, store and bottle biogas for subsequent use in conventional gas boilers depends in the first instance on the number of small scale, on-farm AD plants that might be built in the UK. Such plants are likely to be sited on livestock farms and would process farm slurries and potentially energy crops such as maize. There are 64,000 livestock farms in England alone and more than 120,000 across the UK. Not all livestock farms, however, will benefit financially from installation of an AD plant. In 2010 AEA and the Royal Agricultural Society of England (RASE) undertook a study (Mistry and Smith, 2010), which used a previously developed GIS model (for Defra) to assess the economic feasibility of construction and operation of small scale, on farm AD plants on livestock farms in England. The modelling looked only at the livestock farms in England, and not the whole of the UK, and used the following assumptions:

Only slurries from livestock are fed to the AD plant

Seasonal and all year housing of livestock was examined

A gas engine is used to generate electricity from the biogas

A Feed-in-Tariff of 11.5p / kWh was included

The Renewable Heat Incentive was not included

The modelling also looked at the impact of the overall capital cost of the small scale, on-farm AD systems on economic viability. Three capital cost scenarios were examined:

The capital cost at the time of the modelling

A 20% decrease in capital costs

A 40% decrease in capital costs

For the purposes of this report a 40% decrease in capital costs is assumed as work undertaken by AEA and RASE, in consultation with the AD supply industry, has indicated that cost reductions of this size can be achieved. The work indicates that reductions in costs could arise from high volume modular production and by removing the need for pre-project assessments, and that these improvements could lead to a reduction of between 30% and 55% on current costs. The purpose of the WRAP managed Small Scale, On-farm AD Challenge is to realise these cost reductions and the assumption has therefore been made that the Challenge will be successful. Furthermore, only those modelling scenarios with seasonal livestock housing have been taken into account, as this is the current industry practice. On this basis, and bearing in mind the above assumptions, the numbers of livestock farms in England that might financially benefit from an on-Farm AD plant was estimated to be 1,481. The 1,481 farms are primarily dairy farms and pig farms, with the highest rates of return on investment generally being achieved at pig farms. The approximate size of dairy and pig farm at which the rate of return on an investment in an on-farm AD plant becomes positive is as follows:

Dairy: 200 cows

Pig: 750 pigs

Based on available data it is estimated that there are currently approximately 2000 pig and dairy farms greater than the above size in the UK. Therefore for up to 2000 farms across


the UK it might be financially beneficial if an on-farm AD facility were installed, based on a feed-in-tariff of 11.5 p / kWh. However, since the modelling described above was undertaken the feed-in-tariff for electricity derived from biogas has been increased to 14.0 p / kWh and the Renewable Heat Incentive (RHI) has been introduced currently providing a payment of 7.1 p / kWh of heat utilised from AD facilities below 200 kWth. If the following assumptions are made then the effective subsidy on each kWh of electricity can be calculated:

That the amount of electricity produced from biogas is equivalent to 35% of the biogas fuel value.

That the useable heat produced by the gas engine is equal to 50% of that in the biogas consumed.

That RHI can be claimed on only 50% of the heat produced (as 50% is assumed to be needed to heat the digester or is of too low grade to be routinely used).

This gives an effective subsidy on each kWh of electricity produced of the feed-in-tariff plus 25/35 of the RHI (as only half the heat produced qualifies for the RHI). This gives an equivalent subsidy of 19.5 p / kWh of electricity produced. This figure is significantly higher than the 11.5 p / kWh used in the modelling described above, so the number of farms that might benefit from an on-farm AD plant will be larger. The above modelling also looked at the effect of doubling the Feed-in-Tariff to 23 p / kWh. This had the effect of increasing the number of farms that might benefit from an AD plant by a factor of 2.15. If it is assumed that the number of farms benefiting from an on-farm AD system increases linearly as the FiT increases from 11.5 to 23 p / kWh, then the number of farms that would benefit at an equivalent subsidy of 19.5 p / kWh of electricity is approximately 3,500. This figure of 3,500 represents an estimate of the number of livestock farms that would financially benefit from an on-farm AD plant treating livestock slurries only. It is also worth noting that there are very few on-farm AD plants in the UK at present, so the great majority of these sites are available for new installations. Furthermore, the figure would be significantly larger if energy crops (e.g., maize silage) were considered as part of the feedstock. Modelling undertaken by AEA has indicated that if up to 900 tonnes of maize silage were co-digested with the animal slurries then on-farm AD would be viable at 2,000 to 3,000 more farm sites in the UK. Future rises in energy prices would also increase the number of farm sites at which AD would be viable. The number of sites on which on-farm AD would be viable has been calculated assuming a 40% reduction on current capital costs, current levels of FiT and RHI and a gas engine/ CHP unit to generate electricity and useable heat. However, the significant potential market size that has been demonstrated will apply to a system to clean, supply and bottle biogas for use in a conventional gas boiler only if that system is financially beneficial compared to a gas engine. This comparison is considered below. 13.2 Economic viability 13.2.1 Gas engine / CHP The great majority of currently installed AD systems in the UK, including on-farm systems, combust the biogas produced in a gas engine to generate electricity. Heat is also produced by the gas engine that can be recovered to heat the digester and for use locally on the farm. The typical size of gas engines required, based on the modelling described above, is in the


range 17-56 kWe. The costs and incomes associated with installing and operating a gas engines near the centre of this range (35kWe) is described below. Capital and operational costs

CHP (gas engine) Generator (kWe)

Heat generated by CHP (kW)

Capital cost of gas engine / CHP unit16

Capital cost of grid connection

Operational costs (£ per annum)

35 50 £52,000 £10,000 £10,400 Operational costs are estimated to be 20% of the capital costs per annum. This figure may seem high, but maintenance costs are generally higher per kWh for small gas engines than larger engines. 13.2.2 Income streams Income streams are calculated on the basis that the gas engine operates for 90% of the time and that 10% of the electricity is used as parasitic load. It is also assumed that 50% of the heat is required as a parasitic load or is of too low grade to be used. The efficiency of conversion to electricity is set at 35%, typical for operational gas engines, and the remainder of the CV of the biogas is converted to heat. The income generated per year, with electricity sales at 4p / kWh, would be: Electricity sales = 35*0.9*0.9*0.04 *24*365= £9,934 Heat sales = 50*0.5*0.9*0.01*24*365 = £1,971 FiT income = 35*0.9*0.9*0.14 *24*365= £34,768 RHI income = 50*0.5*0.9*0.071*24*365 = £13,994 A small conservative value of 1p / kWh is given to heat sales as the heat has to be used as it is generated and therefore may not be used all year round. This calculation indicates that if the cost of the AD plant is ignored, the payback period for the gas engine / CHP unit is just over 14.8 months. 13.2.3 Gas cleaning and supply Below the capital and operational costs of a system to clean, compress and supply biogas for use in conventional gas boilers are described. The costs are based on a system to treat 100 kW of biogas, as described for the CHP / gas engine system. Capital and operational costs Heat generated (kW)

Capital cost of system to clean and supply gas

Operational costs (£ per annum)

100 £40,000 £4,000 The anticipated capital cost of the system is estimated at this stage to be £40,000. Operational costs are estimated to be 10% of the capital cost of the system, and this includes regeneration of the solvents.

16 Our comparative economic analysis, in the first part of the report, has used a lower CHP cost.


13.2.4 Income streams Income streams are calculated on the basis that the system to clean, compress and supply gas operates for 90% of the time. It is assumed that 15% of the gas is used as parasitic load to heat the digester, and the remainder of the gas is exported for use in gas boilers on or off farm. The gas sale price is set at 2p / kWh. The income generated per year, including heat sales is: Heat sales = 100*0.9*0.85*0.02 *24*365= £13,403 RHI income = 100*0.9*0.85*0.071*24*365 = £47,580 This calculation indicates (assuming the cost of the AD plant will be the same whichever gas utilisation is chosen), the payback of gas clean-up and supply equipment is 8.4 months. This system is therefore more financially beneficial than the CHP/gas engine system. The two systems would provide a similar rate of return only if the gas clean-up and supply system approached a £64,000 capital cost. This indicates that there is a market for several thousand gas clean-up and supply units at £40,000 per unit and that the market may support a price up to £64,000 per unit. 13.3 Approach to the Market The small scale AD systems of which the gas clean-up and supply equipment would be a component will be based largely on farms. However, the AD systems to be installed are unlikely to be specified by farmers themselves, and it is more likely that the suppliers of small scale AD will advise farmers on the design of the AD system and associated biogas utilisation plant. A two pronged approach to the market is therefore envisaged:

Direct contact with specifiers, suppliers and installers of small scale AD plants and provision of technical and financial information on the benefits of the gas clean-up and supply system over the more conventional gas engine / CHP approach.

Provision of information to the many thousands of farms that might benefit financially from the installation of a small scale AD system. The marketing material would explain the benefits of on-farm AD and specifically the advantages of clean-up and supply of gas for use on or off farm, as opposed to electricity generation on-farm.

The above two marketing campaigns would be very different in scale. There are only a few suppliers of small scale, on-farm AD systems (which include Biotech Services, Envar Ltd, Ever Green Gas, HIRAD Biogas, Kingdom Bioenergy and Marches Biogas) and these companies would be contacted, visited and detailed technical and financial information on the benefits of the gas clean-up and supply system would be provided. The reasons for contacting the farmers would be to make them aware of the benefits of the proposed biogas clean-up system so that they know it is an option when considering installing an AD plant and either specify the system or discuss the option with the supplier of the AD equipment. The marketing material would also describe the broader benefits of farm based AD, as the decision to install an AD plant is the first step.


13.4 Commercialisation Plan 13.4.1 Intellectual Property Landscape This document considers two innovative systems for the removal of carbon dioxide and hydrogen sulphide from biogas produced by small scale, on-farm anaerobic digesters so that gas can be sold as compressed natural gas for use as a fuel in unmodified appliances such as gas boilers. The two options being considered are: 1 The use of a microporous, hydrophobic membrane presented as a pleated sheet in a

cylindrical cartridge format. The biogas is introduced on one side of the membrane and the carbon dioxide and hydrogen sulphide in the gas is transported across the membrane and absorbed into a liquid on the other side of the membrane.

2 The use of a DGC (Downflow Gas Contactor) reactor to remove and absorb carbon dioxide and hydrogen sulphide from biogas. The DGC reactor is a mass transfer efficient gas-liquid adsorption device in which the gas and liquid are introduced co-currently through the specifically designed entry section at the top of the column. This causes a vigorous gas-liquid dispersion with a very high interfacial area in a small operating volume.

The technology proposed in Option 1 has been used for the ozonation of water and humidification of air, but has not been used to clean-up biogas. It is our understanding that no patents or other intellectual property rights exist for the use of this technology in cleaning biogas, and intellectual property for existing uses is held by one of the partner companies in this project, Pall Europe Ltd. The technology proposed in Option 2 has been used by WRK Design and Services Ltd to undertake trials of removing carbon dioxide from biogas and intellectual property on existing systems is owned by WRK Design and Services Ltd, one of the partners in this project. A search has been made for patents that have been applied for or granted and that might conflict with either Option 1 or Option 2. The search was undertaken on Espacenet using the key words biogas and carbon dioxide, and biogas and hydrogen sulphide. Patents that are relevant to the removal of carbon dioxide and hydrogen sulphide are listed and briefly described below. None of these patents are considered to conflict with the systems described under Options 1 and 2 above. List and short description of relevant patents

a) SI2066796 (T1) - Method and Device for Separating Methane and Carbon Dioxide from Biogas (application by MT Biomethan GMBH). The invention relates to a method of separating methane and carbon dioxide from biogas and to a device for carrying out the method. These are intended for purifying biogas, wherein carbon dioxide is separated off from the biogas. Starting from the disadvantages of the known prior art, a method is intended to be provided which is distinguished by an energetically favourable mode of operation. For this the solution proposed is that the biogas is passed under atmospheric pressure and standard temperature into the absorption column, wherein while the biogas ascends through the packed bed carbon dioxide present in the biogas is bound in the wash liquid by chemosorption. The purified methane gas is taken off at the top of the absorption column at a


defined flow velocity.; Carbon dioxide bound in the wash liquid is removed by desorption at a relatively high pressure of 2 to 30 bar and a temperature of at least 120 DEG C. Biogas may be separated particularly economically into methane and CO2 by the suggested procedure.

b) SI1953130 (T1) - Method and installation for raw gases containing processing methane and carbon dioxide, in particular biogas, for extracting methane (application by MT Biomethan GMBH). The method of treating biogas for extracting methane, comprises subjecting the raw gas under normal pressure or small negative pressure (50 mbar) in single or multi-stage wash with an amine containing washing solution with an amine concentration of 15% at normal temperature or at 100[deg] C under formation of clean gas flow consisting of methane and water, compressing the washing solution to 8-12 bar and then heating at 120[deg] C and 1-3 bar under a post-reaction duration of 280-1200 seconds and a constant reaction temperature, and cooling the cleaned washing solution below 50[deg] C and then expanding in a second expansion stage on normal pressure. In the compression process, the predominant portion of carbon dioxide and sulfur compounds is separated from the washing solution and removed as gas flow. The existing residues at dissolvable carbon dioxide and sulfur compounds are separated and the cleaned washing solution is cooled to normal temperature and then recycled into the washing stage. During the multi-stage washing, more than 50% of the necessary quantity of washing solution is used in the first washing stage. The washing solution obtained in the washing is heated in two stages by indirectly heating heat exchanger on the reaction temperature. The gas flow is led through two heat exchangers turned in row, cooled on normal temperature and then supplied to a separator, in which water condensed from the gas flow is separated and the water-free gas flow (carbon dioxide and sulfur compound) is exhausted in a pressure-regulated manner. The hot washing solution eliminated from the first expansion stage is used as heat distribution medium for the heat exchanger and is cooled down at 50[deg] C. The raw gas is heated at 20-60[deg] C and a pressure is adjusted to 20-150 mbar. In the first expansion stage over 95% of the portions of carbon dioxide and sulfur compounds is deposited. The gas flow separated from the first relaxation stage (F01) is desulfurized in a desulfurization plant. The washing solution is exposed to an ultrasound treatment during the first expansion phase.

c) US2012024157 - Method to clean impurities from bio-gas using adsorption (application by Adsorptech Inc). A layered absorbent bed to remove impurities from biogas, such as landfill gas. The system can clean the biogas of several impurities such as siloxanes, water, carbon dioxide, hydrogen sulphide and mercaptans. The invention provides for a method of layering the absorbent bed with multiple absorbents, and when used with a conventional pressure swing absorption process or a vacuum pressure swing absorption process can remove contaminants.

d) WO2012003849 – Process for Converting Biogas to a Gas rich in Methane (application by Topsoe Haldor AS et al). Process for converting biogas to a gas rich in methane comprising the steps of : - mixing a carbon dioxide-comprising biogas with steam to form a mixture comprising carbon dioxide, methane and steam; electrolysing the mixture comprising carbon dioxide, methane and steam in a high temperature solid oxide electrolyser cell unit, to obtain a gas comprising mainly hydrogen and carbon monoxide; catalytically converting hydrogen and carbon monoxide in the gas comprising hydrogen and carbon monoxide to methane in one or more methanation steps to obtain a gas rich in methane.


e) W02011152770 - Method, Arrangement and Use Including a Loop Pump

for Separating Carbon Dioxide from Gas (application by JTM Invest AB). The invention relates to a method for the purification/separation/enrichment of a gas or biogas that contains methane and carbon dioxide. The gas is processed by a spirally constructed coil pump together with a liquid by alternating dosing in such a manner that the coil pump is alternately supplied with liquid and gas that leave the coil pump after a pressure build-up and are conducted to a gas separator from which the gas is conducted as needed to a liquid scrubber for continued purification before the gas is transported to a usage site. The liquid in the gas separator is conducted to a stripper tower for the removal of carbon dioxide, after which the liquid is conducted to a liquid tank for being reused in the method/process.

f) GB2470197 – Hydrogen Sulphide Removal (application by John Hayward

et al). A method of operating a combustion engine using biogas as fuel where prior to the biogas reaching the engine it is passed through a filtering system adapted to remove hydrogen sulphide from the gas. Preferably the biogas is produced at landfill and sewage sites and is used to fuel engines to drive generators. The filtering system adapted to remove hydrogen sulphide may be located downstream of a filtering system adapted to remove siloxanes from the biogas. Preferably the system generally includes one or more beds of polymeric resin granules treated with quaternary ammonium compound or an amine or may be a styrene-divinyl benzene polymer treated with iron carbonyl which capture the hydrogen sulphide molecules and keep them bound to the granules until the filter is regenerated.

g) NZ566845 – Gas Treatment Apparatus (application by Flotech Holdings Ltd). Biogas is upgraded by stripping out carbon dioxide and hydrogen sulphide to leave about 98% methane using a counter-flow water scrubber. The raw biogas that has been freed of moisture and particulates is compressed to about 9 bar for introduction to the scrubber using a water flooded screw (WFS) compressor. The water introduced into the compressor with the raw gas has the effect of not only cooling and lubricating the compressor but also partially scrubbing the gas within the compressor prior to the scrubber operation and allowing the use of a single stage compressor. After scrubbing, the methane is flashed and recovered from the water, and at least some of the water from the scrubber is recycled to the compressor.

h) WO 2008049613 - Process for the Biological removal of Hydrogen Sulphide from Gases, in particular Biogas (application be Guenther Lothar). The invention relates to a process for the biological removal of hydrogen sulphide from gases, in particular biogas, by means of biological gas scrubbing in a bioscrubber. Proceeding from the disadvantages of the known prior art, a process is to be provided which is distinguished by a more economical mode of operation. The solution proposed for this is that air or oxygen or an air/oxygen mixture is introduced into an acidified scrubbing solution and dissolved under pressure, gas and scrubbing solution are conducted co-currently in the bioscrubber at a temperature of 15 to 40 DEG C, wherein the scrubbing solution is introduced in a multistage manner into the bioscrubber for the biological conversion of the hydrogen sulphide. Using this procedure it is possible to lower hydrogen sulphide concentrations present in the biogas from 2000 ppm to below 50 ppm. The oxygen which is introduced under pressure into the scrubbing solution is available in full concentration for the biological conversion. The biologically consumed oxygen leads to the fact that expanded oxygen is redissolved and thus becomes active again. As a result the reaction time is


shortened, the consumption of inert matter is significantly reduced and thus a more economical mode of operation is made possible.

i) DK140696 - Plant for manufacturing methane, carbon dioxide and elementary sulphur from biogas (application by Bioscan AS). A plant able to separate the gaseous components found in biogas in the pure singular components: sulphur, carbon dioxide (99.995% pure) and methane usable as nature gas is constructed with a biological filter in which the hydrogen sulphide component in the biogas is bacterially transformed into elementary sulphur by means of sulphide oxidizing bacteria immobilized onto the filter by admixing the supplied biogas with air. The remaining part of the biogas containing the components carbon dioxide, methane and nitrogen is next processed in a pervaporation membrane plan designed such that the gas components methane and carbon dioxide have different solubilities in the membranes; this enables the components to diffuse through the membrane surface at different rates under high compression above said surface, thereby being separated into fractions which on the high pressure side (denoted the retentate in the following) is enriched in methane, and on the low pressure side is enriched in carbon dioxide (denoted the permeate in the following).; Subsequently, the carbon dioxide is liquefied in the permeate in a liquefaction plant 9 whereby the methane present in the permeate is precipitated and may be carried back to the input of the membrane plant, and the pure carbon dioxide in liquid form may be filled onto pressure gas cylinders.

13.4.2 Standards and Regulation Domestic and industrial gas appliances are designed to operate within a certain gas quality specification range. The gas specification in the UK is set by the Gas Safety (Management) Regulations (GS(M)R), which use the Wobbe Index as the main parameter of interchangeability. Interchangeability is defined as the ability to change one gaseous fuel for another without materially changing the safety performance, efficiency or emissions of the appliance. The Wobbe Index (WI) is defines as: WI = H/√d Where H is the heating value of the gas (MJ/nm3) and d is the relative density of the gas. The GS(M)R set the WI in the range 47.2 and 51.41 MJ/nm3, and methane has a WI in the range 47.9 to 53.39 MJ/nm3. It is therefore necessary to clean-up the biogas so that methane content is 95 - 100% if the UK standards are to be met. It should also be noted that most domestic appliances such as boilers and gas cookers could operate with biogas without removal of the CO2. The GS(M)R are set to maintain operational safety and efficiency when changing gas fuel. Other relevant parameters in the GS(M)R are the hydrogen sulphide content and water content of the gas. The hydrogen sulphide content is set at less than 5 mg/m3 and the water content has to be such that the water dew point does not interfere with the integrity or operation of appliances in which the gas is used. The regulations also require that a stenching agent is added to the gas so that leaks can be detected. Mercaptans are used in mains gas and commercial bottled gas for this purpose. A key consideration for the success of the project is whether the cleaned and bottled biogas qualifies for the RHI. OFGEM has been asked this question and the initial response is that


biogas used in this way would qualify for the RHI at the current rate per kWh for heat generated from biogas. Arrangements would need to be agreed on how the quantity and energy content of the cleaned biogas would be measured and how the RHI payment would be made. 13.4.3 Companies Likely to Deliver the Technology Currently the CHP / gas engines used on existing small scale AD plants are supplied as part of the overall package by the suppliers of the AD equipment. The situation is likely to be the same for equipment to clean-up and bottle gas as described in this report. The companies that will deliver the technology are therefore the suppliers of AD equipment, and marketing materials and marketing effort will be targeted at this relatively small group of companies which include Biotech Services, Envar Ltd, Ever Green Gas, HIRAD Biogas, Kingdom Bioenergy and Marches Biogas. 14.0 Key personnel EHV will provide a core team of four highly experienced professionals, all of whom have been heavily involved in the undertaking the feasibility report and preparation of our proposals for demonstrations. Prab Mistry, Director of EHV will be the Project Director, Dr Mistry will also act as EHV’s Project Manager and will be the principal point of contact for WRAP for the execution of the assignment and will ensure that WRAP is fully informed of the progress of the project at all times. He will be responsible for preparing and maintaining the work programme; attending all progress meetings with WRAP; and preparing Progress Reports at each Reporting Date. In view of the complexity of the project, Dr Mistry will appoint Michael Pugh, an associate of EHV to be Project Manager. Mike is a civil engineer with extensive experience in directing and managing multi-disciplinary studies in all aspects of waste management and environmental protection, recently in managing the monitoring, research and evaluation of the retrofitting of the Energos gasification thermal treatment technology to the existing Energy from Waste plant at Newport, Isle of Wight: one of a number of Defra-supported projects under its New Technologies Demonstrator Programme Marketing and Sales advice will be provided by Ed Gmitrowicz, Director of The Environment and Sustainability Partnership. Ed was the Commercial Director of Inetec Ltd, a venture capital funded company developing and marketing solutions for the treatment of organic wastes from the food and drink sector. In that role he was responsible for the development of products and integrated packages to meet customer needs and the strategy for marketing those products to key client sectors. Ed was also the International Business Manager for Future Energy Solutions, the sustainable energy business of AEA Technology. Last, but by no means least will be Sugat Raymahasay, director of WRK Design & Services Ltd. Sugat has single handedly developed the DGC (Downflow Gas Contactor) Reactor that will form the core of the EHV technology, and has been instrumental in bringing the technology to marketable status. He has carried out the design of the DGC specific to this application and will be responsible for the fabrication, assembly and works testing of the entire demonstration plant at his company premises in Birmingham, and for commissioning the plant at each demonstration site. Curricula Vitae of each of the above were submitted to WRAP earlier in connection with this project.


15.0 Evaluation and monitoring for the purpose of WRAP reporting Throughout the operational period at each of the two sites we will undertake extensive monitoring of the demonstration plant. The data from this monitoring exercise will be analysed and evaluated for the purpose of reporting the plant’s performance to WRAP, both

on completion of each demonstration (D3 and D4), and once the plant has been handed

over to RASE, when we will be preparing our Draft Final Report (D5). The post-demonstration reports will record mass and energy balances associated with each demonstration, and a narrative of the execution of each demonstration, identifying any issues that might have arisen, including any apparent anomalies in the monitoring data, with possible explanations. The data captured from the operation of the non-reagent recovery system will be designed to enable us to make firm projections of capex and opex for a similar plant that incorporates full reagent regeneration capability (twin receiver/feed vessels with heat exchangers). 16.0 Health and Safety Working with biogas and compressed gases in a small area raises a number of health and safety issues, which will need to be addressed at every stage of the project. The principal constituents of biogas (methane, carbon dioxide and, to a lesser extent hydrogen sulphide) each has characteristics hazardous to health:

Methane is inflammable and explosive at concentrations between 5% and 15% methane in air.

Carbon dioxide is an asphyxiant, and being heavier than air can accumulate in low unventilated spaces

Hydrogen sulphide is highly toxic, heavier than air, odourless when in dangerous concentrations, and inflammable

Compressed gases pose additional safety risks in the event of accidental damage to or mishandling of gas equipment. The consequences of sudden release of biomethane would include enhanced risk of fire and explosion. The health and safety arrangements that will be in place for the operation of the host AD plant would apply equally to the temporary installation of the demonstration plant. We will request written copies of these and ensure that our staff and all visitors to our plant are fully conversant with the requirements through enforcing attendance at a brief site safety induction. Appropriate PPE will be issued to all visitors to the plant, whilst our staff are in attendance. Appropriate warning notices will be displayed around our plant. It goes without saying that a no smoking policy will be strictly enforced. A safety plan will be drawn up based on mitigating the above risks.


17.0 Conclusion This project addresses a critical factor in reducing the overall cost of applying AD and biogas utilisation on UK farms. Our project specifically addresses the cleaning of biogas and compressing and bottling so that geographically dispersed heat applications can make (economically attractive) use of this renewable resource. This has been a key barrier to widespread installation of AD plants on farms and a successful demonstration of our product will help to remove this barrier. The proposals for Phase 2 of this project outlined above will result in a robust demonstration at commercial scale of a novel technology that will fill the gap in the market for high energy recovery from small scale on-farm AD plants. The product combines a well-researched and developed application of downflow gas contactor technology (DGC) to produce almost pure biomethane with established gas compression technology to deliver a portable supply of CBM that would be marketable in a wide range of commercial heating applications. We are aware of a number of potential sites for our demonstrations. We will work closely with digester suppliers (two supported under the same call as us, and who are also going through the feasibility stage) and others. The possible sites that are potentially available for our initial testing and demonstration work are as follows: 1 Kemble Farm AD plant, Dairy farm near Gloucester (set up by Marches Biogas) 2 Reaseheath College AD Plant, Nantwich Cheshire CW5 6DF. 3 Farm AD plant, near Sandbach (built by Biotech Services Ltd) 4 Farm AD plant in Cumbria (to be installed using Biotech Services’ self-assembly plant by

a farmer). 5 AD Development Centre at Wilton (part of CPI) Almost all of these installations will have biogas production higher than the size that we wish to demonstrate. As such we anticipate there will only be a small disturbance to the sites’ normal operation. We are proposing a realistic timetable (15 months) for the execution of Phase 2, with logical progress milestones that will enable WRAP to verify that the project remains on programme for successful completion. The project personnel that we would deploy to Phase 2 are fully proficient in the areas of expertise needed to deliver the project. The report clearly sets out each stage of the demonstration project, from WRAP’s Instruction to Proceed to the submission of our Final Project Report, identifying every aspect that needs to be considered to ensure a successful project. All suppliers of materials and equipment have been identified, and where critical, discussions held and budget quotations obtained. Detailed design, fabrication, assembly and Works Testing will be undertaken in the premises of one of our core team, thus assuring full control of quality and timely delivery of the demonstration plant. Though for perceived budget limitations, one of the features of the DGC (regeneration of reagent) is not included in the proposed plant, monitoring of the plant operation will provide


sufficient data on which to develop firm estimates of capex and opex for a plant that incorporates this feature.

APPENDICES

Appendix 1: Biogas Scrubbing based on

Membrane Technology

This evaluation deals with the feasibility of using pleated flat sheet membrane gas-liquid contactors to enhance anaerobic digester biogas upgrading. The work described below was undertaken by Doug Harris of Pall Europe Ltd, a project partner.

Objective

To enhance the methane content of biogas from small farm scale anaerobic digesters to the point at which the owner/operator of the farm can sell the gas as compressed biomethane (CBM, similar to compressed natural gas, CNG), or use it as fuel in unmodified equipment. To do so requires the removal of up to 40% v/v carbon dioxide and up to 200 ppm hydrogen sulphide, through the use of an economically viable ‘black box’ treatment system. This report evaluates the feasibility of achieving the above by improving on conventional gas scrubbing technologies through the use of a pleated flat sheet hydrophobic membrane contactor. Typical process conditions

Biogas flow rate 9.0 Nm3/h CH4 content 60-70% v/v CO2 content 30-40% v/v H2S concentration, incoming assumed 0.02%

Gas pressure in incoming line 0.2 bar g Temperature ~30°C

Outline description of proposed equipment

The core technology proposed is a micro-porous hydrophobic membrane presented as a pleated sheet in cylindrical cartridge format. Note that this technology has not been proven in an application similar to this, but has been demonstrated in ozonation of water, and humidification of air. The gas to be treated would be passed through the core of the cartridge, while a suitable absorbent solution flows around the outside; to present the optimum contact area, a vessel holding multiple cartridges is envisaged (see Figure 1 below).


Differential pressure would be maintained between the gas and liquid phases such that the micro-porous structure of the membrane is essentially filled with gas, but the pressure would not be so high as to overcome the surface tension of the liquid (see Figure 2). Thus, gas will only transit across the gas-liquid interface by diffusion and bubble formation is avoided. This format is expected to present a high contact area in a compact footprint, allowing the use of smaller more efficient equipment than conventional contactor towers. As with a conventional contactor, the absorbent solution must show a high affinity for the CO2, and a low affinity for the CH4. The absorbent must also be readily regenerated as a ‘single use and dispose’ approach would create a large volume of waste solution making it uneconomical, impractical for the owner/operator and environmentally unacceptable. Thus, in addition to the scrubber membrane assembly, a second assembly will be required to strip the absorbed CO2 from a recirculating absorbent solution, either by applying vacuum to the gas side of the membrane, or aided by the flow of a sweep gas. It is likely that the absorbent solution will have to be heated to ~60-65°C to ensure efficient desorption occurs. Figure 3 shows a proposed process flow scheme.

Figure 14: Proposed layout of contactor vessel


Figure 15: Micro-porous membrane showing pores filled with gas

Figure 16: Proposed gas conditioning flow scheme

Operation

(i) Absorbent solution, most likely a secondary or tertiary amine such as methyl-

diethanolamine (MDEA) at up to 50% w/w concentration, is pumped into the liquid side of the absorption contactor from the amine buffer tank. Suggested flow rate not to exceed 15 m3/hr, at not more than 2 bar g.

(ii) In the contactor, CO2 is absorbed into the solution. The CO2 rich gas enters from the top of the vessel, while lean absorbent enters from the bottom of the vessel. Biogas


with CO2 content not higher than 4% v/v, exits the contactor and can then be further purified if required, and compressed.

(iii) CO2 rich absorbent solution is then pumped through a heat exchanger, recovering waste heat from the recovered absorbent, to a heater and then into the desorption contactor. Heat releases the CO2 from the solution and it is then removed by the application of a vacuum or a suitable sweep gas. The waste gas may be exhausted to atmosphere at a suitable location (a vent stack is suggested, but see notes on risks below) or recycled for use in a different application.

(iv) Recirculating flow rates, pressures and temperatures are monitored and equipment adjusted to maintain optimal operation. The absorbent solution pH is monitored after the desorption contactor, and operating conditions adjusted to maintain the desired chemistry.

(v) Pressure relief valves will be fitted to both contactor vessels, while the buffer tank will have level control fitted to ensure that the system does not run dry or flood.

Chemical reaction

For the calculations presented below, it is assumed that the absorbent is a 50% w/w solution of MDEA in water. While this reaction is relatively slow, the use of a substantial excess of MDEA (in both concentration and flow rate terms) ensures good capture of CO2 with minimal impact on the concentration of MDEA. MDEA is a commonly used absorbent with a good track record, particularly when CO2 is to be removed, where the relatively low regeneration heat and corrosivity of MDEA offer advantages over other common

amines17,18,19,20

.

Figure 17: MDEA chemical structure CH2.CH2.OH

H3C N CH2.CH2.OH MDEA reacts reversibly with CO2 in aqueous solution to form a bicarbonate salt:

CH3(C2H4OH)2N + H2O + CO2 CH3(C2H4OH)2NH+ + HCO3-

Mathematical model

A simplified mathematical model has been developed to estimate the contact area required. The following assumptions have made in developing this:

The reaction is such that 1 molecule of CO2 reacts with 1 molecule of MDEA Reactions occur at standard temperature & pressure

o Gases under these conditions exhibit ideal behaviour

17 G. Astarita, D.W. Savage, A. Bisio, Gas Treating with Chemical Solvents, Wiley, New York, 1983.

18 A.L. Kohl, F.C. Riesenfeld, Gas Purification, 4th ed., Gulf Publishing, Houston, TX, 1985.

19 D. Barth, C. Tondre, J.J. Delpuech, Kinetics and mechanisms of the reactions of carbon dioxide with alkanolamines: a discussion concerning the cases of MDEA and DEA, Chem. Eng. Sci. 39 (12) (1984) 1753–1757.

20 W.C. Yu, G. Astarita, Kinetics of carbon dioxide absorption in solutions of methyldiethanolamine, Chem. Eng. Sci. 40 (8) (1985) 1585–1590.


o One mole of gas occupies 22.4 L

Reaction occurs only in a 1mm deep boundary layer on the liquid side of the

membrane21

Diffusion of unreacted CO2 from the bulk gas to the gas-liquid interface is effectively instantaneous

The volume and concentration of amine is such that [MDEA] can be considered constant, so depletion does not have to be accounted for

Diffusion of the bicarbonate salt away from the boundary layer is near instantaneous No CH4 dissolves into the absorbent solution The process vessel can be divided into slices perpendicular to the gas flow

o The process vessel has a number of identical membrane cartridges in it, and gas/liquid flow is identical through all of them

o Each slice represents the volume of gas that will travel down the cartridge in 1s

o During that time, only the gas in the boundary layer reacts

o Reaction equilibrates such that [CO2](l) = 0.78[CO2](g)21,22

o The cartridge comprises a 76.2 mm outside diameter cylinder, the pleated media is formed into 10mm deep pleats, and thus the inner volume is a cylinder 56.2 mm in diameter

o The gas-liquid boundary layer in which the reaction occurs occupies the 10mm annular space of the pleated membrane, and that 50% of that volume is occupied by the membrane itself

o Thus the volume of gas that can react with the MDEA is 50% of that annular volume

The initial concentration of CO2 is known o 40% v/v = 40 mol % (ideal gas) o 9 m3 = 401.8 moles (i.e. 9 m3 / 0.0224 m3) o Of which 161 moles = CO2 o Thus, [CO2] = 161/9 = 17.9 mol.m-3

Using the volume of the annular space, the total number of moles of CO2 present, and the number reacting with MDEA, can be determined in the first slice of the model

By removing the reacted moles of CO2 from the total, and adjusting the volume to account for the removed CO2, a new concentration of CO2 ([CO2]) can be determined and taken forward to the next slice

The process is repeated until the [CO2] passed forward reaches the desired level The number of iterations required to reach this [CO2] level then determines how

much contact area is required

Calculations

The following diagrams may assist in visualising the assumptions and calculations.

21 R. Wang, D.F. Li, D.T. Liang, Modeling of CO2 capture by three typical amine solutions in hollow fiber membrane contactors, Chemical Engineering and Processing 43 (2004) 849–856.

22 G.F. Versteeg, W.P.M. van Swaaij, Solubility and diffusivity of acid gases (CO2, N2O) in aqueous alkanolamine solutions, J. Chem. Eng. Data 33 (1988) 29–34.


Figure 18: Cylindrical pleated membrane

Figure 19: Illustration of modeled slices through a membrane contactor

Annular volume of the contactor cartridge, VAnn

Where R = outside diameter of cartridge, 0.0381 m r = inside diameter of pleated membrane, 0.0281 m L = length of slice, m

LrRVAnn

22


Length of slice, L, assumed to be 1s of gas travel down the cartridge

Where Qg = Gas flow, 0.0025 m3/s

Moles of CO2 reacting, Mr

Mr = VAnn x [CO2](g) x 0.78 Where [CO2](g) = Concentration of CO2 in gas phase 0.78 = Equilibrium coefficient after CO2 transfer to liquid phase New volume after reaction, Vnew

Where [CO2]i = Concentration of CO2 in gas phase at start of calculation, mol.m-3

Vi = Initial volume of gas in slice of model, m3, taking account of the number of cartridges, and assuming 50% of annular area is gas

0.0224 = molar volume of an ideal gas at STP Note: At t=0, Vi = (0.5Π(R2-r2) + Πr2) x number of cylinders x L With the following initial inputs:

[CO2] = 17.9 mol.m-3 Qg = 9 m3/hr Number of cylinders = 6 Target [CO2] = 1.8 mol.m-3

We get:

Gas velocity = 0.09 m/s Slice length, L, = 0.09 m

Initial gas volume, Vi = 0.0019 m3 The following arises [CO2] decay curve (Figure 7).

2r

QL

g

ri

riinew

MV

MVCOV

0224.0

.2


Figure 20: Reduction in [CO2] by modelling slice

This indicates that some 10 slices, or ~1.0 m length of media, would be required in the absorption contactor for a 6 cartridge installation. For the sake of simplicity, it is assumed that a similar sized desorption contactor will be required. As an initial estimate, such vessels will be 12” nominal bore (300 mm ID) by 1500 mm high.

Mass balance

Incoming biogas, 9 Sm3/hr = 401.8 mol/hr [CH4] = 60% v/v, or 241.1 mol/hr (3.9 kg/hr, 35.5% w/w) [CO2] = 40% v/v, or 160.7 mol/hr (7.1 kg/hr, 64.5% w/w) Giving an overall gas flow of 11 kg/hr Outgoing treated biogas [CH4] = 3.9 kg/hr, 241.1 mol/hr (98.2% v/v) [CO2] = 0.2 kg/hr, 4.4 mol/hr (1.8% v/v) Total flow 4.1 kg/hr, ~5.5 Sm3/hr Waste gas 6.9 kg/hr CO2, 156.3 mol/hr, ~3.5 Sm3/hr Recirculating amine


While only a relatively small amount of MDEA is needed to react with the CO2, a substantially higher volumetric flow is necessary to maintain the excess noted and so ensure optimal transfer efficiency. A recirculating flow rate of 10-15 m3/hr is suggested, at a concentration of 50% w/w, 4.4 kmol.m-3. A holding tank of 1-2 m3 capacity should be provided to ensure a buffer level of MDEA is available, and the overall MDEA inventory is likely to be in the region of 2-3 m3. Such a tank should include the capability to bleed off and replace some/all of the amine at appropriate service intervals.

Other operational parameters

As indicated in Figure 3, additional equipment will be needed, all of which bring additional operating costs, primarily in terms of energy consumed. As an indicative approximation, the

energy input required could approach 10 kWh23

.

Life cycle of technology

i. Life span of equipment As a broad assumption only, 1-3 years operating life of the membranes seems not unreasonable, although the gas may need to be filtered and the system protected from pressure and temperature shocks in operation. The amine inventory may last 3-5 years but if subjected to significant thermal work may need replacing more frequently. A life time of at least 5 years for the major electrical and mechanical components seems reasonable, if a good preventative maintenance program is followed.

ii. Commissioning / decommissioning

Assuming the concept is properly developed, on-site commissioning is likely to take less than a week if performed by a competent engineer, and is likely to consist primarily of tuning operating parameters to achieve optimum performance. Economic / Cost Benefit Analysis Provisional description of proposed membrane contactor absorption/desorption unit and associated equipment. All pressure vessels to PD5500/PED, all equipment to comply with ATEX zone 2 requirements and other applicable regulations to ensure CE marking.

EQUIPMENT Description

Membrane contactor x 2

316L stainless steel vessels Design pressure 10 bar g Maximum operating pressure 4 bar g 300 mm ID x 1,500 mm high 6 x 1m long cartridges per vessel

Buffer tank for amine solution x 1

316L stainless steel vessels Design pressure 10 bar g Maximum operating pressure 4 bar g Operating volume ~1 m3, estimate 1,200 mm ID x 1,000 mm high

23 Patterson, T., et al., An evaluation of the policy and techno-economic factors affecting the potential for

biogas upgrading for transport fuel use in the UK. Energy Policy (2011), doi:10.1016/j.enpol.2011.01.017.


Pump x 2 Stainless steel, centrifugal type, capable of up to 15 m3/hr at 3 bar g (~3 kW)

Compressor x 2 Stainless steel, oil-free, capable of 10 sm3/hr at 3 bar g (~2 kW)

Absorbent liquid 3 m3 MDEA solution at 50% w/w

Temperature transmitter x 2 pH probe x 1

Pressure transmitter x 6 Flow transmitter x 2 Level transmitter x 1

Heat exchanger Stainless steel, 15 m3/hr capacity

Electric heater Stainless steel, 15 m3/hr capacity, heat input 10 kW

Air (fan) cooler Stainless steel, 15 m3/hr liquid capacity, 3 kW Pipe work, valves, fittings in stainless steel

Junction box & wiring, including for instruments & controls Pressure relief valves x 3

Data logger/ programmable logic controller

Supporting steel structure

Estimated cost of equipment

Membrane contactor vessels 2 Each £24,000.00

Membrane cartridges 12 Each £500.00

Amine buffer tank 1 £60,000.00

Pump 2 Each £6,500.00

Compressors 2 Each £5,000.00

Instrumentation, pipework & fittings £35,000.00

Temperature transmitters, pH probe; Pressure transmitters, flow meters; Pressure Relief valves

Heat exchanger 1 £10,000.00

Heater 1 £5,000.00

Fan cooler 1 £5,000.00

Electrical £24,000.00

Junction box, control unit, wiring data logger & PLC

Support structure £8,500.00

Installation/commissioning £10,000.00

Contingency £5,000.00

TOTAL £239,500.00

Risk Analysis A number of unproven assumptions have been made in reaching this model, some of which are summarised below, along with other considerations.

Flat sheet membranes are unproven in this application, and CO2 transfer in either direction may be significantly slower or less efficient than predicted. The mass


diffusion rate indicated by Versteeg and van Swaaij24 would become the limiting factor in at least the early stages of the absorptive process, and by inference in the desorptive process also, resulting in significantly larger membrane installations.

H2S must be removed, either from the feed gas, or from the waste gas, as venting to atmosphere cannot be considered acceptable, both from an odour (likelihood of complaints from neighbours) and health, safety and environmental perspective.

The quantity of CH4 transferred from the feed gas to the absorbent, and so to waste,

is unknown, but may be as high as 1.5%25

. Again, HSE considerations may make

the uncontrolled venting of such a gas mix undesirable, although farms running anaerobic digesters without any form of biogas capture or treatment are undoubtedly venting significantly higher quantities of CH4 to atmosphere.

Regrettably, Pall Corporation are withdrawing from this market as the economics are not considered to balance at this scale. Indeed, even at the smaller scale and in high value added applications, the flat sheet contactor product has not proven viable and has been withdrawn. Accordingly, Pall are unable to support further development, particularly in such a cost-driven application as this appears to be.

24 G.F. Versteeg, W.P.M. van Swaaij, Solubility and diffusivity of acid gases (CO2, N2O) in aqueous alkanolamine solutions, J. Chem. Eng. Data 33 (1988) 29–34

25 Benjaminsson, J., 2006. NYA Renings Och Uppgraderingstekniker for Biogas, Swedish Gas Centre, Report 163. Available from http://www.sgc.se/rapporter/resources/SGC163.pdf.



DGC Design

Provisional Details of Biogas Upgrading Process

The Basis and Objective

Removal of CO2/H2S from Biogas Biogas flowrate 9.0 Nm3/h CH4 content 60 - 70% CO2 content 30-40% H2S concentration, incoming assumed 0.02% Gas Pressure in incoming line 0.2 kg/cm2

DGC Reactor Unit: Proposed Flowsheet and Instrumentation

STAGE I – CO2/H2S ABSORPTION

NOTE


(1) An absorbent solution – specially formulated and very effective for CO2 and H2S removal - will be used.

(2) The unit is operated in a liquid recycle mode. The absorbent solution added to the feed/receiver vessel is pumped through a liquid flowmeter into the DGC reactor (There are two feed vessels operating alternately). The operating pressure of the DGC reactor can be varied as required and is controlled by a regulating valve at the outlet of the reactor column. The liquid pressure at the point of entry into the specially designed inlet is between 2.5 – 4.0 barg. There is a pressure drop created which allows the biogas to be fed into the DGC at atmospheric pressure. The inlet biogas is fed into the DGC reactor through the specially designed inlet connected to the top of the DGC reactor.

The liquid (with the absorbed/reacted CO2 and H2S) flows back into the feed/receiver vessel through the outlet of the DGC reactor and this recycle process is continued. When the liquid is saturated with all absorbent having reacted – which can be monitored by the pH - the other feed vessel is put into operation. Unabsorbed gas (which is methane) disengages in the feed/receiver vessel to be vented out through a ‘knockout drum’ (to remove the carryover liquid) as shown and then passes through to STAGE II – for purification and compression. [STAGE II – for final purification as an additional safety measure for H2S removal]

Temperature control is undertaken as required, by using cooling/heating fluid through the jacket in the feed/receiver vessels. [SEE DESCRIPTION BELOW]

(3) The rate of absorption will vary depending on changes in absorbent concentration, liquid flowrate, temperature and also pressure.

Description of the flow and operating parameters and process control, Stage I

1. Absorbent solution (mixture of NaOH and sea salts which mainly contain NaHCO3 and Na2CO3 - see reaction details below) is fed by a pump into the DGC reactor from the feed vessel through a specially designed inlet at the top.

2. Temperature of the solution is controlled by a jacket and temperature controller

looped with heating/cooling water circulation. (During absorption stage cooling is effected and during regeneration of absorbent heating)

3. This absorbent solution is circulated through the DGC reactor at the required

operating pressure and liquid flowrate.

4. Required rate of liquid circulation is controlled by a flow meter and flow control valve.

5. Pressures are monitored at three points by pressure indicators – (i) before inlet into

the DGC; (ii) reactor top after inlet into the DGC ; (iii) reactor bottom at outlet of DGC. Pressures at all these three points are logged.

6. The operating pressure of the DGC reactor is controlled by a flow control valve in the

outlet line of the DGC reactor which is looped with the pH control.

7. The reaction pH is monitored as shown in the layout above.


8. The Biogas, at atmospheric pressure, is fed into the specially designed inlet of the DGC through a non return valve and a gas flow controller

9. The outlet reacted liquid with unabsorbed/unreacted methane gas passes into the

feed/receiver vessel No 1 and No 2 – as required - which is at atmospheric temperature and pressure, where the gas (methane) disengages.

10. The outlet gas from the feed/receiver vessels (through vent) is continuously

monitored for CO2/H2S and methane. The rate of absorbent solution reaction in the DGC can be increased or decreased by controlling the pressure in the DGC reactor depending upon any CO2 or H2S escaping through vent. This is added as a safety measure to ensure complete reaction of the CO2 and H2S.

11. The outlet gas is passed through a hydrocyclone separator or knockout vessel to

recover any liquid carry-over with the disengaging gas.

12. As a safety measure pressure relief valves are installed at the bottom of the DGC reactor and the top of the gas disengagement vessel. These will be set at the required levels of operation and controlled by control system.

13. On saturation of the absorbent liquid in one feed/receiver vessel the process is

switched over to the other feed/receiver vessel which has unreacted/regenerated absorbent liquid.

14. Heating is then applied to the saturated feed/receiver vessel and absorbent liquid is

regenerated with gas (CO2) escaping through the outlet – GO - as shown in layout above.

15. The heat generated during the absorption stage is used to heat the saturated

absorbent liquid during the regeneration stage

16. This process of biogas upgrading by removal of CO2 and H2S is therefore operated on a continuous basis.

It should be noted that if a compressor can be supplied to compress biogas, before its input into the DGC, say at 5 barg, then we can design a smaller DGC reactor. Everything else would practically remain the same. This application will be utilised if the demonstration site can support it.

Graph: SIMULATED BIOGAS [60% CH4-38% CO2-2% H2S]; UPGRADING USING THE

DGC REACTOR.


PROPOSED PROVISIONAL DESIGN ESTIMATE OF SCALED UP DGC REACTOR UNIT

Diameter of DGC Reactor: 20.0 cm Height of DGC Reactor: 3.0 m

PRELIMINARY ESTIMATION OF GAS ABSORPTION SECTION OF UNIT

DGC reactor Feed vessel Support structure Pump Piping Instrumentation Control Condensate trap/removal system – knockout drum

PROVISIONAL DETAILS OF DGC ABSORPTION UNIT & ASSOCIATED EQUIPMENT

Item Equipment Details Note Ref

I DGC Reactor SS design pressure 10 barg maximum operating pressure 4.0 barg

A

II Feed/receiver vessel with cooling coil or jacketed.

SS maximum operating pressure 2.0 barg

B

III Pump SS; upto 40.0 gal/min at 6 Barg (3.0 kW)

IV Absorbent liquid See notes below C

V Temperature indicator/ thermocouple, pH probe

2 nos 1 nos

D

VI Pressure gauges, 2 nos D


Pressure indicator recorder, Pressure transducer

2 nos 2 nos

VII SS pipework, valves, fittings, gas flow controller & liquid flowmeter etc.

See notes below E

VIII Safety, power control box, pressure relief, bursting disc

As required; See notes below F

IX Data logger/ control unit See notes below G

X Support structure As required

XI Knockout vessel See notes below H

NOTES:

A. DGC reactor

B. Feed/receiver vessels: Type- horizontal cylindrical

Column height: 2.0 m; radius: 30 cm [Total volume: approximately 300 litres] With top and bottom flanges Material of construction SS – design code ASME - PD5500 [BC] Connections Top flange: 1 No inlet - 50 NB c/w Feed pipe into vessel 2 Nos outlet - 50 NB c/w gas outlet pressure relief valve – 25 NB Pressure transmitter – 25 NB Thermocouple – 25 NB

C. Absorbent liquid: Total volume: 300-350 litres per batch; specific gravity 1.0–1.2 (mixture of sea salts and alkali or amine solution)

D. All temperature indicators and pressure transducers/indicators will be connected to a data logger and control box

E. Piping: All liquid piping as per piping specifications given above

Gas inlet - 50 NB - connected to specially designed gas inlet of DGC

Bottom flange: Liquid return line: 2 nos 50 NB Drain line - 50 NB Outlet line – 25 NB Level switch - 25 NB.


All thermocouples / pressure gauges / valves etc. to be connected to flanges and piping with standard fittings or flanges. The gas inlet flow into the DGC and also the outlet clarified gas flow from the feed/receiver vessel will be measured by installing a suitable [ATEX Zone I compliant] digital gas mass flow meter and will be connected to the data logger.

F. The maximum operating pressure in the DGC will be 2.5-3.0 barg. An adjustable pressure relief valve will be situated before the regulating valve, just after the outlet of the column and will be set to discharge and open at 3.5 barg to relieve any over-pressure. A pressure indicator controller/relief unit will be connected to the DGC and feed vessel for control of pressure. The pump will be connected with a bypass line fitted with a bursting disc, set to discharge at 6.5 barg pressure. All electric connections will be connected to a power control box as per guidelines of IP55.

G. The computer will be connected to the data logger with required software for control.

H. The outlet clarified methane passing out from the feed/receiver vessel is passed through a knockout vessel in order to remove the water content in the gas before it is fed into the gas purification – STAGE II. [Dimensions be given in detailed design ]

Removal of CO2 and H2S [A] Salt Solution/Alkali A specially formulated salt solution (along with NaOH for CO2 absorption and reaction) will be used for the chemical absorption of H2S. Use of this special solution will offer extra advantages, such as the high efficiency of H2S removal, the selective removal of H2S and the low consumption of the chemicals and can be regenerated. For H2S removal we would use a “Salt Solution” where the two main components reacting with H2S are Na2CO3 and NaHCO3. For NaOH, the stoichiometric reaction is 2 NaOH + CO2 = Na2CO3 + H2O 2 NaOH + H2S = Na2S + 2H2O For Na2CO3 the stoichiometric reaction is Na2CO3 + H2S = Na2S + CO2 + H2O Likewise for NaHCO3 we have: 2NaHCO3 + H2S = Na2S + 2CO2 + 2H2O Alkali- NaOH present will also absorb/react with the CO2 being produced so that there is no additional CO2 emission with the disengaging gas. A concentration of salts and alkali – IN EXCESS CONCENTRATION would be used – which would absorb/react with H2S and CO2 and once all the NaOH, Na2CO3, NaHCO3 has reacted it would need to be removed and a fresh supply of absorbent solution would need to be added or regenerated. This can be monitored by a fall/drop in the pH and also monitored by the gas analyser at the outlet gas stream. When the reaction is ending in the first feed vessel then there will be a change-over to the 2nd feed vessel. This will keep the process continuous.


Two options exist:

Fresh supply of the absorbent solution can be added to the feed vessel and kept ready for the next changeover.

The absorbed/reacted solution can also be regenerated by heating (for CO2) and also aeration/oxidation to recover sulphur from the Na2S formed.

The reacted solution can be regenerated in a separate system or in the same unit itself. Heating of the liquid in the feed vessel can be done by switch over to heating the fluid through the Jackets. [B] Amine Solution As an alternative, amine solution can be used instead of the mixture of salts/alkali as given in Section A. The amine process follows the following reversible reaction:

Cold C2H4OHNH2 + CO2 + H2O <---------------------> C2H4OHNH3

+ + HCO3-

Hot The amines (MEA and DEA) are utilized in the aqueous phase, typically containing 25-30 % amine (w/w). The solution is regenerated by heating, though additional top-up would be required as degradation through oxidation of the amine occurs. NOTE: ALL DESIGN AND DIMENSIONS WILL BE CHECKED AND VALIDATED DURING DETAILED DESIGN. OVERALL MASS BALANCE DESIGN BASIS Average composition/characteristics of BIOGAS at inlet considered as: CH4 64 % by vol (39.90 % by weight) CO2 34 % by vol (58.29 % by weight) N2 1 % by vol (1.09 % by weight) H2S 0.02 % by vol (0.026 % by weight) Water vapour 0.98 % by vol (0.687 % by weight) Temperature 30-45 °C GAS PRESSURE 0.2 kg/cm2 BIOGAS FLOW RATE 9 m3/h Biogas Flowrate at Inlet of DGC reactor 9.0 m3/h = 10.3 kg/h Out of which CH4 4.11 kg/h CO2 6.01 kg/h N2 0.11 kg/h H2S 0.003 kg/h Water Vapour 0.07 kg/h


Final Balance: Biogas at inlet 10.3 Kg/h Feed alkali (NaOH)at inlet 12.0 Kg/h CO2, H2S and moisture free - biogas at outlet 4.11 Kg/h Alkali with (CO2 + H2S + moisture) at outlet 18.2 Kg/h

PROVISIONAL COSTS OF TOTAL UNIT

Principal components Full

demo Key

demo

DGC reactor with specialised entry unit £32,000 £25,600

Feed/receiver vessel with cooling coil or jacketed. £12,500 £6,000

Pumps £6,500 £5,400

Knockout vessel £10,000 £8,000

Temperature indicator/ thermocouple, pH probe

£35,000 £25,000 Gas analyser; pressure gauges; pressure indicator recorder,

Pressure transducer, pressure relief, bursting disc

SS pipework, valves, fittings, gas flow controller, flowmeters etc.

Electrical

£24,000 £18,000 Power control box, control unit

Data logger/computer/software

Support structure £8,500 £6,000

Metal oxide units £1,500

Silica gel units £3,000

Installation/commissioning £20,000 £16,000

Miscellaneous £5,000 £2,000

Total £158,000 £112,000

Above are all estimated costs (+/- 15 %)


Consumables Absorbent liquid salts Alkali- NaOH Metal oxide Silica gel HAZOP A HAZOP will need to be done for the total system and process Supplementary information – The DGC Reactor The DGC reactor is a mass transfer efficient gas-liquid contacting/absorption device [column], where the gas and liquid stream are introduced co-currently through a specially designed entry section at the top of a fully flooded column. The high velocity liquid jet inlet stream, generating intense shear and energy, produces a vigorously agitated gas-liquid dispersion in the upper section of the column. This shear causes the break-up of any gas pocket at the inlet and allows the formation at the top of the column, of a vigorously agitated gas-liquid dispersion with an enormously high interfacial area in a small operating volume. Many industries require gas/liquid contacting in a wide range of processes and some typical examples where the DGC can be beneficial, are: Absorption; Stripping; Air Flotation; Ozone Treatment; Micro-bubble Generation; Oxidation; Catalytic Oxidation; Hydrogenation; Heterogeneous Reactions; Effluent Treatment; Carbonation; Fermentation; Oxygenation; Mineral Separation etc. The high degree of intense shear and turbulence caused by the incoming liquid jet, induces intense mixing and efficient mass transfer as well as constant surface renewal. The downflow liquid velocity in the column is maintained at a value below the rise velocity of the gas bubbles so that there is no tendency for the bubbles to be carried downwards. Hence there is no net movement of the gas phase whilst the liquid phase flows downwards through the inter-bubble spaces. The gas-liquid bubble dispersion slowly expands down the fully flooded column and the level of dispersion (and thereby volume of the gas-liquid dispersion) can be controlled by control of the operating conditions (liquid and gas flow rates). In the lower section of the column as the dispersion proceeds downwards, there is a degree of bubble coalescence since it is no longer within the region of direct inlet steam impingement. This coalescence produces larger bubbles, which rise up the column where they are broken up by the shear of the high velocity inlet liquid jet. Typical bubble dispersion achieved in the DGC, which contains nearly uniformed sized bubbles and results in a distinct gas-liquid interface. The gas/liquid mixture can be maintained at a desired level within the reactor to ensure 100% gas utilisation. The intense turbulence, good mixing and high gas hold-up within the bubble dispersion, accounts for the efficient mass transfer performance of the DGC. The specific shape, dimensions and configuration of the DGC reactor depend on the application and operating conditions required. A DGC could be designed and operated to take into account all variations of operating conditions and applications. The DGC reactor


system also includes a pump and feed/receiver vessel connected together with necessary piping. Suitable control systems (for heating, cooling, dispersion level, pressure, liquid flowrate control, gas flowrate, data logging etc.) are included as required. The inherently simple design and operation of the DGC offers specific advantages over other conventional reactors, such as:

100% gas utilisation and greater than 95% approach to equilibrium solubility levels in very short contact times.

Lower power consumption.

Increased system energy efficiency

Smaller operating volume

No foaming possible as no free gas-liquid interface at the inlet.

High and accurate control of Interfacial areas (1000 – 6000 m2/m3 depending on bubble sizes) – allows for improved gas absorption rates and reaction specificity.

No internal moving parts – e.g. stirrer etc., therefore reduced capital as well as operating costs.

Higher gas hold-ups (40-50%)

Tolerance to particulates – system allows for high solid content.

Easy scale-up without loss in efficiency

Easy automation and control with safe operating conditions.

Low engineering and fabrication costs

Simple, compact with flexibility of design.

INDUSTRIAL APPLICATIONS The DGC reactor, with its advantages as specified above is a versatile tool, which can be used for various types of applications. It can be operated in a batch, semi-continuous or continuous mode. The main areas of application are:

1. GAS ABSORPTION: oxygen or carbon dioxide in water/seawater; selective removal of gases like in biogas upgrading or cleaning up of flue gases.

2. SCRUBBING/STRIPPING of gases (ammonia from farm waste effluent)

3. CHEMICAL REACTIONS: (gas/liquid/solid reactions): hydrogenation (of vegetable oils or fine chemicals production); oxidation processes - like oxidation of p-cresol; by use of slurry, packed bed or monolith catalysis.

4. EFFLUENT TREATMENT: using air, oxygen or ozone, UV (Photocatalytic reactor)

reduction of COD levels, degradation of pollutant or treating 'difficult' liquid wastes GAS ABSORPTION

Gas-liquid contacting devices are used widely in the chemical industry for absorbing gases into liquids and solvents. These devices range from stirred vessels to packed beds and bubble columns and are employed for a variety of different industrial applications.


Most applications employ an upflow mode of gas flow with relatively low gas hold-ups (< 25%) along with subsequent gas disengagement with recycling, coalescence and back-mixing problems. Free gas liquid interfaces with gas pockets are formed in these reactors causing safety problems. Furthermore downflow bubble columns usually operate with jet entrainment of gas and gas bubbles therefore require subsequent disengagement and uneconomic utilisation of gas whilst the interfacial area is not optimised. The use of the DGC reactor eliminates these problems.

The DGC offers significant advantages over more conventional gas-liquid contacting devices and is able to achieve saturation in very short reaction times. Some of the advantages of the DGC when compared with other contacting devices are highlighted below:

DGC compared with a stirred tank for an oxygenation process

Process Conditions Operating temperature 15°C

Liquid flowrate 10 m3/hr

Initial dissolved O2 conc. 10 ppm

Stirred Tank DGC

Operating pressure (Bar a) 5 4

Contact time (seconds) 300 10

Approach to equilibrium (%) 62.5 96

Gas utilisation (%) 90 100

Outlet O2 conc. (ppm) 150 150

Volume of adsorption equipment (m3) 1.5 0.05

Power absorbed (kW) 4.8 1.2

DGC compared with a spray column for a carbonylation process

Process Conditions Operating Pressure 5 Bar a Liquid Flowrate 10 m3/hr Initial Dissolved CO2 Conc. 10 ppm Spray Column DGC Operating temperature (°C) 5 15 Holdup time (seconds) 80 24 Approach to equilibrium (%) 70 97 Gas utilisation (%) 100 100 Outlet CO2 conc. (ppm) 9500 9500 Saturation CO2 conc. (ppm) 13500 9640

Volume of adsorption equipment (m3) 0.2 0.06 Absorption energy ratio (kg/Wh) 0.5 1.4



conventional absorber

We do not have permission to use this quote from the supplier. As such only the high level values are used in our analyses in the main report.


Figure: Preliminary process and instrumentation diagram


Appendix 4: Compression and Bottling

System Quote

From: Clive Noakes, SMP Ltd Received: 26 March 2012 To: 'Dr Prabodh B Mistry' We have considered your project and we are pleased to offer you the following budget proposal. 1 pcs Portable Biogas compression and storage unit, all mounted in a towable box van trailer. Trailer gross weight 3500 kgs, Unladen weight 935 kgs, with roller shutter door. Trailer length 4.7 mtr x width 2.3 mtrs, twin axle. Compressor MCH10/CNG connected via flexible hose to cylinder bank consisting of 6 x 50Ltr cylinders with a capacity at 250 bar of 75m3. Cylinder bank will be manifolded and terminated with gauges and regulator, with outlet connections to be agreed. Electric starter panel to be mounted on frame and connected via flex cable to allow remote siting and connection to mains supply. Budget Price circa £ 16,500.00 Should you find our offer acceptable, we will need to draw up the trailer in detail and confirm supply. Look forward to hearing from you. Regards, Clive Noakes, Sales & Marketing Executive SUBMARINE MANUFACTURING & PRODUCTS LTD. Worldwide Suppliers of Diving, Hyperbaric and Subsea Equipment Blackpool Road • Newton • Preston • Lancashire PR4 3RE Telephone: +44-1772 687775 • Fax: +44-1772 687774 Website www.smp-ltd.co.uk • E-mail [email protected] Further breakdown of the above quote was received, as follows: Compressor = £5000.00 (MCH10) or £3000 (MCH05) 6 bottle storage bank = £3000.00 Trailer = £6000.00 Integration = £1500.00 pipework, valves, steelwork Other = £1000.00 labour Based on the above, EHV have derived quotes for use in the project as follows:

1. Stationery system based on MCH05 is available at £8,500 2. Trailer mounted system based on MCH10 is available at £16,500.

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