economic modelling of anaerobic digestion/ biogas ...

International Biogas and Bioenergy Centre of Competence

ECONOMIC MODELLING OF ANAEROBIC DIGESTION/ BIOGAS INSTALLATIONS IN A RANGE OF RURAL SCENARIOS IN CORNWALL

Prepared by

INTERNATIONAL BIOGAS AND BIOENERGY CENTRE OF COMPETENCE (IBBK) Michael Köttner, Dr. Sigrid Kusch, Achim Kaiser, Dominik Dörrie

In cooperation with

DAVID COLLINS RENEWABLE ENERGY ASSOCIATION, LONDON (REA)

For the

CORNWALL AGRI-FOOD COUNCIL (CAC) CORNWALL ENTERPRISE

Final Report 21 August 2008


Cornwall Agri-food Council introduction and context for the study; Looking at; the ‘Economic Modelling of Anaerobic Digestion / Biogas Installations in a range of rural scenarios in Cornwall’

The Cornwall Agri-food Council Development Team (CACDT) has, for some time, been aware of the interest that has been building within the agricultural and food sector about the opportunities provided by renewable energy in all its forms as either a source of additional income or as a method of managing waste/resources. Through conferences, study tours and other activity the team has worked with farmers, technology providers, energy users and regulators to raise the awareness of different technologies and their appropriateness for use on farms in Cornwall and the Isles of Scilly. Through our work it became clear that there was great interest within the industry about Anaerobic Digestion (AD) on farms but due to the absence of real life demonstration projects it was difficult to prove the economic viability of this technology at farm scale in the United Kingdom. Therefore with support from Objective One EAGGF and DEFRA funds the CACDT agreed to commission research into the economic modelling of different AD options. In undertaking this study the CACDT worked in close collaboration with the South West Regional Development Agency, The Environment Agency, Cornwall Sustainable Energy Partnership and industry partners and thanks must go to all those that have given their time to be a member of the steering group for this study. To present the strongest financial case, both sides of the market need to be understood, with individual projects requiring thorough analysis under current market conditions and future scenarios. AD can be considered from two points of view: o o

Waste Treatment where AD is a technology that will deal with biomass such as animal slurry, wet wastes and food wastes that attract a gate fee; electricity and heat are saleable by-products. Energy production where AD is a technology that is used to produce renewable heat and electricity from biomass such as wet waste and energy crops. The National Waste Strategy strongly encourages the consideration of (AD) in the development of private and public sector waste infrastructure and services. As such there is considerable regional interest, especially from the agricultural sector, for utilising the technology to assist management of nutrients and soil condition; as well as in the provision of wet and ‘dry’ feedstocks for digestate.

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The aim of this study is to establish the feasibility and viability of installing (AD) technology in a range of rural scenarios in Cornwall and the Isles of Scilly with the combined benefits of reducing slurry effluent and other organic waste and the generation of energy for use on farm or for supply to the national grid. It is designed to provide the reader with a realistic picture of what types and volumes of waste streams are needed to make such installations viable. The results also provide a detailed analysis of each scenario so that readers of this study can make a decision on whether or not to pursue further investigation into the feasibility of an installation on their own premises. We hope that the results of the study will also provide suggestions for suitable intervention rates for government grants where needed and / or recommend barriers and opportunities for alternative incentives. With the current State Aid issues surrounding double State Aid support; meaning that individuals could only claim grant and one ROC or no grant and two ROCs; we hope that the study will detail the considerable adverse effect this may have on the uptake of technologies. Finally, when considering any renewable technology that is fuelled by energy crops or waste, we must be aware of the future markets and limitations on supply. If there were to be a swift uptake on technologies then this may cause the cost of wastes to inflate. Also where penalties are imposed on companies for waste, there is also a worry that waste streams will be reduced. The Cornwall Agri-food Council Development Team commissioned this study to give the Agricultural, Horticultural, Food and Land Based sectors in Cornwall and the Isles of Scilly a realistic picture of the viability of small on-farm and community plants. However, its findings are applicable to other areas of the South West region and to England as a whole and so we hope it will also benefit other areas as well. The scales that achieve viability in this study are some of the largest in the county and not by any means an average Cornish farm. We still believe that Anaerobic Digestion is a renewable technology that could provide great benefits; with the mitigation of contributions to CO2e, the increased availability of nutrients in the final digestate, odour control and the sale of the electricity and heat produced from the technology. We look forward to seeing installations, where viable, installed and studied for knowledge transfer and market uptake and we hope that this study will help interested parties to further their investment ideas. David Rodda / Nicky Garge Cornwall Agri-food Council Development Team

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Economic Modelling of AD in Cornwall – Contents

Contents

List of Tables ......................................................................................................................................................... 4 List of Figures........................................................................................................................................................ 6

1 Executive Summary ............................................................................................... 7 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8

Introduction ..................................................................................................................................................................... 7 AD Regulations................................................................................................................................................................ 7 Biogas Utilisation............................................................................................................................................................. 8 Grid Connection .............................................................................................................................................................. 8 Explanations to the Economic Modelling of this Study................................................................................................ 8 Individual Case Studies................................................................................................................................................... 9 Recommendations to Future Biogas Plant Operators ................................................................................................ 11 Conclusions .................................................................................................................................................................... 12

2 Introduction .......................................................................................................... 14 2.1 The Anaerobic Digestion Process and its General Environmental Benefits ............................................................. 14 2.2 Biogas in Europe and in the United Kingdom............................................................................................................. 14 2.2.1 2.2.2

AD in the European Union ............................................................................................................................................................14 The Biogas Market in the United Kingdom ..................................................................................................................................16

2.3 Scope of this Study ........................................................................................................................................................ 17

3 The UK Regulatory Regime for Biogas Plants .................................................. 19 3.1 3.2 3.3 3.4 3.5 3.6

Overview of Regulatory Approval Procedures for AD Plants ................................................................................... 19 ABP Regulatory Regime ............................................................................................................................................... 20 Environmental Permitting (EP) ................................................................................................................................... 21 Digestate Standard PAS 110 and Protocol .................................................................................................................. 23 NVZs and the Effect on Biogas Plant Planning........................................................................................................... 24 Digestion of Sewage Sludge (Biosolids) with other Feedstock.................................................................................... 25 3.6.1 3.6.2 3.6.3

The Sludge (Use in Agriculture) Regulations 1989 ......................................................................................................................25 Code of Practice for Agriculture Use of Sewage Sludge ..............................................................................................................26 The Safe Sludge Matrix (ADAS Matrix).......................................................................................................................................26

4 Biogas and Digestate Utilisation.......................................................................... 27 4.1 Electricity Generation ................................................................................................................................................... 27 4.1.1 4.1.2 4.1.3 4.1.4 4.1.5

4.2 4.3 4.4 4.5

Renewable Obligation Certificates (ROCs)...................................................................................................................................27 Double ROCs for Biogas ...............................................................................................................................................................28 Climate Change Levy Exemption Certificates (LECs) .................................................................................................................29 Embedded Benefits and Triads ......................................................................................................................................................29 Electricity Sales..............................................................................................................................................................................30

Combined Heat and Power........................................................................................................................................... 31 Heating with Biogas....................................................................................................................................................... 32 Biogas as a Road Fuel and Gas Injection into the Gas Grid ...................................................................................... 32 Utilisation of Digestates................................................................................................................................................. 36

5 Electrical Grid Connection in Cornwall ............................................................ 37 5.1 Regulatory Frameworks ............................................................................................................................................... 37

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5.2 General Procedure and Costs....................................................................................................................................... 37 5.3 Connecting with Western Power Distribution (WPD) ............................................................................................... 39 5.3.1 5.3.2 5.3.3 5.3.4 5.3.5

Company Profile ............................................................................................................................................................................39 The Connection Process to Western Power Distribution’s Network ............................................................................................39 Planning Permission and Other Consents......................................................................................................................................40 Connection Costs with WPD .........................................................................................................................................................41 Typical Connection Sizes and Connection Voltages.....................................................................................................................41

5.4 Documentation of Essential Reading for Prospective Generators............................................................................. 42

6 Explanations to the Economic Modelling of this Study.................................... 43 6.1 General Layout and Selection of AD Technology ....................................................................................................... 43 6.2 Assumptions for Calculations....................................................................................................................................... 44 6.2.1 6.2.2

Substrates, Biogas Yields, Digestate Nutrients .............................................................................................................................44 Costs and Income ...........................................................................................................................................................................45

6.3 Sensitivity Analysis and Grant Requirements ............................................................................................................ 47

7 Individual Case Studies........................................................................................ 48 7.1 Site 1 (75 kW): A 200 cow dairy farm using slurry and grass/maize silage and having potential to use heat ....... 48 7.1.1 7.1.2 7.1.3 7.1.4 7.1.5 7.1.6

General Overview, Input Substrates and Potential Methane Yields .............................................................................................48 Environmental Permitting ..............................................................................................................................................................49 Plant Design and Equipments ........................................................................................................................................................49 Outputs of the AD Process (Energy and Digestate) ......................................................................................................................50 Economic Viability ........................................................................................................................................................................51 Recommendations ..........................................................................................................................................................................54

7.2 Site 2 (499 kW): A Vegetable Farm using Poultry Manure and Energy Crops ....................................................... 54 7.2.1 7.2.2 7.2.3 7.2.4 7.2.5 7.2.6

General Overview, Pre-Selection Wet/ Dry Digestion, Input Substrates and Methane Yields ....................................................54 Environmental Permitting ..............................................................................................................................................................56 Plant Design and Equipments ........................................................................................................................................................56 Outputs of the AD Process (Energy and Digestate) ......................................................................................................................57 Economic Viability ........................................................................................................................................................................59 Recommendations ..........................................................................................................................................................................61

7.3 Site 3 (190 kW): An agricultural AD plant digesting mainly grass silage and supplying heat and possibly electricity to a proposed industrial site ........................................................................................................................ 62 7.3.1 7.3.2 7.3.3 7.3.4 7.3.5 7.3.6


7.4 Site 4 (105 kW): A 600 LU dairy farm using slurry, manure, grass and wheat, and having some digestate storage capacity already................................................................................................................................................ 69 7.4.1 7.4.2 7.4.3 7.4.4 7.4.5 7.4.6


7.5 Site 5 (250 kW): A 1000 LU cow farm using cow slurry and silage........................................................................... 75 7.5.1 7.5.2 7.5.3 7.5.4 7.5.5 7.5.6


7.6 Site 6 (250 kW): A Pig Farm using Pig Slurry and Energy Crops ............................................................................ 81 7.6.1 7.6.2 7.6.3 7.6.4 7.6.5 7.6.6 7.6.7

General Overview, Input Substrates and Potential Methane Yields .............................................................................................81 Environmental Permitting ..............................................................................................................................................................82 Plant Design and Equipments ........................................................................................................................................................82 Outputs of the AD Process (Energy and Digestate) ......................................................................................................................83 Economic Viability ........................................................................................................................................................................83 Scenario 6 - Option 2: Additional Energy Crops as AD Feedstock..............................................................................................85 Recommendations ..........................................................................................................................................................................88

7.7 Site 7 (75 kW): A Cow Dairy Farm using Slurry, Manure and small amounts of Energy Crops........................... 88 7.7.1 7.7.2

General Overview, Input Substrates and Potential Methane Yields .............................................................................................88 Environmental Permitting ..............................................................................................................................................................89

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7.7.3 7.7.4 7.7.5 7.7.6 7.7.7

Plant Design and Equipments ........................................................................................................................................................90 Outputs of the AD Process (Energy and Digestate) ......................................................................................................................91 Economic Viability ........................................................................................................................................................................91 Scenario 7 – Option 2 and 3: Taking in different amounts of food waste to the AD Plant at Site 7............................................93 Recommendations ..........................................................................................................................................................................95

7.8 Site 8 (861 kW): A Community Based AD Plant digesting Wastes, Slurry and Energy Crops............................... 95 7.8.1 7.8.2 7.8.3 7.8.4 7.8.5 7.8.6

Preliminary Note: Co-digestion of Sewage Sludge with other Substrates....................................................................................95 General Overview, Input Substrates and Potential Methane Yields .............................................................................................96 Plant Design and Equipments, Digestate Management.................................................................................................................97 Energy Production..........................................................................................................................................................................97 Economic Viability ........................................................................................................................................................................98 Recommendations ....................................................................................................................................................................... 100

8 Recommendations to Future Rural Biogas Plant Operators ......................... 102 8.1 On-farm AD and the Farm Management.................................................................................................................. 102 8.1.1 8.1.2

Integration of a Biogas Plant into the Farm Concept ................................................................................................................. 102 General Technical Recommendations concerning Farm Management...................................................................................... 102

8.2 Planning and Approval ............................................................................................................................................... 103 8.2.1 8.2.2 8.2.3

Decision-making Criteria............................................................................................................................................................ 103 Co-digestion of Wastes ............................................................................................................................................................... 103 Optimisation of the Approval Procedure and Connection to the Grid ....................................................................................... 104

8.3 Successful Operation of the Biogas Plant .................................................................................................................. 105 8.3.1 8.3.2 8.3.3

Expertise on the AD Process....................................................................................................................................................... 105 Effort and Labour........................................................................................................................................................................ 105 Long-term Viability of the Installation....................................................................................................................................... 106

9 Conclusions ......................................................................................................... 108 9.1 Current status of AD in the United Kingdom within a European Context ............................................................ 108 9.2 Assessment of the eight pre-selected potential Biogas Plants in Cornwall.............................................................. 109 9.2.1 9.2.2

Technical Feasibility and total potential Energy Generation ..................................................................................................... 109 Economic Assessment................................................................................................................................................................. 111

9.3 Possible Barriers and Chances for on-farm AD in the UK and Cornwall .............................................................. 114 9.3.1 9.3.2 9.3.3 9.3.4

Chances for Farmers and Industries............................................................................................................................................ 114 Uncertainties on Income from Electricity for UK Biogas Plant Operators................................................................................ 115 Possible Advantages of a Guaranteed Feed-in Tariff................................................................................................................. 115 Grants .......................................................................................................................................................................................... 117

10 References and Acknowledgements.................................................................. 118 10.1 List of References ........................................................................................................................................................ 118 10.2 Acknowledgements...................................................................................................................................................... 119

11 Annexes................................................................................................................ 120 11.1 Abbreviations............................................................................................................................................................... 120 11.2 Economic Modelling: General Assumptions ............................................................................................................. 122 11.3 Site-specific Annexes ................................................................................................................................................... 124 11.3.1 11.3.2 11.3.3 11.3.4 11.3.5 11.3.6 11.3.7 11.3.8

Annex to Site 1............................................................................................................................................................................ 125 Annex to Site 2............................................................................................................................................................................ 128 Annex to Site 3............................................................................................................................................................................ 131 Annex to Site 4............................................................................................................................................................................ 134 Annex to Site 5............................................................................................................................................................................ 137 Annex to Site 6............................................................................................................................................................................ 140 Annex to Site 7............................................................................................................................................................................ 146 Annex to Site 8............................................................................................................................................................................ 155

11.4 AD Companies ............................................................................................................................................................. 158 11.4.1 Biogas plant equipment suppliers in the UK market.................................................................................................................. 158 11.4.2 Profiles of Companies which Contributed to this Study’s Results by giving UK market prices .............................................. 163

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Economic Modelling of AD in Cornwall – Figures and Tables

List of Tables Table 1-1 Table 2-1 Table 2-2 Table 3-1 Table 3-2 Table 3-3 Table 3-4 Table 3-5 Table 4-1 Table 4-2 Table 4-3 Table 5-1 Table 6-1 Table 6-2 Table 7-1 Table 7-2 Table 7-3 Table 7-4 Table 7-5 Table 7-6 Table 7-7 Table 7-8 Table 7-9 Table 7-10 Table 7-11 Table 7-12 Table 7-13 Table 7-14 Table 7-15 Table 7-16 Table 7-17 Table 7-18 Table 7-19 Table 7-20 Table 7-21 Table 7-22 Table 7-23 Table 7-24 Table 7-25 Table 7-26 Table 7-27 Table 7-28 Table 7-29 Table 7-30

Executive Summary of Energy Production Scenario 1 to 8 Primary energy production of biogas and electricity production from biogas in the EU (including landfill gas and sewage sludge gas) in 2005 and 2006 [EurObserv'ER, 2007a; EurObserv'ER, 2007b] Overview of current AD facility types in the UK Overview of key elements in the UK regulatory regime for AD plants Material Categories of the EU Animal By-Products Regulation EU Standard and National Standard for ABP digestion Type of authorisation for AD activities requiring EA authorisation Examples of Effective Sewage Sludge Treatment using AD Capital Costs for Biogas Upgrading (indicative) Running Costs for Biogas Upgrading (indicative) Example of fertiliser application summary (potential for replacement of fertiliser by digestate) Typical WPD Connection Voltages for Renewable Energy Generators of different sizes Assumed Standard Substrate Costs for AD feedstock Parameters for Sensitivity Analysis Site 1: Biogas substrates and anticipated biogas production (annual mean) Scenario 1: Substrate mix when cows are kept inside and while they are kept free range Site 1: Environmental Permitting Requirements Scenario 1: Biogas Plant Feeding and Key Process Parameters Scenario 1: Energy Generation Scenario 1: Digestate Nutrients for Landspreading Summary Economic Viability Scenario 1 Overview of Economic Viability and Grant Requirement in Scenario 1 Sensitivity Analysis Scenario 1 Scenario 2: Biogas Substrate Mix and anticipated Biogas Production (annual mean) Scenario 2: Biogas Substrate Mix throughout the Year Site 2: Environmental Permitting Requirements Scenario 2: Key Process Parameters Scenario 2: Energy Generation Scenario 2: Digestate Characteristics after passing a Solid/Liquid-Separator Scenario 2: Digestate for spreading to own land after Solid/Liquid-Separation and partial digestate transport off-farm to neighbours Summary Economic Modelling Scenario 2 Grant Requirements Scenario 2 Sensitivity Analysis Scenario 2 Scenario 3: Biogas substrates and anticipated biogas production Scenario 3: Biogas substrate mix when cow manure is available (cows are housed) and when manure is not available Scenario 3: Environmental Permitting Requirements Scenario 3: Biogas Plant Feeding and Key Process Parameters Scenario 3: Energy Generation Scenario 3: Digestate Nutrients for Landspreading Summary Economic Viability Scenario 3 Grant Requirement in Scenario 3 Sensitivity Analysis Scenario 3 Site 4: Available biogas substrates and anticipated biogas production (annual mean) Scenario 4: Substrate mix while animals are housed and while cows are kept free range

9 15 17 19 20 20 22 26 33 34 36 41 46 47 48 48 49 50 51 51 52 53 53 55 55 56 57 58 58 59 59 60 61 62 63 63 64 65 65 66 67 68 69 69

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Table 7-31 Table 7-32 Table 7-33 Table 7-34 Table 7-35 Table 7-36 Table 7-37 Table 7-38 Table 7-39 Table 7-40 Table 7-41 Table 7-42 Table 7-43 Table 7-44 Table 7-45 Table 7-46 Table 7-47 Table 7-48 Table 7-49 Table 7-50 Table 7-51 Table 7-52 Table 7-53 Table 7-54 Table 7-55 Table 7-56 Table 7-57 Table 7-58 Table 7-59 Table 7-60 Table 7-61 Table 7-62 Table 7-63 Table 7-64 Table 7-65 Table 7-66 Table 7-67 Table 7-68 Table 7-69 Table 7-70 Table 7-71 Table 7-72 Table 7-73 Table 7-74 Table 7-75 Table 9-1 Table 9-2 Table 9-3 Table 9-4

Table 11-1

Site 4: Environmental Permitting Requirements Scenario 4: Biogas Plant Feeding and Key Process Parameters Scenario 4: Energy Generation Scenario 4: Digestate Nutrients for Landspreading Summary Economic Modelling Scenario 4 Grant Requirement in Scenario 4 Sensitivity Analysis Scenario 4 Site 5: Available substrates and anticipated biogas production (annual mean) Site 5: Recommended substrate mix when cows are kept inside and while kept free range Site 5: Environmental Permitting Requirements Scenario 5: Key Process Parameters Scenarios 5: Energy Generation (annual mean) Scenario 5: Digestate Nutrients for Landspreading Summary Economic Modelling Site 5 Overview of Economic Viability and Grant Requirement in Scenario 5 Sensitivity Analysis Scenario 5 Scenario 6: AD substrates and anticipated biogas production (annual mean) Scenario 6: Biogas substrate throughout the year Scenario 6: Environmental Permitting Requirements Scenario 6: Key Process Parameters Scenario 6: Energy Generation Scenario 6: Digestate Nutrients for Landspreading Summary of Economic Viability Scenario 6 Grant Requirement in Scenario 6 Sensitivity Analysis Scenario 6 Scenario 6 – Option 2 (Additional Energy Crops): AD Substrates and Biogas Production Scenario 6 – Option 2 (Additional Energy Crops): Key Process Parameters Summary Economic Modelling Scenario 6 – Option 2 (with additional energy crops) Scenario 7: Available substrates and anticipated biogas production (annual mean) Scenario 7: Biogas substrate mix when cows are kept inside and free range Scenario 7: Environmental Permitting Requirements Scenario 7: Key Process Parameters Scenario 7: Energy Generation Scenario 7: Digestate Nutrients for Landspreading Summary Economic Modelling Scenario 7 Grant Requirement Scenario 7 Sensitivity Analysis Scenario 7 Scenario 7 – Option 2 (with 1,000 t/a Food Waste): Summary Economic Modelling Scenario 7 – Option 3 (with 4,000 t/a Food Waste): Summary Economic Modelling Scenario 8: AD substrates and anticipated biogas production (annual mean) Scenario 8: Key Process Parameters Scenario 8: Energy Generation Summary Economic Modelling Scenario 8 Grant Requirement Scenario 8 Sensitivity Analysis Scenario 8 Anticipated Methane and Energy Production of the eight Biogas Plants of this study Overview Economic Viability Scenario 1 to 8 Grant Requirements Scenario 1 to 8 Example of possible benefit from AD electricity of two sites with different own electricity demand under the double ROCs concept (assuming that biogas electricity is used to cover own electricity demand) Assumptions of the Economic Modelling

70 71 71 72 73 74 74 75 76 76 77 78 78 79 80 80 81 81 82 82 83 83 84 85 85 86 86 87 89 89 89 90 91 91 92 93 93 94 94 96 97 98 98 99 100 110 112 113

116 122

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List of Figures Figure 1-1 Figure 4-1 Figure 7-1 Figure 7-2 Figure 7-3 Figure 7-4 Figure 7-5 Figure 7-6 Figure 7-7 Figure 7-8 Figure 7-9 Figure 7-10 Figure 7-11 Figure 7-12 Figure 7-13 Figure 7-14 Figure 7-15 Figure 7-16 Figure 9-1 Figure 9-2

Executive Summary Economic Viability Scenario 1 to 8 UK CNG Filling Stations Proposed AD plant Scenario 1 10-year Cash Flow Projection Scenario 1 Proposed AD Plant Scenario 2 10-year Cash Flow Projection Scenario 2 Proposed AD plant Scenario 3 10-year Cash Flow Projection Scenario 3 Proposed AD plant Scenario 4 10-year Cash Flow Projection Scenario 4 Proposed AD Plant Scenario 5 10-year Cash Flow Projection Scenario 5 Proposed AD Plant Scenario 6 10-year Cash Flow Projection Scenario 6 10-year Cash Flow Projection Scenario 6 – Option 2 Proposed AD plant Scenario 7 10-year Cash Flow Projection Scenario 7 10-year Cash Flow Projection Scenario 8 Summary of Profitability AD Scenario 1 to 8 Scenario 1 to 8: Business Profit/ Losses without grant and with 50% grant on total investment costs, assuming that either 2 x ROCs or only 1 x ROCs could be claimed

10 34 50 52 57 60 64 67 71 73 77 79 82 84 87 90 92 99 112 113

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Economic Modelling of AD in Cornwall

1 Executive Summary 1.1 Introduction Essentially due to the utilisation of landfill gas, the UK was the leading biogas producer in the EU until the year 2005. Sewage sludge digestion is also common; approximately 50% of the waste water treatment plants have digesters. But the number of UK agricultural biogas plants is very small, only very few farmers have implemented anaerobic digestion. Anaerobic digestion (AD) contributes to the establishment of an environmentally sound slurry and manure management on farm. It is currently the most promising way to tackle gaseous emissions from agricultural activity. AD reduces climate gas emissions (CH4, N2O), and minimises odour nuisances. In addition, it generates digestate with improved fertiliser value, which results in better nutrient uptake by plants and fewer leaching losses. At the same time the generated energy has the potential to displace other energy sources such as fossil energy. This reduces greenhouse gas emissions and contributes towards a more sustainable energy concept. This study researches AD possibilities in Cornwall. Eight rural sites were pre-selected by Cornwall Agri-food Council. The AD scenarios are based on the individual site requirements and evaluate technical feasibility and economic viability of a biogas plant.

1.2 AD Regulations Unprocessed farm slurry and manure spread to land is classed as a non-waste by-product. But manures and slurries destined for AD treatment and digestate from slurry and manure are currently classed as waste because there has been further processing to recover energy. This brings manures and slurries under the regulatory regime of the Environment Agency (EA), which is responsible for all waste management activities. Wastes include kitchen waste, food waste, non AD crop residues and the above mentioned manures and slurries which are digested. If AD inputs are waste, all outputs are waste. EA authorisation is required for storage and pre-treatment, digestion, post-treatment, digestate management and combustion of biogas. On 6 April 2008 the Environmental Permitting Regulations came into force, combining the existing Waste Management Licensing regulations with Pollution Prevention Control regulations. Under the new regulatory regime biogas plant operations are either authorised by Environmental Permit or by using Registered Exemptions. Registered Exemptions use a light touch regulation to cover low risk waste operations and requires either very small annual fees or is free for agricultural exemptions. Digestion of food-wastes, residues from food-processing and animal by-products bring the AD plant under the Animal By-Product (ABP) Regulations. All ABP treatment must be approved by Animal Health. ABP processing requires pasteurisation, regular analyses and other provisions. Digestate regulations are currently subject of changes. A Digestate Standard and Protocol (PAS 110) is scheduled for October 2008. The protocol is designed to assure digestate meeting it’s criteria, is of sufficient quality to be classified as a non-waste material and therefore not subject to the waste regulatory regime. 7


1.3 Biogas Utilisation Biogas can be converted to energy by heat generation (gas boiler), electricity production with export to the grid (preferably in combination with heat in CHP units) or by upgrading to biomethane (for use as vehicle fuel or injection in the gas grid). Investment in facilities for cleaning and upgrading of biogas to biomethane is only justified on larger scales. Combustion of biogas for heating purposes will not be the most favourable option in Cornwall. Even very small plants would generate far more heat than the farm would require; this would result in poor valorisation of the generated energy (despite significant investment and ongoing costs). A Combined Heat and Power Plant (CHP) is particularly suitable at an AD plant as some of the generated heat can be directly used to maintain the required digester temperature for the biological process. Locally used surplus heat can generate additional revenue. The UK has no guaranteed feed-in tariff for electricity from renewable sources. Revenue from electricity consists of two main elements: the actual sales price and revenues from ROCs. The wholesale electricity price is in principle a negotiation result between the electricity producer and the electricity buyer. Power purchase agreements will price the electricity on its shape against the electricity market. Rural locations can obtain additional financial benefits above the basic electricity price (‘embedded benefits’); sites located at far ends of the grid reduce the requirement for moving electricity over this long distance and therefore also reduce distribution losses. Renewable electricity generating stations including biogas plants with electricity production can be accredited for Renewable Obligation Certificates (ROCs). In order to be accredited an approved electricity meter needs to be installed. Since April 2007 it is no longer necessary to sell electricity to the main power grid in order to obtain ROCs, it is now sufficient to install the meter at the point of electricity generation. One ROC is issued per one MWh of generated electricity. ROCs can either be sold directly to electricity providers or they can be auctioned. In the last five years the average trading value of ROCs ranged approximately between £40 and £50. The coming Energy Bill foresees that 2 x ROCs will be available for biogas energy from April 2009 on. Confirmation of the double ROCs concept is awaited in autumn 2008. The double ROCs concept will significantly improve the economic viability of AD plants.

1.4 Grid Connection An AD plant will normally be connected to the low or medium voltage distribution network. Contact with the Distribution Network Operator which in Cornwall is Western Power Distribution (WPD) at an early stage is important to ensure that the desired connection date can be met. WPD will carry out a feasibility study and will decide upon necessary grid reinforcement. Electricity generators must wait for grid reinforcement completion (if necessary) before they are connected. Costs are associated with the staged connection process. There is no priority access for renewable energy.

1.5 Explanations to the Economic Modelling of this Study The detailed economic modelling of the eight studied scenarios is based on current UK market prices. A number of pre-selected companies were contacted. While some company offers covered full costs 8


(including digestate storage, indications for necessary earth works etc.), others included the actual plant components only. Missing cost elements were added to obtain a full final price. After assessing technical suitability and assuring completeness of all associated costs the most favourable option was selected and taken as basis for the economic modelling. It is assumed as a standard that biogas is converted to electricity and heat by utilisation of a CHP unit. Revenue from electricity is priced with 14.5 p/kWh (= 5.5 p/kWh wholesale electricity price + 2 x 4.5 p/kWh for double ROCs). Site specific heat utilisation potential is taken into account. While some of the scenarios have good potential for at least partial heat supply to consumers, others do not have this option. All scenarios include digestate storage capacity for 182 days. Fertiliser value of digestate is considered. The modelling includes a sensitivity analysis and assesses grant requirements.

1.6 Individual Case Studies Seven farm-based sites (Scenarios 1 to 7) and the community based Scenario 8 were evaluated within this project (Table 1-1). The installed capacities of the CHP units vary between 75 and 861 kWel. In Scenario 5 and 6-1 cow and pig slurry are the main AD inputs. Scenario 2, 3 and 6-2 are based on digestion of high amounts of energy crops. Table 1-1

Executive Summary of Energy Production Scenario 1 to 8

Scenario/ substrates

1

cow slurry, grass/ maize silage 2 cow slurry, poultry manure, silage, potatoes, straw 3 cow manure, grass, straw 4 cow slurry, manure, grass silage, wheat 5 cow slurry, potatoes 6-1 pig and cattle slurry, some grass 6-2 pig slurry, silage3) 7 cow slurry, horse manure, silage 8 cow slurry, maize silage, wastes (meat, fish, food) Total

Throughput substrates t/a 2,350

CH4 production m³ CH4/d 363.9

Installed capacity CHP unit kWel 75

Electricity generation CHP unit MWhel/a 436.93

Available Avaielectricity1) lable heat1) MWhel/a MWhth/a 393.24 362.28

Utilised heat2) % 38.9%

10,405

2515.6

499

3507.55

3181.35

2689.35

4.5%

4,263 6,499

931.1 578.1

190 104

1298.23 803.90

1165.81 717.89

940.85 445.48

100% 0%

17,670 22,900

1065.0 1172.4

250 250

1461.66 1617.56

1311.11 1457.42

824.13 820.65

17.5% 74.7%

28,435 5,056

2476.4 349.4

499 75

3443.76 415.81

3109.71 373.40

2185.26 286.11

30.2% 1.7%

42,530

4038.6

861

5689.96

5092.51

3288.76

83.4%

117,208

12,318.1 2,304

17,057.804) 15,345.025) 11,022.22

43.1%

1)

Actually available energy after self-consumption of the AD process and losses during transport/ transformation 2) Assumed heat supply to nearby consumers, expressed as % of surplus heat of the AD process (‘Available heat’) 3) Scenario 6-2 is considered to calculate ‘Total’ in the last line 4) This corresponds to a power output of 1,947 kWel 5)This corresponds to a power supply of 1,752 kWel

The total energy generation potential of Scenario 1 to 8 can be summarised as follows:

9


At an installed capacity of 2.30 MW, the 8 CHP units would generate 1.95 MW (= 17,058 MWh/a) of electricity. Of this, 1.75 MW (= 15,345.0 MWh/a) could actually be fed into the grid, the rest being self-consumption of the AD facility and energy losses (0.20 MW).

Heat utilisation potential was studied on a monthly pattern of availability and need of customers. The assumed heat valorisation would displace at least 475,000 litres of heating oil per year.

Implementation of Scenario 1 to 8 would reduce greenhouse gas emissions by approximately 15,000 tonnes CO2 equivalent per year.

Better heat utilisation would further improve environmental benefits.

The four scenarios with an installed capacity below 200 kWel are economically not viable (Figure 1-1), with the economic modelling forecasting Business Losses. With an installed capacity of 250 kWel or higher, the other scenarios would generate positive Business Profit. Aside from the community based Scenario 8, the slurry-based scenarios 5 and 6-1 (both with an installed capacity of 250 kWel) are the most favourable ones. They promise a Business Profit between £40,000 and £50,000 per year at a Payback Period of around 8 years. Scenario 6-1 profits from higher biogas heat valorisation and also from an even flow of pig slurry all year round. Cattle are kept free range during several months per year in all scenarios. This does not only reduce the total amount of cattle slurry for digestion but also the continuity of its availability. At an installed capacity of 499 kWel Scenario 2 and Scenario 6-2, which include co-digestion of high amounts of energy crops, have significantly higher business volume but result in lower Business Profit and longer Payback Periods compared to the slurry-based 250 kW-scenarios. The reduced profitability is mainly a result of the fact that aside from investment for the actual AD plant, additional investment for silage storage capacity is required. Revenue

1.000.000 £/a 750.000 £/a

Ongoing costs without write-off Total costs including write-off Business Profit/ Losses

500.000 £/a 250.000 £/a 0 £/a -250.000 £/a -500.000 £/a -750.000 £/a -1.000.000 £/a

Revenue (£/a) Ongoing costs without write-off Total costs including write-off Business Profit/ Losses (£/a) payback period (years) installed capacity (kW el.) total investment (£) of this: energy crop storage (%)

Figure 1-1

Scenario 1

2

3

4

5

6-1

6-2

7

8

69.854

505.889

240.056

112.702

204.791

258.272

533.873

59.129

1.009.906

-81.538

-378.214

-203.384

-98.006

-102.838

-144.935

-405.907

-70.776

-702.423

-119.219

-476.692

-271.430

-134.511

-164.064

-208.678

-515.221

-106.331

-934.214

-49.364

29.198

-31.374

-21.809

40.727

49.594

18.651

-47.202

75.692

10,7 499 1.364.085 25,1

26,0 190 953.176 15,3

32,0 104 470.054 3,0

8,1 250 822.122 0,0

7,7 250 876.590 0,0

12,3 499 1.571.720 21,5

neg. 75 506.921 11,4

neg. 75 464.489 0.0

10,3 861 3.157.036 0.0

Executive Summary Economic Viability Scenario 1 to 8

A grant of 30% on total investment would shorten the Payback Period for the 250 kW slurry-based biogas plants to around 5 years. This would further encourage the farmers to decide in favour of AD. Environmentally this would be of special benefit, as slurry-based biogas plants have a particularly 10


high greenhouse gas reduction effect (mainly related to reduced emissions during slurry/ manure management). To shorten the Payback Period of the 190 kW plant in Scenario 3 to approximately 8 years would require a grant of 55%. The 104 kW plant in Scenario 4 would require 60% grant for a Payback Period around 8 years; however it needs to be taken into account that investment costs in Scenario 4 include only partial digestate storage capacity as some appropriate storage is already available on farm. All mentioned grant benefits are based on the assumption that 2 x ROCs could still be claimed when taking a grant. At present a recipient of a government grant would probably not receive 2 x ROCs but would fall back on single ROCs, as there is concern that this could otherwise be construed as double state support. The individual case studies of this report provide evidence that if a farmer is obliged to choose between taking a grant and loosing the second ROC or refusing all grant and claiming 2 x ROCs instead, the latter will in general be the more favourable option. This however can result in a situation in which the AD project would need some limited grant in order to be economically viable, but accepting a grant would worsen the prospect. Aside from economic viability other criteria can be meaningful when taking decisions. Site 7 is a farm which is embedded in a larger complex including facilities for education and research. A biogas plant at this site could be of particular benefit for the development of AD in Cornwall. Detailed feasibility studies are recommended before taking final decisions. Investment costs were calculated according to preliminary prices of non-binding offers from the companies as well as preliminary price assessments from the planning undertaken during this study. Further studies should include substrate analyses, substrate costs, precise assessment of heat utilisation potential and of the possibility for electricity utilisation on site. In addition, cost shifts in other units of the farm business due to AD should be analysed. Dairy units could save costs, since no extra slurry storage under or beneath the barns needs to be foreseen (slurry should be fed to the digester and would be stored afterwards). On the other hand a more expensive scrape system should be installed instead of a flush system (cleaning of barns). Additional costs might also be associated with more slurry/ manure transport (if necessary). This needs to be studied in more detail.

1.7 Recommendations to Future Biogas Plant Operators A biogas plant can be a source of additional income for farmers but it can not fix a financially stricken farm business. Investment in a biogas plant is long-term fixed and should be carefully evaluated before taking the decision. If well integrated into the farm concept, the AD unit has mostly positive interactions with the rest of the farm business. This includes provision of digestate with high fertiliser value, supply of heat, reduction of odour nuisance and reduced storage capacity for untreated slurry (slurry will be stored after digestion). Cooperation with neighbouring farmers can be of advantage. Slurry should be used as fresh as possible and should preferably be fed directly into the biogas plant. To clean the barns, scrape systems are more favourable than flush systems. Dilution of manure will require larger and more expensive digestion facilities and can also increase the stratification risk within the digester. Litter material which is favourable in the digestion process should be used in the barns. Woody material such as sawdust will hardly yield any biogas. Sand will clog and damage equipment. It will precipitate during digestion and fill the digestion tank, thus continuously reducing the effective digester volume. Straw is favourable; it should be chopped prior to using it in the stable. Digestate cannot be stored under the barns because degassing can continue after digestion. The volume of main digesters cannot be considered as storage volume, extra storage is required. 11


A biogas plant operator should be well-informed about technical and biological issues, and regulatory frameworks. An AD plant requires continuous labour and attention. Any decline in gas production, a lowered efficiency of the CHP unit or a temporary breakdown of equipment can significantly reduce revenue. Maintenance should be carried out on a regular basis. It is of advantage to decide in favour of technologies from companies which provide support. Process imbalances require extra attention. Contact to other biogas plant operators and regular exchange of knowledge is beneficial.

1.8 Conclusions The economic viability of biogas plants in Cornwall generally depends on several key factors:

scale of the biogas plant

amount of slurry and manure, housed time of breeding stock

availability of energy crops and their specific costs

production of waste on site

policies and regulations when treating other wastes

favourable approval conditions which can be fulfilled at reasonable costs

gate fee which is charged or paid for waste

value of bio-fertiliser

the value at which the ROCs are traded

possibility of on site heat use

reasonable investment and building costs

already available equipment or buildings that can be integrated in the biogas concept

availability of grants

In Cornwall, the time in which animals are kept free range can be high. No slurry or manure at all or a much reduced amount is collected during this period. This does not only reduce the total amount of substrate but also the continuity of its availability. Availability of some energy crops or other organic substrates can help to underpin the variability in availability of slurry and manure. Energy crop digestion requires additional investment in feedstock storage, which reduces the possible benefit. It is one result of the economic modelling of this study that due to the high extra investment in feedstock storage, co-digestion of energy cops can result in reduced profitability compared to digestion of manure alone. Certainly if more energy crops are to be used, a special incentive would be required. Co-digestion of wastes can be beneficial for the profitability of an AD plant and can be an option which is particularly friendly to the environment. Provided that substrates are not contaminated, this option closes nutrient cycles and converts already available materials into energy. However, waste treatment requires special pre-treatment and therefore investment costs are higher. In addition, farmers might be reluctant to accept wastes to their farms. Biogas technologies need to be established in the UK. Profitability and reliability of renewable energy technologies need confidence if more stakeholders are to invest. Grants are an appropriate means to encourage farmers in taking the opportunity to make themselves suppliers of energy. The results of 12


this study demonstrate that many agricultural AD plants will require grants to reach economic viability and acceptable payback periods. If falling back on single ROCs however, profitability of a biogas plant is very much at stake even with high grants. Clearly the electricity value is of decisive influence on the viability of a rural AD project. Refusing all grants and claiming 2 x ROCs will in most cases be the more favourable option. Having no benefit when obtaining a grant, this results in a situation in which no incentive is possible for an AD plant that is close to being economically viable but not yet within risk boundaries which the farmer is willing to take. Unlike in other countries, there is no guaranteed feed-in tariff for electricity from renewable sources. Energy producers rely on the value of ROCs to supplement the wholesale electricity price that they receive. Together with the problem of falling back on single ROCs when accepting a grant this additional risk element may be an obstacle to a more widespread implementation of on-farm anaerobic digestion in the UK.

13


2 Introduction 2.1 The Anaerobic Digestion Process and its General Environmental Benefits Climate change and emission reduction belong to the most important and pressing issues of this time. Anthropogenic emissions affecting global climate change comprise, amongst others, the gases carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). Besides rice cultivation and enteric fermentation, animal manure/ slurry is one major source for climate gas emissions (CH4, N2O) in the agricultural sector. Anaerobic digestion (AD) of manure, and hence the production of biogas, is currently the most promising way to tackle climate gas emissions from agriculture and especially from animal and dairy production. AD has the potential of producing green energy like power, heat or vehicle fuel. Additionally added organic wastes and energy crops can boost the gas yield and at the same time AD contributes to regional waste management schemes. AD also facilitates the establishment of an environmentally sound manure management system on farm. It results in a digestate with an improved fertiliser value and also has the potential to displace mineral fertilisers. A pollutant arising from manure spreading is nitrate. In raw animal manure, 3050% of the nitrogen is in organic form with the rest as ammonia. Ammonia can be converted to nitrate for plant uptake, while some plants may use ammonia directly. In the organic form, nitrogen must be first mineralised. The extent of nutrient uptake by plants depends on the time of application and there is always the possibility that nutrients will be leached from the soil when plants are unable to take them up. AD converts much of the organic N into ammonia, yielding a digestate with 60-80% of the total nitrogen content in the form of ammonia [Banks et al., 2007]. This makes it much more predictable, minimises leaching losses and is in line with the development of good agricultural practices. In addition, odour emissions are significantly reduced through the anaerobic process. Biogas production makes use of a naturally occurring anaerobic process and supplies a controlled technical environment that allows catching and utilising the gases produced. Co-digestion of manure with other biomass can improve methane generation. Two main factors influence the result: a higher biogas potential of the additional biomass and beneficial effects on maintaining or establishing environmental conditions favourable for the microbial consortium. A strong reason for co-digestion of feedstocks is the adjustment of the carbon-to-nitrogen (C:N) ratio, which should be in a range of 2530:1 [Ward et al., 2008]. Different biomass types vary widely in their C:N ratios and co-digestion of a low C:N ratio feedstock with a high C:N ratio feedstock can adjust the resulting ratio closer to optimum.

2.2 Biogas in Europe and in the United Kingdom 2.2.1

AD in the European Union

The EU countries are becoming more and more interested in biogas production. Biogas primary energy production increased by 13.1% in 2006 with respect to 2005 [EurObserv'ER, 2007a], see Table 2-1. In particular, electricity production from biogas rose strongly (+28.6%), especially due to a significant increase in electricity produced in CHP (combined heat and power plant) units, which in 2006 moved ahead of installations producing electricity alone. CHP type production is most often used in the case of sewage sludge digestion, small agricultural units, and solid waste treatment plants. In 14


this type of valorisation, the production of heat participates directly in the methanisation process, since at least part of the heat serves to keep the digester at a constant temperature. If other heat consumers are available, the overall efficiency of the installation can be further increased. Landfill gas is principally used to produce only electricity, which is injected into the power grid. In 2006, landfill gas contributed with 56.7%, sewage sludge gas with 18.3% and other biogas (including agricultural biogas and methanisation gas from municipal solid waste) with 25.0% to the total primary energy production of biogas in the EU. Table 2-1

Primary energy production of biogas and electricity production from biogas in the EU (including landfill gas and sewage sludge gas) in 2005 and 2006 [EurObserv'ER, 2007a; EurObserv'ER, 2007b] Primary energy production of biogas [ktoe/a]

Germany United Kingdom Italy Spain France Netherlands Austria Denmark Poland Belgium Greece Finland Czech Republic Ireland Sweden Hungary Portugal Luxembourg Slovenia Slovakia Estonia Malta Total EU

2005 1594.4 1440.3 343.5 316.9 220.0 119.0 30.8 91.5 50.7 84.0 36.0 63.5 55.8 34.3 29.8 7.1 10.1 7.4 6.8 4.8 1.3 0.0 4547.9

2006 1923.2 1498.5 353.8 334.3 227.0 119.0 118.1 93.6 93.8 83.3 69.4 63.5 59.9 34.7 27.2 10.5 9.2 8.9 8.4 4.8 1.3 0.0 5142.5

Primary biogas energy production per inhabitants [toe/(1000 inhab.*a)] 2006 23.3 28.1 6.1 7.6 3.6 7.3 14.3 17.4 2.5 8.0 6.2 12.1 5.8 8.3 3.7 1.0 0.9 19.4 4.2 0.9 0.9 11.5

Electricity production from biogas [GWh/a] 2005 4708.0 4690.0 1197.9 620.2 485.0 286.0 69.7 289.9 175.1 240.1 179.0 22.3 160.9 106.0 53.4 24.8 34.7 27.2 32.2 4.0 7.2 0.0 13413.4

2006 7338.0 4887.0 1336.3 674.9 503.0 286.0 409.8 280.1 241.2 237.2 578.6 22.3 174.7 108.0 46.3 22.1 32.6 32.6 32.2 4.0 7.2 0.0 17254.1

In the UK, landfill gas contributed with 88% to the total primary energy production of biogas in 2006. Total production increased with 4% in 2006 (with respect to 2005), essentially due to an increase in electricity generation from landfill gas, which has particularly benefited from the ROCs concept. The ROCs concept requires electricity suppliers to increase the share of electricity from renewable sources in total production each year (from 6.7% in 2006/07 to 15.4% in 2015). After a long time as the leading biogas producer, the UK had to give up its first place position to Germany since the year 2005 [EurObserv'ER, 2007a]. In Germany, biogas electricity increased by 55.9% in 2006 (with respect to 2005), principally due to new small farm plants equipped with CHP units [EurObserv'ER, 2007a]. The success is explained by the application of an especially attractive feed-in tariff for small biomass-based electricity production plants, including agricultural AD facilities, and additional payments for digestion of energy crops 15


alone, a bonus for the use of produced heat by consumers (other than the digestion plant itself) and a bonus for the implementation of high-performance technology such as dry digestion. In 2006, landfill gas contributed with 29.8%, sewage sludge gas with 19.2% and other biogas (including gas from agriculture and municipal waste methanisation plants) with 51% to the total primary energy production of biogas in Germany. Presently, around 3700 German biogas plants exist. In the EU, the additional biogas potential is mainly within the agricultural sector.

2.2.2

The Biogas Market in the United Kingdom

In the UK, there has been little development in biogas plant construction except at water treatment plants where approximately 50% of facilities have digesters using sewage sludge. Some of these use the biogas in CHP units and export electricity to the grid, whilst others use the energy for heat or flaring. In agriculture, the number of AD plants is very small: only 0.01% of UK farms have a digester [Banks et al., 2007]. A large number of small farm based biogas plants were built in the 1970’s and 80’s by Farmgas, which then formed a core of British expertise. Although Farmgas does no longer exist, their knowledge is still available at the companies Greenfinch (today the leading UK designer and manufacturer of AD systems) and Methanogen, which were both established in the 1990’s. Annex 11.4 provides an overview of companies active in the UK biogas sector. However, European companies focusing on building large AD facilities based on household wastes are not listed here. Large established companies with a key competence in treatment of MSW or source-separated biowastes, such as Dranco, Ros Roca, Valorga, Kompogas, Linde (Strabag), Xergi, work in an international context and the UK is part of their potential European market. A general overview of companies involved in anaerobic digestion together with an assessment of the suitability of their technology for biomass projects in the East of England was provided by Juniper [2007]. Unlike Europe, in the UK there was no significant construction of larger commercial plants until the construction of the Holsworthy Plant in 1993. The plant was technically successful, but failed commercially and was taken over by Summerleaze/ Andigestion, which now owns and runs the plant. Driven by increasing landfill tax, government incentives and the imperative to develop a low carbon economy, a number of plants were built from 2004 on:

Dumfries and Galloway: seven farm scale plants built by Greenfinch for environmental reasons; most are using the biogas for heat only

Ludlow, Shropshire: built and run by Greenfinch, capacity of 5,000 t/a, expandable to 7,500 t/a; feedstock of source-separated household wastes

Wanlip, Leicester: run by Biffa, processes 50,000 t/a waste material (organic fraction from a MBT system); material cannot be spread to farmland as it is not source-separated

Bedford: built by Biogen (UK), capacity of 42,000 t/a food waste and animal slurry; the plant is able to return the digestate to its own farmland

Isle of Lewis, Hebrides: Linde (Strabag) technology, capacity of 12,000 t/a food waste and animal slurry

Holsworthy, Devon: run by Summerleaze, design capacity of up to 140,000 t/a farm slurry, abattoir and food processing wastes; has just ceased to take slurries and uses only food wastes

Turriff, Aberdeenshire: John Rennie & Sons (farmers), capacity of 12,000 t/a slurry and abattoir wastes

16


Demo Plants: research and/ or experimental biogas facilities at Cambridge Research Park (Summerleaze), Horsington/ Somerset (Organic Power), Longstock/ Hampshire (Bioplex Ltd)

Orkney: Methanogen Ltd has constructed farm scale digesters on Westray

Blandford Forum, Dorset: farm based plant constructed by Biogas Nord

Kemble, Cirencester: farm based plant, construction by Greenfinch

Further stimulated by developments such as new grant funding from Defra and the Waste Resources Action Programme, the proposed increase from 1 ROC/MW to 2 (see Chapter 4.1.2) which is scheduled until at least March 2013 (and the Renewable Obligation policy scheduled to remain in place until 2027), resulted in a large increase in interest in building new biogas plants:

Manchester: MBT PFI contracts, Clarke Energy using Haase AD technology

West Lothian Council: MBT AD facility

30 to 40 planning applications are currently in progress for new plants

Today’s AD facilities in the UK can be categorised as shown in Table 2-2. Table 2-2

Overview of current AD facility types in the UK

Category type Single Farm using own feedstock Non ABP Multi Farm using own and imported substrates ABP Commercial or Merchant ABP Non ABP within food processing factory AD attached to MBT

t/a feedstock 5,000 – 15,000

feedstocks slurry, crops

15,000 – 40,000

slurry, crops, food waste, other

30,000 – 60,000

slurry, crops, food waste, other vegetable & fruit waste

15,000 – 20,000 40,000 – 60,000

organic fraction of MSW

Main income gate fee no

Comments ROCs yes

digestate displacement of fertiliser

for 35% of tonnage

yes

value to farmer

for 75% of tonnage

yes

value if sold to farmers

negative due to animal feed competition yes, £40/t

yes

value if sold to farmers

yes

negative, cannot be landspread

needs capital grant commercial from 30 kt/a on, otherwise grants needed commercial

only viable on low capital cost basis commercial within MBT envelop

2.3 Scope of this Study Technology is only one aspect when producing biogas. Other and maybe even more important aspects are the operator's knowledge of the whole digestion process, his management skills and financial incentives. The aim of successfully developing the AD branch by accelerating widespread, but appropriate utilisation of AD technologies relates not only to technical feasibility of new biogas plants but also to a careful evaluation of their economic efficiency. This project's objective is to research AD possibilities in Cornwall. Eight pre-selected rural scenarios are studied in detail. Technical feasibility and economic viability are analysed for each of the 17


scenarios. Individual requirements needed to comply with UK legislation and regulations are investigated. Economic viability calculations are based on UK market conditions within a European context. The site specific assessments also give consideration to nutrient values of digestates. For each of the studied scenarios, a 10 year cash flow projection with profit and loss forecast and sensitivity analysis is calculated. It is also studied if public grants are required.

18


3 The UK Regulatory Regime for Biogas Plants 3.1 Overview of Regulatory Approval Procedures for AD Plants It is important to contact the Local Authority Planning Department at an early stage and involve them in detail into the project. The Local Authority will assess the application and might carry out a consultation with local stakeholders. They will also decide on requirements of an Environmental Impact Assessment. The future biogas plant operator should be aware about the relevant regulatory regulations. For all permitted feedstocks, Table 3-1 reviews the main regulatory elements, including the Animal ByProduct Regulations (ABPR, see Chapter 3.2) and necessity of a licence from the Environment Agency (EA), further described in detail in the following chapters. The EA is the regulatory enforcement agency responsible for all waste management activities. This includes farm based plants that handle only their own wastes or manures. There are procedures to register exemption for processes that are not require to be licensed (Chapter 3.3). Table 3-1

Overview of key elements in the UK regulatory regime for AD plants

Type of waste Livestock waste Green waste Livestock/ green + catering waste Catering waste Catering waste + animal by-products Livestock waste + animal by-products Animal by-products (ABP)

ABP standard none under ABPR none under ABPR National ABPR National ABPR EU EU EU

Animal Health approval no no yes yes yes yes yes

EA licensing exemption licence required licence required licence required licence required licence required licence required

All ABP treatment must be approved by Animal Health before it can be used. Details of new sites should be submitted at the design stage to ensure that it complies with the regulations and that potential problems can be resolved before capital expenditure is involved. The Duty of Care applies to all ‘Controlled Waste’ from business and industry. Commercial, industrial, agricultural, household wastes and Hazardous Wastes are classified as ‘Controlled Waste’. This means that waste materials produced as part of a business or within a workplace are regulated by law and are subject to the Duty of Care, so the anaerobic digestion plant would be subject to scrutiny by those businesses and organisations which send their waste to the plant. Likewise, any wastes, especially rejects or pre-sorted material which are not processed in the plant, would be subject to Duty of Care and would have to be properly disposed of, via an appropriately authorised company. Digestate regulations are currently subject to changes. When the presently prepared Digestate Standard PAS 110 and Protocol (Chapter 3.4) is in operation in about October 2008, the biogas plant operator has the opportunity to choose between following the Environmental Permitting route (see Chapter 3.3) and applying for the Digestate Standard based on PAS 110.

19


3.2 ABP Regulatory Regime The EU animal by-products regulation divides animal by-products into three categories, which are described in Table 3-2 with indication if digestion in a biogas plant is possible. Table 3-2 Category 1 “high-risk”

Category 2 “mediumrisk”

Category 3 “low-risk”

Material Categories of the EU Animal By-Products Regulation includes specified risk materials (SRM) from abattoirs, e.g. bovine heads, spinal cords and stomachs; animals which may have been infected with TSEs, animals from experimental laboratories, zoo and pet animals includes animals which die on farms (which do not contain SRM), diseased animals, manure or animal by-products that could be contaminated with animal diseases, manure and digestive tract content

This material may only be incinerated.

This material must be incinerated or rendered. Although in Cat 2, ABP manure and digestive tract content can be digested as if it was a Cat 3 material and it may still be spread untreated on farmland, except pasture land. includes ABP from abattoirs which are fit but not destined This material may be incinerated, for human consumption, e.g. soft offal, blood, feathers, rendered or transformed in a hooves and hides; Cat 2 material which has been pressurecomposting or biogas plant. cooked at 133°C and 3 bar for 20 minutes; raw meat and fish Digestions in a biogas plant and from food manufacturers and retailers; raw milk, eggs, fish digestate utilisation are further and other sea animals (except for mammals), shells; food specified. waste from food processing factories which use ABP; food waste from retail outlets; catering waste from commercial and domestic kitchens

Important parameters for a biogas plant to be approved under the EU ABP Regulation are:

The particle size of all material must be reduced to below 12 mm.

All material must be pasteurised, either before or after digestion, at 70°C for one hour.

The plant must include a source of back-up heating for the pasteurisation unit.

Measures must be taken to prevent recontamination of the digestate with raw waste.

Digestate samples must be verified to have no salmonella and limits of enterobacteriaceae.

Digestate may not be applied to pasture land, being defined as land on which ruminants graze within 3 weeks and pigs within 8 weeks.

EU member states may adopt their own standards if the only Category 3 material being treated is catering waste. Table 3-3 compares the EU Standard to the National Standard. However, the national standards do not apply to supermarket food waste. Since practical biogas plants will need flexibility to handle all types of permitted organic waste, adoption of the EU regulatory regime is recommended. Table 3-3

EU Standard and National Standard for ABP digestion

Minimum temperature Minimum time Maximum particle size 70°C 1 hour 12 mm 57°C 5 hours 50 mm or 70°C 1 hour 60 mm For the National Standard, an additional barrier is: treat only meat-excluded catering waste or store the material for a minimum of 18 days (this could be anaerobic digestion of material for 18 days).

EU Standard National Standard

20


Biogas plant operators should be aware that, as the ABPRs require that digestate derived from ABP and catering waste is only applied to non-pasture land, livestock must not be allowed access to land to which this type of digestate has been applied for the indicated minimum time period (8 weeks for pigs, 3 weeks other farmed animals).

3.3 Environmental Permitting (EP) If a farmer intends to use slurry directly on land for beneficial purposes it is not classified as waste. However, if the intention is to use the slurry in an anaerobic digester then this slurry is currently classified as a waste before and after the AD process and is subject to the regulatory regime of the Environment Agency (EA), which is responsible for all waste management activities. The decision by the EA to classify slurries and manures which are destined for AD or which have been digested as waste is subject to ongoing discussions between the REA Biogas Industry Group and the EA. Meetings took place in June 2008 to discuss this issue. Currently, wastes include kitchen waste, food waste, non AD crop residues and abovementioned manures and slurries which are digested. If inputs to a biogas plant are waste, all outputs are waste and remain so until their final use. If waste inputs are accepted into a biogas plant, the following operations require EA authorisation:

storage and pre-treatment

anaerobic digestion

post treatment

use of digestate materials

combustion of biogas

However if inputs are non waste, then biogas output is non waste and digestate is non waste, provided it is certain to be used without further treatment as part of the continuing production process. Non wastes include crops grown specifically for AD. No type of EA authorisation is necessary for the digester (any digester size, including substrate storage and pre-treatment) and the biogas combustion; only very large gas combustion plants will require a (Local Authority issued) permit. In general, with non waste inputs, only the following may come under EA authorisation:

post treatment

use of digestate

Until April 2008 all biogas plants were subject to the requirements of the Waste Management Licensing Regulations (WML) and in some cases required a Pollution Prevention and Control Permit (PPC) in accordance with the Waste Management Licensing (England and Wales) (Amendment and Related Provisions) (No. 3) Regulations 2005. When using feedstock simply from the own farm, exemptions from requiring a Waste Management Licence were possible under Para 7A of the WML. On 6 April 2008 the Environmental Permitting (EP) Regulations came into force, replacing the WML. These new regulations will make existing legislation more efficient by combining Pollution Prevention Control (PPC) and Waste Management Licensing (WML) regulations. Where a biogas plant already

21


has a PPC permit or a Waste Management Licence it will automatically have become an Environmental Permit from 6 April, containing the same conditions as before. Table 3-4 compiles which type of authorisation is necessary for AD activities which involve wastes and therefore fall under the regulatory regime of the Environment Agency. Under the new regulations, biogas plant operations can be authorised in two main possibilities:

AD authorisation using Registered Exemptions: Registered Exemptions uses light touch regulation to cover low risk waste operations, and must not endanger human health or harm the environment. It uses either small annual registration fee or is free for agricultural exemptions.

AD authorisation using Environmental Permits: This new regime is based on an application for Environmental Permits which replace the WML licences and PPC permits, with one permit per site and operator. It bases on a risk-based approach to permitting compliance assessment and charging which uses standard or bespoke permits.

Table 3-4 Activity Digesting waste

Burning biogas (originating from wastes) as a fuel Storage, pre- and post-treatment (waste materials)

Use of digestate (originating from wastes)

Type of authorisation for AD activities requiring EA authorisation

digester up to 1000 m³ at place - where the input wastes (this includes manure and slurry going to AD) are produced - where the digestate is to be used - or occupied by the waste producer/ digestate user digester > 1000 m³ or other place in appliance with an aggregated rated thermal input of < 0.4 MW 0.4 to 3 MW storing waste for digestion-registered exemption under Para 12 chipping, shredding, pulverising, waste plant matter, up to 1000 t per week if > 1000 t/week stabilising (composting) digestate pasteurising waste/ digestate beneficial use on agricultural land various conditions including: - annual prior notification, with certificate of benefit/ risk assessment - secure storage at to 12 months, away from water courses, wells etc. - no more than 250 t/(ha*12 months)

Type of authorisation Registered Exemption Para 12 (free) includes storing the waste for digestion

Environmental Permit Registered Exemption Para 5 (free) Environmental Permit included in the Registered Exemption Para 12 (free) Registered Exemption Para 12 (free) Environmental Permit Registered Exemption Para 12 (free) Environmental Permit? Registered Exemption Para 7 annual review simplified procedure possible (e.g. beneficial spreading of no more than 50 t/(ha*a) digestate from manure/ slurry)

for all plants taking ABP wastes, Animal Health approval is required when digesting ABP wastes, compliance with the ABP regulations

When burning the biogas, the rated thermal input refers to the net calorific value of biogas, which typically is 5.83 kWh/m³ [EA, 2008]. Application of specified wastes (which include digestate) to agricultural land for agricultural benefit at a rate of up to 250 t/(ha*a) is exempt from licensing under Para 7 schedule 3 of EP Regulations. This 22


exemption needs to be registered annually and various restrictions apply such as the proximity of spreading to watercourses and wells. There is normally a registration fee, but agricultural wastes are free. There is a simplified registration process (free) to spread digestate produced solely from manure/ slurry (or mixtures of energy crops with manure/ slurry) at up to 50 t/(ha*a) for agricultural benefit (Para 12 Exemptions for the AD plant, Whole Farm Approach). To spread between 50 and 250 t/(ha*a) of digestate solely from manure/ slurry (or energy crops with manure/ slurry), registration is still free, but additional information and evidence of the agricultural benefit must be provided. In case of up to 250 t/(ha*a) of digestate produced from manure/ slurry with other non-agricultural wastes, similar information and evidence together with a registration fee are requested [EA, 2008].

3.4 Digestate Standard PAS 110 and Protocol The purpose of the Digestate Standard PAS 110 and Protocol, currently under preparation, is to remove a major barrier to the development of AD by encouraging markets for the digested materials. It creates an industry specification against which producers can verify that the digested materials are of consistent quality and fit for purpose. The underlying principle is that only source separated biodegradable materials can be accepted within the scheme; this reduces the laboratory testing regime to a manageable level and for example greatly reduces the risk of the presence of a wide range of harmful organic compounds. There is a PAS 100 which is a compost standard. The Digestate Standard PAS 110 is called ‘Specification for whole digestate, separated liquor and separated fibre derived from the anaerobic digestion of source-segregated biodegradable materials’ and is now in the final stages of preparation. Once it is complete it will be the standard against which a certifying body will inspect the production of digestate at biogas plants. A Quality Protocol has been written and is now open to consultation. It has the following three main purposes:

clarify the point at which waste regulatory controls are no longer required

provide users with confidence that the digestate materials they purchase conform with an approved standard

protect the environment (including soil) and human health by describing acceptable best practice for the use of quality digestates in agriculture, forestry (excluding horticulture other than soilgrown horticulture) and in land restoration

The Renewable Energy Association will be running the Scheme Rules for the Standard and Protocol. Biogas plants which successfully pass the PAS 110 and Protocol will no longer be subject to Environment Permitting Regulations, since the digestate will cease to be waste and instead be classed as a product. This will have two main benefits, firstly removing the need to make applications to the Environment Agency, which at present is expensive, time consuming and inflexible, and secondly to remove the “waste” tag from the digestate. This will overcome resistance from retailers and some quality labels which are very sensitive to the nature of any soil additives that may cause concern to the public or to food buyers.

23


3.5 NVZs and the Effect on Biogas Plant Planning Around 60% of nitrate and 25% of phosphates in English waters originate from agricultural land. High levels of these nutrients are of concern because they can cause eutrophication, which harms the water environment, and excess nitrate has to be removed before water can be supplied to consumers. Agriculture contributes between 25 – 50% of the pathogen loadings which affects England’s bathing waters. Up to 75% of sediment input into rivers can be attributed to agriculture. This reduces water clarity and causes serious problems for fish, plants and insects. Pesticides are contaminating drinking water sources, requiring expensive treatment at water works to remove pesticides before it is supplied to consumers. A total of 55% of England was designated as a Nitrate Vulnerable Zone (NVZ) in October 2002 (this includes the 8% originally designated in 1996). A recent review of NVZs is likely to result in an increase in coverage to about 70% of England. Maps of the revised NVZs proposed for designation in 2008 are available from Defra, covering Cornwall in detail. A farm that is within an NVZ has to implement an Action Programme with the following measures [Defra, 2002a]:

Limit inorganic nitrogen fertiliser application to current crop requirements, after taking into account the results of soil tests. The rules for NVZs set a limit for organic manure (nitrogen) loadings of 250 kg/(ha*a) of total N on grassland, and 210 kg/(ha*a) N on land in non-grass crops, averaged over all agricultural land within the NVZ. The loading limit for land in non-grass crops in NVZs reduces to 170 kg/(ha*a) N after the first four years of the Action Programme.

These limits include manure deposited by grazing animals and N in imported organic materials, and they are based on the period 19 Dec to 18 Dec in the following year. The amount of N produced as livestock excreta varies according to the number and type of livestock on the farm.

No individual field should receive organic manure applications (which excludes manure deposited by grazing animals) which supply more than 250 kg/ha of total N in any 12 month period, or supply available N in excess of the crop requirement.

On sandy or shallow soils the NVZ Action Programme imposes a closed period of 3 months (1 Aug to 1 Nov) when no slurry, poultry manures or liquid digested sewage sludge may be applied to land which is not in grass nor to be sown with an autumn sown crop. The closed period for land in grass or to be sown with an autumn sown crop is 1 Sept to 1 Nov. These closed periods do not apply to FYM (straw-based manures) or other forms of sewage sludge or other organic materials.

Farm records must be kept, including cropping, livestock numbers and the use of organic manures including digestates and nitrogen fertilisers.

The Action Programme under the Nitrates Directive is also a Statutory Management Requirement (SMR) for cross compliance under the Single Payment Scheme. This means that the farmers have to comply with the Action Programme measures to be entitled to their full subsidy payment; failure to comply could lead to deductions.

Manure cannot be applied in the following conditions: waterlogged or frozen or snow covered land, steeply sloping fields, within 10 m of watercourses, and during the closed autumn period (sufficient capacity for the cattle slurry to be stored must be provided).

The biogas plant operator should identify the actual land areas onto which the digestate is to be applied as part of the feasibility study and business plan. It must be determined if land is in an existing or new NVZ area. To determine the N content of the soil, soil tests should be conducted or obtained. 24


Moreover, the N content of animal slurries on the land less the amounts of slurry diverted to the biogas plant should be calculated. Based on the expected digestate nutrient content and the maximum allowed fertiliser application, the land area required for digestate spreading can be calculated. If there is not enough land for spreading the digestate on the own farm, nearby farms should be contacted which may be interested in taking the digestate. Since digestate spreading is largely seasonal, there will have to be an adequate storage for the digestate to cover those times of the year when spreading is not allowed.

3.6 Digestion of Sewage Sludge (Biosolids) with other Feedstock Sewage Sludge can be co-digested with other feedstocks, and spread to farmland, however, the regulations which apply to each feedstock are different and must both be followed. While the Environmental Permitting scheme (Chapter 3.3) must be followed for other materials such as food waste or agricultural manures, other regulations affect sewage sludge. The key UK legislation on Sewage Sludge, also known as Biosolids, derives from two European Directives:

The Sewage Sludge Directive (86/278/EEC) (for more information see: http://ec.europa.eu/environment/waste/sludge/index.htm): The EU Directive was implemented in the UK primarily by the ‘Sludge (Use in Agriculture) Regulations 1989’ (see Chapter 3.6.1).

The Water Framework Directive (2000/60/EC) (for more information see: http://www.environment-agency.gov.uk/subjects/waterquality/955573/): It came into force in December 2000 and was transposed into UK law by December 2003.

The Water Framework Directive (WFD) applies to surface freshwater bodies, groundwater, groundwater dependant ecosystems, estuaries and coastal waters. Its implementation will update the current water legislation and will replace a number of existing EU Directives by the end of 2013 at the latest. The WFD is the largest and most significant piece of EU water policy to be developed for at least 20 years [EA, 2003]. One of the key issues of the Directive is the control of diverse sources of diffuse pollution and the implementation will also address practices in land management and farming. Spreading of sewage sludge to farmland is one source of diffuse pollution.

3.6.1

The Sludge (Use in Agriculture) Regulations 1989

The Sludge (Use in Agriculture) Regulations 1989 (together with the Sludge (Use in Agriculture) (Amendment) Regulations 1990) permits the use of sludge on agricultural land, if certain conditions are met. These include:

Testing the sludge

Testing the soil on which the spreading takes place

Limiting the amounts to be spread

Not to be spread on fruit or vegetable crops within 10 months of application

3 weeks before grazing animals allowed on land

Rules concerning injection to soil 25


In addition, detailed information has to be recorded concerning where the sludge is applied and a register kept of operations. The Regulations are available via the websites below. http://www.opsi.gov.uk/si/si1989/Uksi_19891263_en_1.htm http://www.opsi.gov.uk/si/si1990/uksi_19900880_en_1.htm

3.6.2

Code of Practice for Agriculture Use of Sewage Sludge

The Code of Practice for Agricultural Use of Sewage Sludge provides the detail of how the sludge can be used on farmland. The Code can be downloaded from the Defra website using the link below. http://www.defra.gov.uk/environment/water/quality/sewage/sludge-report.pdf The Code also explains possible risks related to spreading of sewage sludge to agricultural land and lists different sludge treatment methods which are classified to be effective. Composting and anaerobic digestion are possible options if certain criteria are guaranteed. Table 3-5 lists effective methods for sewage sludge treatment using anaerobic digestion. It can be seen that the treatment methods are different from ABP Regulations for food waste. Table 3-5

Examples of Effective Sewage Sludge Treatment using AD

Process type Sludge Pasteurisation Mesophilic Anaerobic Digestion Thermophilic Anaerobic Digestion

3.6.3

Treatment Minimum of 30 minutes at 70°C or minimum of 4 hours at 55°C (or appropriate intermediate conditions), followed in all cases by primary mesophilic anaerobic digestion. Mean retention period of at least 12 days primary digestion in temperature range 35°C ± 3°C or of at least 20 days primary digestion in temperature 25°C ± 3°C followed in each case by a secondary stage which provides a mean retention period of at least 14 days. Mean retention period of at least 7 days digestion. All sludge to be subject to a minimum of 55°C for a period of at least 4 hours.

The Safe Sludge Matrix (ADAS Matrix)

The ‘Safe Sludge Matrix’ is an agreement between Water UK, representing 14 UK Water and Sewage Operators, and the British Retail Consortium (BRC) representing the major retailers. The agreement affects all applications of sewage sludge to agricultural land and came into force on 31st December 1998. The provisions of the agreement were supposed to be incorporated into legislation in the Sludge (Use in Agriculture) Regulations and in the Code of Practice for Agricultural Use of Sewage Sludge; but this has never been completed. Hence there is no regulatory recognition of the Matrix; it is a voluntary agreement. The ‘Safe Sludge Matrix’, commonly referred to as the ADAS Matrix [Adas, 2001], forms the basis of the agreement and consists of a table of crop types, together with clear guidance on the minimum acceptable level of treatment for sludge based products which may be applied to that crop or rotation. The guidelines can be downloaded using the link below. http://www.adas.co.uk/media_files/Publications/SSM.pdf 26


4 Biogas and Digestate Utilisation Anaerobic digestion creates two main types of output: biogas which is rich in energy and digestate which is rich in nutrients but may also contain harmful substances. If the digestate can be spread to land, its fertiliser value adds a benefit to the AD installations. Digestate which cannot be spread to land, especially when contaminated with harmful components, must be disposed of, which implies additional costs. Biogas from on-farm AD can be converted to useful energy in different ways:

gas boiler for use of heat on site

electricity export to grid and local heat via CHP on site (or pipe to remote CHP)

vehicle use or injection to the gas grid after cleaning the biogas to methane

Landfill gas is mostly converted to electricity alone. While there is no significant heat demand at landfill sites, AD reactors require heat input and combined heat and power generation is the more favourable option compared to electricity generation alone. The efficiency of CHP units at electricity generation is almost at the level of conventional generators and their overall efficiency degree is higher due to the co-generation of heat energy which is at least partially used.

4.1 Electricity Generation 4.1.1

Renewable Obligation Certificates (ROCs)

Under the Renewables Obligation (RO) policy, companies that supply electricity are obliged to annually increase the proportion of electricity they source from renewable energy. The target rises annually – for 1 April 2008 to 31 March 2009 it is 9.1% and it was 7.9% in the previous annual period (the RO’s year is 1 April to 31 March the next year). The current UK total electricity from renewable sources is about 5%. The RO policy is not actually an obligation to achieve the target levels, but to include the electricity supplying companies in a market orientated renewable energy scheme. For each renewable MWh of electricity, the supplier receives a certificate, a Renewables Obligation Certificate (ROC). Because the electricity suppliers cannot produce the required number of ROCs to the regulator they must pay a “buy-out” fee (Non-compliance Penalty) for every MWh they are short. For the non-compliance, the electricity supplier is penalised with a basic fee of £30 per MWh that is not supplied, index linked at 2002/03 RPI levels making a current buy-out fee of £35.76/MWh (3.576 p/kWh) in 2008/09. This buy-out is paid into a fund which then is distributed equally to every ROC registered by the administrator (OFGEM). The buy-out fund is distributed back to the electricity suppliers in proportion to the level of compliance under the RO. Recycling the buy-out fund back to those companies that hold the ROCs has two implications [Andersons, 2008]:

It makes the RO more compelling to companies, because whilst paying the buy-out per MWh might be cheaper option than investing in a renewable sector of the business, that money would be redistributed to competitors.

It also means that, as ROCs are tradable, the market value of ROCs is higher the further away the industry is from achieving the target for the year as a greater amount of buy-out fund is payable per certificate. 27


The value of ROCs is determined by the degree of shortfall in the supply of energy from renewables. When a licensed electricity supplier holds a ROC, it not only enables them to benefit from the buy-out fund, but also means the electricity supplier does not need to pay the Non-compliance Penalty into the fund for each ROC’s energy equivalent (1 MWh/ROC). Thus the trading value of the ROC is the NonCompliance Penalty (buy-out) per MWh missing electricity from renewables (2008/09: £35.76/MWh) plus the likely redistribution of buy-out fund per ROC. In April 2008 a ROC sold for an average of £51.39, which is the highest for some years. In the last five years ROCs were traded on average values ranging approximately between £40 and £50. Seasonal variations occur, and ROC banking (carrying ROCs over from one year to another) and other trading risks also impact their value. To obtain ROCs, licensed electricity suppliers can either generate renewable energy themselves or contract other companies to generate it on their behalves. Another option is to purchase ROCs either from another company that has exceeded its RO target or from a renewable energy generator such as a farm that does not have an obligation at all. ROCs are tradable independent to the electricity they were awarded for and an electricity supplier can buy ROCs from a farm or another renewable energy producer also if they do not buy the electricity. Farms are not obliged to generate any electricity from renewable sources, and consequently they do not have to pay any Non-compliance Penalties (buy-out fees) into the RO fund. They will therefore probably achieve higher benefits from selling their ROCs than waiting for the redistribution dividend from the buy-out fund [Andersons, 2008]. ROCs can either be sold directly to electricity providers or they can be auctioned online [e-roc, 2008]. Renewable electricity generating stations including biogas plants with electricity production are accredited for the Renewables Obligation by OFGEM individually and a unique accreditation identification number is issued. In order to be accredited an approved electricity meter needs to be installed. Before April 2007, renewable electricity had to be sold to the Power Grid via the local electricity supply company in order to be able to claim ROCs. Electricity needed on-site had then to be re-bought from the electricity supplier. This is no longer necessary, an OFGEM approved meter at the point of electricity generation is sufficient. An AD plant is now able to still claim ROCs for produced electricity which is not send to the grid but which is directly used, and a small AD plant can receive ROCs even if it has no exporting grid connection at all.

4.1.2

Double ROCs for Biogas

The Energy Bill 2007 – 2008 contains the legislative provisions required to implement UK energy policy following the publication of the Energy Review 2006 and the Energy White Paper 2007. The Bill is at present going through the Committee Stages of the House of Commons and House of Lords. In the Bill 2 x Renewable Obligation Certificates are available per MWh of electricity generated from combustion of biogas (from April 2009 on). This is only for plants operational after 11 July 2006. The government will examine support for biogas plants again in 2013, but this is not expected to affect conditions for plants already approved by OFGEM, only new ones. Confirmation of the double ROCs concept is awaited in autumn 2008.

28


4.1.3

Climate Change Levy Exemption Certificates (LECs)

Non-domestic customers have been required since April 2001 to pay a Climate Change Levy (CCL). The CCL is currently £4.56/MWh electricity for the year from 1 April 2008 and is index linked. All electricity generated from eligible renewable sources has been exempt. Climate Change Levy Exemption Certificates (LECs) are issued to certified renewable electricity generators. If this electricity is then used by a non-domestic customer, it negates the Climate Change Levy [Andersons, 2008]. AD operators can register for the LECs so that their customers can claim the Levy exemption. As a consequence, LECs will generate a higher electricity sales price. Unlike ROCs, LECs are not directly tradable independently from the electricity they were issued for and they only generate a benefit when the electricity is sold to a customer which is required to pay CCL. LECs are only used to identify electricity that is Levy exempt. One LEC is issued per each MWh of electricity generated from eligible renewable sources.

4.1.4

Embedded Benefits and Triads

Selling electricity to the grid from a rural location could have additional financial benefits above the negotiated basic electricity price (‘Embedded Benefits’). Moving electricity along a metal wire is not one hundred percent efficient. The further away the wire travels from power station, the more electricity is lost from the grid. Thus, an AD site selling electricity to the grid in a location near the end of the grid reduces the requirement for moving electricity over this long distance and therefore also reduces distribution losses. On average, this could be worth up to 0.5 p/kWh [Andersons, 2008]. In Cornwall, AD plants situated at far ends of the grid could particularly take advantage from the possibility of Embedded Benefits if they sell their electricity to a licensed electricity supplier. So called Triad benefits are also a possible type of embedded benefits. Triads are related to the process which is applied to cover the costs of the National Grid. The National Grid is the high-voltage electric power transmission network in Great Britain, connecting power stations and major substations and ensuring that electricity generated anywhere in Great Britain can be used to satisfy demand elsewhere. Licensed electricity suppliers (BGB, Powergen, EDF Energy etc.) are charged for using the National Grid. An electricity generator does not need to be a ‘licensed electricity generator’ unless selling more than 50 MW or have capacity of 100 MW, far bigger than any AD operation [Andersons, 2008]. Agricultural digestion plants are not connected to the high-voltage network of the National Grid but to the low or medium voltage distribution network operated by the DNO (Distribution Network Operator), see Chapter 5. There will be no costs for agricultural AD plants to be settled with the National Grid (but they will be charged by the DNO, see Chapter 5). The following explains how the embedded small electricity generator can profit from the triad system of the National Grid. In April of each year, each licensed electricity supplier is charged a fee which is based on the load it imposed on the National Grid during the three peak half hours of the previous winter. These three half hours of peak demand are usually referred to as the Triads. The ‘Triad Demand’ is the average demand on the system over the three peak half hours between November and February (inclusive) in a financial year. These three half hours comprise the half hour of system demand peak and the two other half hours of highest system demand which are separated from system demand peak and each other by at least ten days. The charge is calculated in retrospect, by looking back over each of the 17,520 half hours and locating the three peak half hours. After identification of the triad period half hours, each of

29


the energy supply companies is then charged according to their average peak loads in MW on the National Grid system during those three half hour periods. The average triad charge (whole country) is about £15,000/MW per year. Theoretically, if averaged over all power supplied in the UK in one year the charge is around 0.2 p/kWh (total annual triad charges of £15,000/(MW*a) x 50 GW = £750 million divided by total number of units sold of around 3.6 trillion kWh) [Wikipedia, 2008]. However, the way the National Grid is paid for is by means of a capacity charge, i.e. a charge on kW not kWh. Therefore, triad avoidance is a revenue earning opportunity for small electricity generators by reducing a site’s peak demand at National Grid peak periods (Triad periods). There are no triad charges for the biogas plant. Reducing a site’s peak demand means lowering triad charges for the licensed electricity supplier, who might therefore pay a triad benefit (a proportion of the total triad avoidance) to the embedded generator. Exact triad charges vary depending on the distance from the centre of the network. At the extremity of the system, the Western Power Distribution area in the South West, the total annual transmission cost is about £21,000 per MW per year (which is much higher than the average triad charge of the country), again charged to supply companies at the average of their loads at the three Triad half hours. So, if the load was cut by 1 MW or a 1 MW generator was started running during those periods, the electricity supply company saved £21,000 [Wikipedia, 2008]. Triad charge avoidance is only possible to that extent to which the electricity consumption is reduced exactly during the triad periods. One estimate is that at least 500 MW of load are shifted by reduced electricity consumption of large consumers during the anticipated triad times [Turvey, 2003]. Small embedded electricity generators actually generating power during the triad times reduce the triad charge of the licensed electricity supplyer. According to Foster [2007] (SmartestEnergy), the triad benefit paid to the embedded generator is usually 80% of the total triad benefit of the licensed electricity supplier. Based on the 2007/08 triad charge for the South West (£23.7/kW [SmartestEnergy, 2008]), the benefit for a Cornish biogas plant with 100 kW output during the triad periods would be around £1,895 (which is around 0.22 p/kWh if the biogas plant ran on this output the whole year). Embedded benefits (including triad benefits) typically add around 0.1 – 0.2 p/kWh to the revenue stream of an embedded electricity generator [Foster, 2007], and as described above the benefits for a generator in the South West can be higher.

4.1.5

Electricity Sales

In the UK there is no guaranteed price for electricity from renewable energy. The electricity sales price is in principle the result of negotiations between the electricity producer and the electricity buyer. When selling the generated electricity to a licensed electricity supplier, the electricity production site is priced on its shape against the electricity market price. The power purchase agreement comprises different elements:

the wholesale electricity price, based on the basic export electricity price, embedded benefits, a margin and a provision for imbalance (non-delivery)

the LECs (see Chapter 4.1.3)

the Renewable Energy Guarantee of Origin

details on the long or short term contract

30


Since LECs are not tradable independently from the electricity they were issued for, their value will usually be part of the wholesale electricity price. The Renewable Energy Guarantee of Origin (REGO) is one element of power purchase agreements, but REGOs have no price. REGOs certify that the electricity was in fact generated from renewable sources. They are not transferable or tradable but provide authorisation of renewable credentials. REGOs are issued by OFGEM in Great Britain but they are a pan-European label [Ofgem, 2008]. The main types of power purchase agreements are short term and long term contracts. Long term contracts can be commitments for longer periods (several years) with fixed electricity prices for some years or with a guaranteed minimum electricity price and the actual price agreed annually and in general indexed against current electricity values. Short term contracts may achieve higher revenues but also include higher risks and more continuing negotiation efforts, whereas long term contracts provide more security and also are more advantageous when negotiating the financing conditions with the bank. They are therefore in general to be recommended. Depending on contract details, electricity sold to the grid is likely to currently sell for about 5 – 6 p/kWh [Andersons, 2008]. In addition, there is the revenue from the trading of ROCs, see Chapter 4.1.1. With a value of £40 to £50 per ROC (= 4 – 5 p/kWh), the total revenue package for the sold electricity is around 9 – 11 p/kWh, and with the Double ROCs (see Chapter 4.1.2) 13 – 16 p/kWh (from 1 April 2009 on). While LECs cannot be traded independently from the electricity they were issued for, this is possible with the ROCs (see Chapter 4.1.1). However, some supply contracts foresee to bind the electricity sales with the sales of LECs and ROCs at the same time. This might return the AD plant operator a slightly lower value for the ROCs because they will be sold before the ROC year-end, so the electricity company will include a risk and margin factor, but this could make the process of electricity and certificate sales very straight forward [Andersons, 2008]. Retail electricity prices are higher than the wholesale electricity price. Therefore, a higher return per kWh can be possible when selling electricity to a consumer nearby and supplying him via a private wire, laid from the generator to the consumer. The wholesale price to the neighbouring consumer must be lower than the retail price from the grid to provide a real incentive and a basis for laying the private wire. Prior to deciding in favour of laying a private wire, the electricity generator should carefully assess the wholesale electricity price which the licensed electricity supplier would be willing to pay, including embedded benefits (triad and other benefits) and the LECs value; especially at far ends of the grid the price could be attractive. LECs generate a benefit only if the electricity is sold to a buyer who is required to pay CCL. Concerning the issue of ROCs for the generated electricity, there is no difference between electricity sold to the grid and electricity consumed directly. Since 2007, an AD plant can claim ROCs also for electricity consumed on site, not only for electricity supplied to the grid (see Chapter 4.1.1), while previously the meter had to be installed where the electricity was sent to the grid.

4.2 Combined Heat and Power With a Combined Heat and Power Plant (CHP), heat and electricity are generated simultaneously in a single process. A CHP itself is already an environmentally friendly technology and fuelling it with 31


biogas makes the technology even more environmentally favourable. When using gas, the gas is burned in a combustion chamber. This produces a flow of hot air, which drives one or more prime movers. A generator converts this rotational energy into electricity. A CHP unit is particularly suitable at an AD plant, since some of the generated heat can be directly used to maintain the digester temperature. Exhaust heat can be pumped out through insulated pipes, to provide space and water heating for local buildings. Sometimes cooling is also produced (‘trigeneration': electricity, heating and cooling). Here, some of the heat drives absorption chillers producing cold air for air conditioning (used e.g. for local buildings or pig units in hot summers). The exhaust heat of the CHP unit is low grade energy, and the energy content is not enough to achieve low temperatures which would be required for example for cold stores (< 8°C or lower). However, new technologies are currently under research and development in Germany and elsewhere. Heat which cannot be used must be dissipated. Only heat which is used by consumers (others than the AD plant itself) has an economic value for the AD plant operator, as it has the potential to replace other ways of heating such as heating with oil or natural gas. CHPs are based on gas or dual fuel engines. With the last, it must be considered that additionally to the biogas a specific amount of ignition oil is needed, in order to ignite the gas. This must be taken into account as additional cost factor. However, dual fuel engines can be operated in case of a breakdown of the biogas supply with pure ignition oil, in order to prevent operational failures of the biogas plant.

4.3 Heating with Biogas Combustion of biogas for heating purposes (without electricity generation) is done at some very small plants in Europe and elsewhere. Generation of heat alone will most likely not be the most favourable option for biogas utilisation in Cornwall. Even a relatively small plant is likely to generate more than most farm-sites would require [Andersons, 2008]. 1 m³ biogas with a methane content of 55% has the energy content of 0.55 litres oil. Production of heat alone will not enable the biogas plant operator to profit from the ROCs system. Especially the 2 x ROCs concept makes electricity generation far more attractive than heat production alone. When derived from a CHP unit, any utilisation of the waste heat is beneficial for the economic viability of the AD installation. Replacement of other heating systems such as heating with oil or electric heating saves costs and also is beneficial for the environment.

4.4 Biogas as a Road Fuel and Gas Injection into the Gas Grid For use as either a vehicle fuel or for injection into the network the biogas has to be cleaned and upgraded.

Cleaning involves removing water, hydrogen sulphide, silicon compounds (siloxanes) and any other trace components such as halogenated hydrocarbons. 32


Upgrading involves removing the carbon dioxide to enhance the calorific value of the fuel. The principal processes for upgrading biogas are: Gas scrubbing, Adsorption, Membrane Process and CO2 – liquefaction.

In the UK, no policy is available for renewable gas yet, making it less profitable than electricity generation [Andersons, 2008]. Injection of upgraded biogas into the mains gas grid is in principle an environmentally favourable option. It ensures that the captured biogas energy is highly preserved and finally used, whereas electricity generation and other biogas utilisation options might have a more limited efficiency degree. However, injection into the gas grid is only reasonable for larger AD facilities. It requires assurance of certain standards and only larger scales justify investment in the necessary technology. Injection of upgraded biogas into the gas grid is for example done at some large-scale AD plants in Germany. For Gas Network Entry, the Calorific Value (CV) of the gas will require enhancement to meet the necessary CV and odorisation to impart the normal smell. Enrichment would normally be carried out by the addition of Propane. A typical biomethane enriched to meet a network CV target of 38 MJ/m³ (for example) will be as follows:

CH4

=

93.2%

CO2

=

1.94%

O2

=

0.78%

N2

=

1.16%

C3H8

=

2.92%

Biogas treatment and upgrading for vehicle use has been carried out in Europe, particularly Sweden and Switzerland since 1992 in capacity sizes ranging between 10 m³N/h and 1,400 m³N/h. In general, the availability of plants is reported to be greater than 95%. The majority of plants are either Pressure Swing Adsorption (PSA) or Water Wash with few gas scrubbing plants using either Selexol or Amine. The costs in Table 4-1 and Table 4-2 apply principally to PSA and water wash systems, however it is not clear whether they include provision for gas clean up (in the case of PSA) as well as upgrading or whether there has been provision for compressing the biomethane to the final pressure requirement. The costs are based on information and literature provided by the companies and are purely indicative. The costs of PSA and Water Wash are comparable in terms of both capital and operating costs, but PSA systems are reported to have lower operating costs for the smaller units. In general, unit costs are higher for small plants (< 200 m³N/h). Table 4-1

Capital Costs for Biogas Upgrading (indicative)

Capacity m³N/h 25 100 1000

GTS 329.0 412.0 827.5

Capital Costs - £1,000 per year Malmberg BioGast Questair N/A 282.5 N/A 675.35 531.35 386.5 1,185.00 1,478.00 1066.0

Average Costs Not available < 365.0 1,250.0

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Table 4-2

Running Costs for Biogas Upgrading (indicative)

Electrical Power Operation & Maintenance Filter Media Filter Regeneration Totals

GTS 12.44 8.00 ? ? 20.44

Running Costs - £1,000 per year Malmberg BioGas Questair 12.08 2.76? 13.0 11.6 10.0 8.0 1.44 1.44 ? 4.00 4.00 ? 29.12 18.20 21.0 +?

Average Costs 12.6 8.5 1.44 4.00 26.54

In the UK the biogas industry has not developed enough to justify building the infrastructure for cleaning and distributing clean biomethane for vehicles. Therefore any development has been in the area of CNG vehicles, where natural gas from the Gas Grid is used. Once a network has been developed using CNG or LNG, then biomethane can be progressively introduced. There have been individual examples of cars converted to run on biogas, and others which have used local “garage” compressors from the gas grid to fuel cars and vans; however these are not likely to lead to any larger scale usage. Possible reasons why the UK has not developed include:

CNG network relatively undeveloped (Figure 4-1)

No duty on diesel fuel in buses – this makes it impossible to compete with diesel prices, which are the lowest in Europe – the EU is challenging this and this could result in the UK getting a passenger miles subsidy only

Road Transport Fuel Obligation includes biomethane but because there is no infrastructure, it is only helping liquid biofuels

Export to gas grid not developed

No standard for the quality of Biomethane

Lack of RHD (Right hand drive) CNG cars

Resistance to change

Figure 4-1

UK CNG Filling Stations

Only the Crewe filling station can fill cars and vans. A new filling station has also been recently announced by Organic Power in Wincanton, Somerset, and the company is also running several biomethane vehicles. 34


Tesco has been trialling the RHD Econic CNG vehicle in London, which is a significant development for NGVs in UK given Tesco market power:

Fuel saving of 10 p/km (33 cents per mile)

No congestion charge (£8/day saving)

50% of noise of diesel and can run 24 hours so need 30-40% less vehicles compared to diesel

Tesco depot located next to CNG Services station in Crewe – interested in Sprinter

Also trialling the Clean Air Power – 380 bhp Mercedes Axor (Euro 3), dual fuel showed clear benefits despite conversion cost of $36,000 for CNG:

Saving of around $20,000 per vehicle per year

Reduction of around 20 tonnes of carbon per vehicle per year

Some UK utilities have become interested in using the Mercedes Benz Sprinter CNG including the National Grid, Water companies and Electric utilities. The vehicle is for the German market, with very low emissions “EEV” standard, 25% less CO2 than petrol; with an included small petrol tank it has a total range of 1100 km. The Hardstaff Group is the most progressive development company in the UK in the field of CNG vehicles. Designed for use with both compressed natural gas (CNG) and liquefied natural gas (LNG) Hardstaff has it’s own patented OIGI (Oil Ignition Gas Injection) dual fuel technology which meets the highest emission standards, whilst maintaining maximum fuel economy and cost savings. OIGI® technologies can be adapted to passenger cars, light and heavy good vehicles, buses and coaches, refuse vehicles and locomotives. The Hardstaff OIGI® is a dual fuel system developed to substitute natural gas for diesel in light and heavy duty engines. The natural gas injection system is electronically controlled and can cater for multi-point, mono point and sequential port injection, providing a greater range of applications for the majority of brands of truck and bus available. A separate electronic control unit (ECU) is used for the natural gas fuel, providing a full closed loop feedback system that monitors existing variables alongside the diesel electronic control unit (ECU) and controls the gas injection based on the feedback from the various engine sensors. The sensors include boost pressure, lambda sensor signal, pedal deflection, coolant temperature, gas temperature and pressure, and many more inputs. Diesel is required as the ignition source in dual fuel engines. With the OIGI® system the engine will use 100% diesel at idle; gas injection and diesel reduction commences when engine speed increases from idle. Precise control of diesel reduction and gas injection quantities ensures efficient fuel use and performance equivalent to the original diesel engine. Currently the following RHD vehicles are available (with manual gearbox):

Volvo FH12

DAF 55, DAF 65, DAF 85

Vehicles with Caterpillar C12 engine

Mercedes Benz Axor

35


4.5 Utilisation of Digestates A potential income from digestate is linked to the displacement of other fertilisers. Therefore, a current fertiliser application summary should be prepared, which may look like Table 4-3. Based on the digestate nutrient content the amount of replaced fertiliser can be calculated. Special attention should be paid to the fact that all nutrients must be regarded in the same chemical form when different materials are compared; e.g. K is sometimes given as total K, K2O, K2SO4 or KCl and failure to be aware of the different actual contents of the target nutrient results in an inaccurate material balance and pricing. Table 4-3

Example of fertiliser application summary (potential for replacement of fertiliser by digestate)

product t/ha total N kg/ha total P2O5 kg/ha total K2O kg/ha total MgO kg/ha total SO3 kg/ha organic matter t/ha

NVZ 170 kg N 21 170 65 193 47 112 6

NVZ 250 kg N 31 250 96 283 70 165 9

Non-NVZ 63 500* 192 566 139 330 17

* COGAP recommends this level only if very little available N. Normally the limit would be 250 kg/ha.

However, it needs to be taken into account that any nutrients in the digestate originating from slurry or manure are not to be considered as direct mineral fertiliser replacement if the slurry/ manure was already used as organic fertiliser on the farm before AD was installed (those nutrients are returned to the soil whether the slurry/ manure passes the biogas plant or not). Only digestate nutrients from additional substrates can be considered as direct replacement of mineral fertiliser. However, digested slurries/ manures to some extent have an improved fertiliser value since nutrients are better available after the AD process. Compared to granular fertiliser, digestate has the drawback that it is a pre-determined blend and its constituents cannot be altered. Once the soil requirement of the first nutrient has been met, then no more should be applied to the soil. Other fertiliser is therefore likely to be required to top up the nutrient needs of the soil. When applying the digestate to farm land, a genuine plant benefit needs to be demonstrated. If the digestate is of high P or K for example and the soil analysis suggests the additional application of the nutrient is not warranted, then it would be advisable not to apply in this area [Andersons, 2008]. Digestate which is not fit for landspreading must be disposed of. The biogas plant operator is the holder of this waste and has a Duty of Care to ensure that it is removed and disposed of in a controlled and licensed manner. Sending waste to a landfill site incurs a gate fee. One of the most far-reaching requirements of the EU Landfill Directive is to reduce the quantities of landfilled biodegradable waste to 75%, 50% and 35% of the amount produced in 1995 by 2010, 2013 and 2020 respectively. The UK landfill tax for those wastes rises each year. The landfill tax in the current year 2008/09 is £32 per tonne ‘active’ waste (the landfill tax year begins in April), and it will rise to £40 in 2009/10 and to £48 in 2010/11 [Andersons, 2008]. Many businesses are happy to pay a ‘gate fee’ equivalent to, or higher than landfill cost for disposal via AD. However, agricultural biogas plants should reject material containing plastics, metals or woody components. 36


5 Electrical Grid Connection in Cornwall 5.1 Regulatory Frameworks The EU Directive 2001/77/EC is the key directive in regards to renewable energy and the grid. In the context of implementation of the EU Directive, the UK achieves compliance with mandatory articles. However, relevant non-mandatory articles of the EU Directive are not implemented in the UK despite clear EU indications that these are highly desirable. In particular the ‘Priority Access for Renewable Energy’ is not provided. The UK does not implement a ‘Must Take’ policy either [Scott, 2007]. While other EU countries like Denmark, Germany, and Spain provide priority dispatch of renewable energy, the UK doesn’t. There is no special treatment of renewable energy projects within the current regulatory frameworks. Projects are not connected until the grid can provide guaranteed transmission access and this in general means long delays. Before connection, UK electricity generators must necessarily wait for complete grid reinforcement completion (if reinforcement is necessary, which will be assessed in a feasibility study for each individual case, see Chapter 5.3.2 for the connection procedure with Western Power Distribution in Cornwall). In many other European countries constraint is used whilst necessary reinforcements are being implemented, an element which is not available in the UK. The UK does offer guaranteed transmission and distribution of electricity sourced from renewable energy, but this is only when connected and hence after grid reinforcement completion. However, once the transmission can be guaranteed, the UK grid connection policy is very shallow compared to other European countries. The system operator provides all the reinforcement and extension works, some of the interconnecting connection assets and all the generator needs to do is ‘plug in’ [Scott, 2007]. While many other EU countries have no or very low tariffs for the on-going use of the system (and some countries exempt only renewable energy generators from the fees), the UK has high DUOS (Distribution Use of System tariffs) charges [Scott, 2007]. Costs vary significantly in different regions. Although UK grid practices were assessed to be in general fair, open, non-discriminatory and mostly transparent [Scott, 2007], the long delays for connection, the missing priority for renewable energy producers and high DUOS which make the system expensive are restrictive elements.

5.2 General Procedure and Costs Although an electricity producer itself, each rural biogas production facility equipped with a CHP unit needs to be connected to the power grid. Electricity export to the grid requires an adequate connection of the AD facility. If using the electricity on site without export to the grid, the biogas plant will in general generate enough electricity, but on some occasions such as during maintenance periods import of electricity from the grid will be necessary to cover the electricity demand. Compared to nonrenewable energy connections, there are no special requirements or conditions for renewable energy generators, the connection process will be the same. Depending on whether the generated electricity is used on site or is exported to the grid, the following connection options would be available: 37


Electricity Generation for own supply only without export option (non synchronized connection): This is used where the output of the generator is less than the normal electricity import of the site. A changeover panel is used, which isolates supply from the grid network whilst the generator is available, but re-connects to the grid in the case of a generator interruption.

Generation for own supply with export (synchronized connection): This is implemented when the electrical output of the generator is more than the lowest load taken by the site. When exporting electricity the output of the generator has to be synchronized to the frequency of the grid network.

Generation for export only (separate connection for export): When the entire electricity output is exported to the grid network, a new separate connection for export is required and a survey of the network to confirm that it can handle the increased energy flow. Additional reinforcement of the grid may be required, resulting in possible delays for the connection (see Chapter 5.1).

For a biogas plant, external connection to the grid will normally be to the low or medium voltage distribution network operated by the DNO (Distribution Network Operator) which in Cornwall is Western Power Distribution. The National Grid operates the high voltage transmission network, but a rural AD facility will not require connection to this. For generators up to 1000 kVA the distribution can in general be handled on the low voltage network (415 volts) but larger generators will need the medium voltage network (in general 11,000 volts). When changing the existing onsite network (at low voltage) there will be costs associated for network modifications and the changeover switch (indicative: £25/kVA) and annual costs (indicative £800/(1000 kVA*a)) for maintenance of the electrical equipment. Prior to establishing new connections to the grid network a network study is required to ensure that the new point of connection (POC) will not adversely affect the network due to reverse power flows. These studies may cost £1,000 – £5,000 and take about three months. Very small export < 50 kW would not normally require this service. Following the study a formal connection application would be made to the DNO. The actual cost for grid connection depends very much on local conditions. Some sites may be situated a long distance from any possible electricity network, whilst others may be adjacent or already connected. Amounts of £30,000 – £40,000 or higher are not unusual. In summary, when connecting electricity producing AD plants to the grid, the following cost elements are relevant:

Connection Cost: Depends on the distance from the generator and the point of connection (in addition there might be costs for reinforcement of the DNO network upstream of the connection). For example, cable trenching and reinstatement in open ground could be £20 per metre plus low voltage cable and joints at £15 per metre. Some of this work can be carried out by an independent connection provider.

Grid Reinforcement Costs: These are shared between the generator and the DNO according on OFGEM formula.

On-Going Use of System Costs: Distribution Use of System tariff (DUOS) charges are payable, which in the UK vary much between different regions.

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5.3 Connecting with Western Power Distribution (WPD) The following descriptions of the connection procedure to the WPD network are mainly taken from publications by the company [WPD, 2007a; 2007b; 2008].

5.3.1

Company Profile

Western Power Distribution (WPD) is the electricity distribution company for South West England and South and West Wales, two of the original Regional Electricity Company areas. WPD is no longer a retailer of electricity and does not get involved in either buying or selling of electricity to the end use customers, which is the responsibility of electricity supply companies. In the South West, South Western Electricity plc operated under the SWEB brand name until 30 September 1999. Following the sale of its retail supply business (including the SWEB brand name) on that date, the company became a regional electricity distribution business or Distribution Network Operator (DNO) and now operates under the name Western Power Distribution (South West) plc. In October 2000, WPD acquired Hyder plc, the Welsh multi-utility which owned the electricity distribution business serving South and West Wales. This resulted in the formation in the two licensed distribution businesses and in Wales the company operates under the name Western Power Distribution (South Wales) plc. As a distribution business WPD own the distribution system assets including 84,000 km of network and 90,000 transformers plus associated switchgear. WPD are responsible for:

maintaining the electricity network on a daily basis

repairing the electricity network when faults occur

reinforcing the electricity network to cope with changes in the pattern of demand

extending the electricity network to connect new customers

5.3.2

The Connection Process to Western Power Distribution’s Network

Sufficient time should be allocated to the development stages of a project as it can typically take several months from first contact with WPD to energisation of the connection. Large connections at 132,000 Volts may take more than 24 months to commission. WPD will need to carry out technical assessments before a generating unit can be connected to the network. The staged connection process for distributed generation is summarised as follows:

Stage I, Feasibility Study: Studies are carried out to determine the impact of the proposed generation on WPD’s existing network. An indicative budget estimate is given to the customer, which will be subject to further study and a number of conditions. The connection of distributed generation to the electricity network will, amongst other factors, affect the power flow, voltage profile and fault level within that network. The fault level can be viewed as the magnitude of energy, which will need to be interrupted by circuit breakers during a failure/fault on the electricity distribution system; generating plant normally increases the fault level in the electricity distribution system. The technical impact of the new generating unit is assessed during the early stages of a project’s development. In some cases, the impact of the new generator will be adverse

39


and require either reinforcement of the electricity network or operating/output constraints to be enforced at certain times of year or during abnormal network operating conditions.

Stage II, Formal Connection Offer: Based on a satisfactory outcome in stage I and on instruction from the customer, detailed design work is carried out to produce a connection charge and connection offer. Further technical studies including Stability Studies (for large connections, normally over 5MW) are completed as necessary. WPD start the process to obtain any necessary planning permissions and/or consents. For larger projects, WPD will make Tender and Contract applications for necessary plant, equipment and construction works.

Stage III, Project Completion & Commissioning: Following acceptance of the connection offer and subject to consents and planning permission, the project will proceed to completion and commissioning at agreed timescales. The customer has the option to carry out contestable work elements. It is possible that some small connections will not require any physical works to be carried out to WPD’s network.

For most small connections (typically below 500 kW), the process is normally condensed, with Stage I and II combined into one.

5.3.3

Planning Permission and Other Consents

The types of consents and permissions required for substations, overhead lines and underground cables necessary to make a connection can be summarised as follows:

Wayleaves/ Easements: Required from private landowners where an overhead line or underground cable is to cross his or her land. Underground cables laid in the public highway only require the consent of the Local Authority.

Local Authority Consent: Planning permission is required for new substations of a certain size. However, the substation required for the generator connection would normally be included in the planning application for the whole site. The Local and County Authority must be consulted on new overhead lines and they will make comment to BERR.

BERR Consent: Section 37 consent under the Electricity Act 1989 is required for most new overhead lines. The views of the local planning authority, local people and statutory bodies such as the Environment Agency, Countryside Agency and English Nature/ Countryside Council for Wales can be brought into the decision making.

Environmental Statement: This must be produced for new overhead lines with a voltage of 132,000 Volts or above and at lower voltages, if called for by BERR (this is rare however).

Substations and cables constructed in certain areas (e.g. an SSSI or close to a watercourse), will also require the consent of the Environment Agency and English Nature/ Countryside Council for Wales. Other bodies that may have to be consulted or may wish to provide comment (especially on overhead lines) include English Heritage/ Welsh Historic Monuments Executive Agency (CADW), Campaign to Protect Rural England/ Campaign for the Protection of Rural Wales, The County Archaeological Officer and local Wildlife Trusts. In addition, other regulations exist for large renewable energy generators (in general > 10 MW) but will in general not be relevant for anaerobic digestion facilities in rural Cornish areas; information can be obtained from WPD.

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5.3.4

Connection Costs with WPD

Recent changes to the regulatory framework have introduced a common approach of Western Power Distribution (WPD) for connection charges associated with both demand and generation connections. These are detailed in the Connections Charging Statements which may be downloaded from the ‘Information for Suppliers’ area of the WPD website, together with other relevant information and contact details (www.westernpower.co.uk). The recently reviewed documents in the ‘Information for Suppliers’ area of the WPD website include Statements of the Connection Charging Methodology and Statements of Charges for Use of WPD’s Electricity Distribution System. There are costs associated with the staged connection process outlined in Chapter 5.3.2, which will be charged to the customer. A fee for the initial Feasibility Study including any external costs to cover consultants for stability or other technical studies are payable prior to the work commencing. However, no advance payment is necessary for system studies up to 1 MW [WPD, 2007b]. The fee charged will in general depend on the size, type and location of the proposed generator. WPD’s time and resource costs beyond the Feasibility Study will normally be recovered in agreed stages in line with WPD’s expenditure. If the project does not proceed for whatever reason, the customer/developer will be asked to settle any abortive costs. The connection procedure includes contestable and non-contestable works, which allows the customers to carry out certain work elements before they are connected to the Distribution System.

5.3.5

Typical Connection Sizes and Connection Voltages

The connection voltage for a site can influence the cost of connection and in general the higher the voltage, the higher the cost and this is due to the general increase in size and insulation requirements of plant and equipment as the voltage increases. WPD’s network operates at the following three-phase voltages: 400 V, 11 kV (6.6 kV in some areas), 33 kV (66 kV in some areas) and 132 kV. As an approximate guide, the size of the generator connection and the likely connection voltage is set out in Table 5-1. However, there will be some overlap between the voltage boundaries and many site specific geographical and technical parameters can influence the connection voltage to be used. Occasionally in remote rural locations for example, it may be more feasible, both technically and financially, for a 3 MW installation to be connected at 33 kV, where normally one would expect this size of energy generation to be connected at 11 kV. Table 5-1

Typical WPD Connection Voltages for Renewable Energy Generators of different sizes

Generator size (3-phase) 0 – 0.25 MW 0 – 0.5 MW 0.25 – 4.0 MW 0.5 – 7.0 MW 4.0 – 20.0 MW 7.0 – 20.0 MW > 20.0 MW

Rural or urban location rural urban rural urban rural urban urban or rural

Typical connection voltage 400 V 400 V 11,000 V 11,000 V 33,000 V 33,000 V 132,000 V

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5.4 Documentation of Essential Reading for Prospective Generators Documents and contacts concerning the procedure of connecting a Cornish biogas plant to the electrical grid of Western Powers Distributions can be found on the company’s website [WPD, 2008]. The Distribution Code of Licensed Distribution Network Operators of England and Wales, Section DPC7, is particularly relevant for the connection of Embedded or Distributed Generation. The following documents contain relevant information [WPD, 2007a]:

Engineering Recommendation G59/1: Recommendations for the connection of embedded generating plant to the regional electricity companies’ distribution system

Engineering Recommendation G75/1: Recommendations for the connection of embedded generating plant to public distribution systems above 20 kV or with outputs over 5 MW

Engineering Recommendation G83/1: Recommendations for the connection of small scale embedded generators (up to 16 A per phase) in parallel with public low-voltage distribution networks

Engineering Technical Report 113: Notes of guidance for the protection of embedded generating sets up to 5 MW for operation in parallel with PES distribution systems

DTI Report K/EL/00318/REP: Technical guide to the connection of generation to the distribution network

G59/1, G75/1, G83/1 and ETR 113 can be purchased from the Energy Networks Association, 18 Stanhope Place, London, W2 2HH. Report K/EL/00318/REP is available via the DGCG’s (Distributed Generation Co-ordinating Group) website listed below. The ‘Reports and Publications’ section of the Department for Business Enterprise & Regulatory Reform (BERR) also contains a number of relevant documents on this topic and other aspects of renewable energy generation [BERR, 2008]. Useful websites include:

www.westernpower.co.uk

www.ofgem.gov.uk

www.energynetworks.org

www.berr.gov.uk/energy

www.distributed-generation.gov.uk (DGCG)

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6 Explanations to the Economic Modelling of this Study 6.1 General Layout and Selection of AD Technology The economic modelling is based on a range of rural scenarios. All studied sites are ‘real’ sites and the scenarios are based on the actual requirements of the individual locations. The sites were pre-selected by Cornwall Agri-food Council. In order to collect the basic data, a questionnaire was sent to all sites. Site visits were carried out and were followed by subsequent consultations where necessary. A number of pre-selected companies active in the UK biogas market were contacted. Offers were obtained for all studied scenarios. Calculations of the economic modelling therefore is based on current UK market prices (summer 2008). Only technology which is actually available in the UK is considered. Offers from companies were checked for completeness and technical suitability. While offers of some companies cover full costs and also indicate necessary earth works etc., other companies include costs for the actual plant components only. When comparing different offers, it was ensured that all relevant cost elements are included in the final prices. In cases where relevant cost elements were not included in one offer, those additional costs were added for comparisons. The economic modelling does not calculate with average market prices of all companies, but with the most favourable option, after assessing the technical suitability of a proposed digestion system and assuring the completeness of all associated costs. This report does not link the necessary investment costs of a scenario to the offering company. It is advisable for each interested potential biogas plant operator to directly contact different suppliers in order to receive individual and updated offers. Each of the presented designs could actually be built in the UK. This takes into account that the necessary equipment is not fully interchangeable between different plant types, and it is assumed that the key elements would be bought from one supplier. In general a future biogas plant operator would order one or several digesters equipped with full technology such as heating, stirrer, pumps, gas collection, control elements, and also after-digesters if necessary, from the same AD supplier. For the small scenarios, the economic modelling assumes some limited investment cost reduction compared to the companies’ offers, mainly by suggesting a simpler substrate pre-treatment. This assumes that the mixing pit with the necessary equipment can be regarded independently from other plant elements, thus not having to be built with the company that supplies the main AD facilities. Some of the scenarios suggest larger digesters than would actually be necessary to ensure a reliable AD process. This is because the larger option from one company was in effect less expensive than a smaller option, resulting in reduced overall costs. All suggested mixing pits are reinforced concrete tanks equipped with suitable agitator and pump. Solid feeders are manufactured of stainless steel. All digesters are vertical reinforced concrete tanks with insulation, equipped with air inflated roof as gas holder, and include all necessary agitators, instrumentation and sensors (temperature, gas level etc.). Main digesters are heated tanks equipped with heating circuit. After-digesters are in general non-heated and are equipped with gas holder roof as well.

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All scenarios include a minimum digestate storage capacity of 6 months (182 days). In most scenarios the daily amount of digestate is higher during the winter months than during the summer time, a result of the fact that dairy cows are kept free range for some months during the year. All technology design, including the storage capacity for 182 days, takes into account the higher slurry amounts during the time when animals are housed. With regard to the minimum storage capacity, the maximum amount of digestate in 182 days is calculated. With regard to biogas generation, it is suggested to equalize gas production throughout the year by digesting higher amounts of other substrates during the summer time when available slurry amounts are smaller. This in general results in smaller mass throughput during the summer, as substrates such as energy crops achieve higher gas yields compared to slurry. The different biogas utilisation options were described in Chapter 4. Heat production alone is not recommended. Upgrading the biogas to biomethane for injection into the grid is not suitable at site 1 to 7, as the size of the AD plants will not justify the necessary additional technology required. It might possibly be feasible at site 8 (the community based plant), but this would need to be studied in more detail which was not possible in the very limited time of 3.5 months of this project. Also biogas utilisation as a road fuel might possibly be an option for larger AD projects. However, the very limited infrastructure for biogas fuelled vehicles is a risk when considering this option. An operator of a farmscale AD plant should strive to set up a facility with the highest possible economic viability and limited risks. Electricity generation is recommended for all scenarios. It is highly probable that from April 2009 there will be 2 x ROCs available for electricity generated from biogas (see Chapter 4.1), which makes the option particularly attractive. Therefore, in this study it is assumed as a standard that biogas is converted to electricity and heat by utilisation of a CHP unit. Although quite often found in mainland Europe at small digestion plants, only one of the contacted companies offered a dual fuel engine with the CHP unit, but no economic advantage compared to a gas engine CHP could be identified. Therefore, all scenarios look at electricity generation based on a gas engine. With a gas engine, the total of electricity generated originates from renewable sources, while with dual fuel engines a part of the electricity would originate from the ignition fuel oil, and would rise the question if ROCs, LECs and other elements of the renewable energy policy could be claimed for all electricity generated or only for the part actually converted from biogas methane.

6.2 Assumptions for Calculations General assumptions of the economic modelling are compiled in Annex 11.2. Key aspects are discussed in the following.

6.2.1

Substrates, Biogas Yields, Digestate Nutrients

Where possible, substrate properties (DM, oDM content) are used according to data received from the studied sites; otherwise, and for biogas yields and digestate nutrients, standard figures from literature [FNR, 2005; KTBL, 2007] or figures based on IBBK’s experience are used for calculations. Figures are not listed here, but all key parameters are visible in the sheets of the economic modelling for each site. The most important figures are also given in the text of Chapter 7 (case studies). For dairy farms, it is assumed that liquid residues from milking parlours and foot bathes will be pumped away or by-passed (disinfectants should not affect biogas production). All manure considered

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as substrate for biogas plants is assumed to be free of antibiotics and of chlorine based disinfectants (according to the farmers’ information), and therefore will not affect the AD process negatively. In all scenarios where dairy cattle slurry is one of the substrates, at least some of the animals are kept free range during the warmer season. As a standard for dairy herds it is assumed that during the time when stock is free range 20% of that slurry amount which would be collected if all animals were housed is available for biogas generation (this assumes that dairy cows are in for milking for 20% of the day = 4.8 hours per day). If a scenario includes other assumptions, this is clearly indicated in the individual scenario (e.g. when no slurry is available from neighbouring farms during this time). The time for which the animals are kept free range varies at the sites. This time period is considered site-specific (not averaged) in the economic modelling. It is one key objective of this project to inform the farmer about the economic viability of a biogas plant based on the site-specific implications.

6.2.2

Costs and Income

The two major costs associated with a biogas plant are the initial investment costs (set-up of biogas plant, including planning costs, costs for approval, grid connection, etc.) and the ongoing costs (substrate costs, maintenance, insurance, labour costs, spreading of digestate, etc.). All assumed costs are visible in the individual scenario presentations and the most important costs are listed in Table 11-1 of the Annex or indicated in the following. Where it would be possible to integrate already available buildings into the AD concept, this is considered in the economic modelling. Costs for digestate storage are considered according to the requirements at each site. As with all other costs, full costs related to the AD unit are taken into account, assuming AD to be an option to the farm management without AD (AD scenario costs are compared to farm management without AD). Only adequate storage capacity on farm is taken into account, such as available lagoons. Slurry storage under the barn cannot be considered as digestate storage capacity. Labour costs are considered with £15 per hour and include only labour time related to the AD plant management. Depending on size and type of the AD plant, a necessary labour time between 4 and 5 hours per kW is assumed, according to average figures of German biogas plants. Labour for silage production or management of other feedstock is taken to be included in the substrate costs already. Costs for digestate spreading are considered separately. They are compared to the current costs for manure spreading, so that only costs caused by the AD unit are included in the economic modelling. In this study a standard price for substrates is assumed although the farmers indicated different individual prices. Assuming a standard price makes the calculations more comparable and also avoids the uncertainty that those individual calculations of site-specific prices may have included differing price elements, e.g. plant cultivation costs with or without fertiliser costs, costs for ensilage, material storage costs, and costs for any additional silage storage capacity or other material storage capacity which may be needed. Additionally needed substrate storage capacity is not part of the assumed basic substrate cost but is regarded separately (additional investment cost). Since the results of the economic modelling include a sensitivity analysis, the economic viability can be reliably assessed even if the individual site-specific substrate costs vary from the assumed standard substrate cost or if substrate costs will experience significant changes for example due to rising market prices for fertilisers. 45


Key substrate costs are listed in Table 6-1 (where possible based on Nix [2008]). There are no AD costs for manure/ slurry; those substrates are part of the general farm management. However, all additional costs resulting from the biogas plant operation, such as costs caused by additional transport of substrates, are priced. Table 6-1

Assumed Standard Substrate Costs for AD feedstock

Maize Silage Grass Silage Crop Grain (Wheat) Whole Crop Cereal Silage (Wheat) Straw Manure, Slurry

Costs (£/t) 25.0 22.5 105.0 32.0 50.0 0.0

takes straw shortage in the south west into account but any additional costs caused by AD are considered

On the income side, the economic modelling takes into account revenues from four sources at the anaerobic digestion facility:

sales of electricity

utilisation of excess heat from the CHP unit

fertiliser value of the digestate

gate fees for the treatment of wastes (if any)

It is assumed that the AD facility is connected to the electrical grid and that all electricity generated is fed into the grid (aside from the AD plant’s own electricity consumption and transformation and feedin losses). Based on Chapter 4.1 (in particular Chapter 4.1.5), the total revenue per kWh electricity supplied to the grid is assumed with 14.5 p, consisting of the following two key elements:

wholesale electricity price (including embedded benefits, triad benefits, LECs): 5.5 p/kWh

2 x ROCs at 4.5 p/kWh: 9.0 p/kWh

Since the economic modelling also includes a sensitivity analysis, it will be able to assess the economic viability of the biogas plant for the case that electricity usage on site was favoured (higher electricity sales price possible), in case of lower or higher wholesale electricity price or in case of a lower or higher ROCs value. Assessment of the utilisation of heat from the biogas plant includes an analysis of the generated and actually available heat per month (after self-consumption of the digester and heat losses) and of the anticipated possible heat consumption during this time (in some cases more heat is available from the biogas plant than can be consumed and in other cases more heat is necessary than is available from the biogas unit – only the actually utilised heat is taken to have an economic value). It is assumed that the consumed biogas heat replaces another source of heating, and the economic value of the biogas heat is considered to be 90% of the price for heating oil in the calculations. 10 kWhth of utilised biogas heat replace 1 litre of heating oil. Concerning the fertiliser value of digestate, the economic modelling distinguishes between nutrients originating from slurry/ manure and nutrients originating from other feedstock. Nutrients from slurry/ manure must not be taken into account with the full economic value, since they would be spread to 46


land with or without passing the biogas process (see Chapter 4.5), but there is an improved fertiliser value due to the better availability of nutrients in the digested material. If manures/ slurries are taken from neighbouring farms for AD under the option to give back digestate, it is not suitable to simply give back the same amount of material. Nutrient contents can vary significantly between the fresh manure/ slurry and the AD digestate, which is a blend of all digested feedstocks. In scenarios that foresee to return digestate to neighbouring farms, the fertiliser value of the incoming manure is calculated and balanced against the necessary amount of digestate with the same fertiliser value. Since the digestate constituents cannot be altered but will differ from those of the fresh manure/ slurry, it is not possible to actually give back the same amounts of nutrients (some materials will for example contain lower concentrations of N, but higher concentrations of other nutrients). In order to achieve a same total fertiliser value, the concentrations of N, P and K are regarded.

6.3 Sensitivity Analysis and Grant Requirements The economic modelling and the profitability projection include a sensitivity analysis. Table 6-2 lists the parameters. All parameters are varied by ± 10% and other variations of the individual parameters are chosen upon suitability. Table 6-2

Parameters for Sensitivity Analysis

Parameter Electrical efficiency CHP unit Gas production Investment costs Substrate costs Revenue from electricity

Variation ± 10% rel.* ± 5% rel.* ± 10% ± 5% ± 20% ± 10% ± 20% ± 10% ± 20% (= 11.6 and 17.40 p/kWhel) ± 10% (= 13.05 and 15.95 p/kWhel) ± 5% (= 13.78 and 15.23 p/kWhel)

* the variation of the electrical efficiency is relative and not absolute to the efficiency of the basic scenario, e.g. if the basic scenario calculates with an efficiency of 34.0%, a +10% higher efficiency means an efficiency of 37.4%

The economic modelling also researches the necessity of grants for the planned biogas plants. In scenarios where the results of the basic modelling indicate longer payback periods, it is determined which grant would be required to achieve a payback period of eight and of five years.

47


7 Individual Case Studies 7.1 Site 1 (75 kW): A 200 cow dairy farm using slurry and grass/maize silage and having potential to use heat 7.1.1

General Overview, Input Substrates and Potential Methane Yields

Site 1 is a dairy farm. Unchopped straw and sand are used as bedding material for cows. Sand is a common problem in biogas production (sinking layer formation, abrasion of technical equipment). Shortage of straw in the region and consequently a high straw price, and beneficial effects of sand on the acidic soil conditions (otherwise addition of lime would be necessary) are the main reasons why the farmer is reluctant to stop using sand as bedding material. In basic trials the farmer also founds straw not to work well under his conditions and hence fears loss of productivity with straw alone. Miscanthus is not favoured as an alternative; the farmer sees a risk that it starts degrading and gets warm when used as a bedding material. It is assumed that only slurry without high amounts of sand will be used for biogas generation. Further potential biogas plant input materials are grass silage and maize silage (Table 7-1). Table 7-1

1 2 3 4

Site 1: Biogas substrates and anticipated biogas production (annual mean)

substrates dairy cow slurry (liquid manure)1) straw2) grass silage maize silage biogas plant input mix

mass flow t/a 1100 100 500 650 2350

DM

oDM

% 8 86 34 29 22.7

% 6.4 79.1 29.9 27.3 20.3

specific biogas yield % DM LN/kg oDM 80 350 92 320 88 540 94 670 89.4

biogas pro- methane duction content m³/d % CH4 59 51 54 52 683 53.2

1)

slurry without sand; total slurry production is 2160 t/a, but around 50% are with very high proportion of sand (30-50% w/w; 350 t/a sand are used in half of the stall) and are not considered as input for the biogas plant; cows are all kept free range for approx. 140 d/a; 20% of total slurry amount is collected during the months when dairy cows are kept free range 2)used as litter; straw should be chopped to be better degradable in AD, biogas yields are for chopped straw

Liquid manure is mostly available during the time when cows are kept inside the barn. It is possible to equalize gas production throughout the year by using more silage during months when stock is kept free range (Table 7-2). Table 7-2 1 2 3 4

Scenario 1: Substrate mix when cows are kept inside and while they are kept free range

substrates slurry straw (in slurry/ litter) grass silage maize silage biogas plant input mix DM input oDM input biogas production methane content

kg/d kg/d kg/d kg/d kg/d % % DM m³/d % CH4

while cows inside (7.5 months/a) 4314 392 1222 1589 7517 20.7 88.9 683.5 53.4

while cows free range (4.5 months/a) 863 78 1614 2099 4654 27.8 90.6 683.3 52.9

48


7.1.2

Environmental Permitting

Site 1 is proposing to use slurry plus grass and maize silage collected from its own farm and spreading the digestate to its own farm. There is less than 0.4 MW thermal rated input from the biogas. The farm slurry and manure which is presently being spread to land is classed as a non waste by-product, but is classified as waste after digestion because there has been further processing to recover biogas for the production of energy. Although the digester size at this site could easily be reduced to below 1000 m³, a slightly larger digester was the cheapest one available in the UK market. With a digester < 1000 m³ the farmer could apply to the Environment Agency for Exemptions for the complete AD facility and there would be no cost, but the larger digester needs an Environmental Permit (Table 7-3). If the farm decides to use manures from another farm then a Registered Exemption under Para 7, Environmental Permit, will be required, with conditions such as annual notification with certificate of benefit and risk assessment, secure digestate storage, away from water courses, and no more than 250 m³ digestate applied per ha and year. The farm is not within a current or future NVZ; NVZ Regulations are not applicable, but COGAP Soil Code 1998 advises maximum of 250 kg/(ha*a) total N. Table 7-3

Site 1: Environmental Permitting Requirements

Biogas Plant Gas Combustion Beneficial Spreading of Digestate to own land

7.1.3

Own feedstock & spreading digestate within farm (> 1000 m³) digester & < 0.4 MW thermal rated input if > 1000 m³: Environmental Permit if < 1000 m³: Free Para 12 Exemption, includes storage of Manure & Slurry Free Para 5 Exemption Free Para 12 Exemption if less than between 50 – 250 t/(ha*a) If less than 50 t/(ha*a) simplified procedure is used.

Plant Design and Equipments

This biogas plant will be of small size. In order to approach economic viability, the biogas plant needs to be technically as simple as possible while still enabling a reliable digestion process with high energy conversion efficiency. Design of the biogas plant needs to take into account that the DM content of the input mix is quite high, especially during the summer months. Technically, the DM content inside the digester is not the same as the DM content of the input (organic substance is degraded in the digester) and depending on the technology it could be feasible to run a system without addition of water or recirculation of digestate with reduced DM content (recyclate). However, a higher viscosity in the digester would result in higher energy consumption and higher operational demand on the equipment. Also for the pre-treatment of the substrates there would need to be both a reception pit and a solids feed system. However, with the rather small throughput at this site, it would also be possible to leave away the expensive solids feed system and work with a mixing pit only. This concept requires the DM content of the input mixture to be reduced to around 12% in order to obtain a mixture of liquids and solids which can be pumped. Recirculation of digestate with reduced DM content saves water but is only possible if no inhibitory substances accumulate in the system. Typically ammonia can accumulate when substrates rich in nitrogen are digested, such as grass silage or poultry manure. Ammonia should be kept below 3,000 mg/L NH4-N, although the inhibitory effect depends not only on the concentration but mainly on pH and temperature. Addition of some water helps to avoid process problems. Water is available at Site 1, a river runs nearby. Figure 7-1 gives an overview of the proposed AD plant.

49


CHP unit

heat

electricity

feed-in

heat consumer biogas

internal consumption


animal barns slurry

solid substrates

reception pit with mixer and pump

dilution water

digester heated, stirred with gas holder 38°C

digestate digestate storage landspreading

recyclate

Figure 7-1

Proposed AD plant Scenario 1

The concept includes a mixing pit of 90 m³, a digester of 1,184 m³ (effective volume, after allowing a freeboard of 0.5 m, gross volume 1,308 m³) and digestate storage capacity for 182 days. The resulting maximum digester organic loading rate of 1.2 kg oDM/(m³*d) and the minimum hydraulic retention time of 75 days (Table 7-4) during periods when a rather high amount of slurry is fed into the digester (slurry itself has stabilizing potential) promise very high process stability. In fact the digester could well be designed smaller with little risk of increased process instability, but the chosen digester was the cheapest one available in the UK market (at least from the companies which placed an offer for this scenario). No secondary digester is proposed. For digestate storage, Manure Bags/ Flexistores manufactured from plastic sheeting are a low cost option and can be adapted to individual space requirements (see www.wiefferink.nl). The maximum digestate in 182 days is 1,486 t = 1,415 m³ (necessary storage capacity). More details can be found in the Annex. Table 7-4

Scenario 1: Biogas Plant Feeding and Key Process Parameters

substrates Table 7-2 dilution water recyclate AD input incl. recyclate DM-content input organic loading rate hydraulic retention time digestate production*) DM-content digestate

kg/d kg/d kg/d kg/d % kg oDM/(m³*d) d kg/d %

while stock inside (227.5 d/a) 7517 1507 6123 15,146 12.1 1.2 75 8,164 8.8

stock free range (137.5 d/a) 4654 2740 4901 12,295 11.9 1.0 92 6,534 6.9

*)

note: recyclate addition does not result in higher digestate production, as recyclate is recirculated in the system

The AD plant will be located at a distance of 400 m from the barns; a concrete surface is already available, which reduces investment for earth works/ infrastructure. In addition to investment costs for the actual AD plant, a silage pit for storage of energy crops is necessary (1,180 m³). The economic modelling assumes that full digestate storage needs to be built (any slurry storage under the barn is not usable for AD digestate). The next transformer station (grid connection) is around 100 m away.

7.1.4

Outputs of the AD Process (Energy and Digestate)

Among the CHP units available on the market, a unit equipped with a MAN gas engine and an installed capacity of 75 kWel is chosen. Assuming a runtime of 8000 h/a, the engine would run on 73%

50


of full power. The actual efficiency degree, the production of electricity and heat, and the final amount of available energy which can generate income are listed in Table 7-5. Table 7-5

Scenario 1: Energy Generation

Methane flow CHP gas engine actual efficiency degree CHP:

132,806 m³/a installed capacity: 75 kWel electrical 32.9%

Energy content: 1328.1 MWh/a runtime: 8000 h/a at 72.8% of full power thermal 48.3%

Generation Demand AD process Losses1) Available surplus

electricity 436.93 36.70 6.99 393.24

heat 641.46 204.98 74.20 362.28

MWh/a 50 kWel MWh/a (= 8.4%) MWh/a MWh/a

MWh/a MWh/a MWh/a MWh/a

(= 32.0%)

1)

electricity: transformation (feed-in); heat: losses for distribution and delivery to customer

There is good potential for heat utilisation from biogas generation: two houses (heated in winter, one of the houses is a very large one) and one swimming pool (heated ½ year in summer). The tables in the Annex contain an overview of available heat from the AD plant for each month and of the assumed potential need from consumers during this time. The AD plant can fully cover the consumers’ heat demand in each month; 14,100 L/a oil would be replaced by 141.0 MWh/a biogas heat. The tables in the Annex also compile material flows that go into the biogas plant (substrates) and material flows that leave the plant (biogas and digestate) including nutrients in detail. Nutrients originating from slurry and from other substrates are listed separately in the Annex, since their economic value is different (see Chapter 4.5 or Chapter 6.2.1) and hence they are priced differently in the economic modelling. Table 7-6 lists the nutrients which are available for spreading to land. For spreading of digestate, enough land is available on the own farm. The farmer’s slurry tanker is not equipped with a vacuum pump (other system was chosen due to high sand content). Since spreading equipment will probably be available in the neighbourhood, those costs are not considered in the modelling. Table 7-6 nutrients

Scenario 1: Digestate Nutrients for Landspreading

total: effective:1) digestate amount: land for spreading

N: 12.46 t/a N: 10.59 t/a 2756 t/a necessary: available own farm:

P2O5: 4.44 t/a K2O: 15.36 t/a P2O5: 4.44 t/a K2O: 15.36 t/a nutrientseff: 3.84 kg N/t; 1.61 kg P2O5/t; 5.58 kg K2O/t 42.4 ha (minimum for N250) 60 ha arable, 120 ha grass land

1)

after losses (during storage and spreading)

7.1.5

Economic Viability

The economic modelling assumes that the plant will be completely bank-financed. Investment costs include full digestate storage capacity costs and costs for additionally necessary silage storage. All details are given in the Annex. Table 7-7 presents a summary. High Business Losses must be expected; the negative Payback Period indicates that the generated revenue would not even be high enough to cover ongoing costs including necessary re-payments to the bank. The 10-year cash flow projection (Figure 7-2) accumulates to total Business Losses of nearly £500,000.

51


Table 7-7

Summary Economic Viability Scenario 1

Scenario 1

12. August 2008 Input

Manure Grass Maize Straw Dilution Total

Annual mass flow [t/a] 1.100 500 650 100 720 3.070

cattle (liquid manure) grass silage (general) maize silage straw (in slurry) dilution water

Main digester Amount: Effective digester volume: Organic loading rate (annual mean): Theoretical retention time (annual me After-Digester: Effective digester volume Organic loading rate (annual mean): Theoretical retention time (annual me Storage: Eco/ Manure Bags Effective storage volume: Retention time (annual mean): Mass reduction of input: Gas yield and gas utilisation: Biogas - yearly flow rate: Methane content CHP: Gas Engine Runtime of CHP unit: Demand of ignition fuel oil: Electric power: Electric efficiency of CHP: Electricity production: Demand of biogas plant: Transformation and feed-in losses Electricity for sale: Heat: Thermal efficiency of CHP: Heat production: Demand of biogas plant: Heat losses (from theor. avail. heat): Available heat for consumers: Actually used heat by consumers:

Daily mass flow [t/d] 3,01 1,37 1,78 0,27 1,97 8,41

DM

oDM

[%FM] 8% 34 % 29 % 86 % % 17,3 %

[%DM] 80 % 88 % 94 % 92 % % 89,4 %

Daily Input oDM [kg oDM/d] 193 410 485 217 0 1.305

Investment costs: Total investment costs: Own capital: Subsidy/Grant: Total without VAT:

1 1186 m³ 1,1 kg oDM/m³·d 80 d

Biogas Yield [L/kg oDM] 350 540 670 320 0

Costs of Capital/ Ongoing Costs: Write-off: Construction: 20 years Technology: 12 years CHP: 7,0 years Rate of interest: 7,0 % Insurance: 1,5 % Rent for land: Maintenance/ Repair: Construction: 2,0 % Technology: 3,0 % CHP: 0,96 p/kWh Ingnition fuel oil (if dual fuel): 52 p/L Electric power from the grid: 9, p/kWh

249.460 m³/a 53,2 % 75 kW 8.000 h/a 0 L/a 32,9 % 436.933 kWh/a 36.702 kWh/a 6.991 kWh/a 393.240 kWh/a 48,3 % 641.455 kWh/a 204.979 kWh/a 74.201 kWh/a 362.275 kWh/a 141.000 kWh/a

Daily flow rate Daily flow rate biogas methane [m³/d] [m³/d] 68 40 221 120 325 169 69 35 0 0 683 364

2009

Wholesale electricity price ROC Second ROC Others Total electricity value

m³ d

Methane content [%] 59 % 54 % 52 % 51 % % 53,24 %

Revenues: Year of commissioning:

506.921 £ £ £ 506.921 £

#DIV/0!

1.440 m³ 6,6 months 10,2 %

Biogas Yield [m³/t FM] 22,40 161,57 182,64 253,18 0,00

13.843 £/a 12.638 £/a 11.199 £/a 17.742 £/a 7.604 £/a £/a

5,5 4,5 4,5 0,0 14,5

p/kWh p/kWh p/kWh p/kWh p/kWh

Revenue from electricity 14,5 p/kWh 57.020 £/a Gate fees for waste £/a Revenue from heat usage 4,7 p/kWh 6.599 £/a Digestate fertiliser value (manure: improved fertiliser value only) N: Manure 12,0 ct/kg N 453 £/a N: Other biomass 56,0 ct/kg N 2.633 £/a P: 24,0 ct/kg P 1.107 £/a K: 23,2 ct/kg K 2.043 £/a Total revenue: 69.854 £/a

5.537 £/a 4.550 £/a 4.195 £/a £/a £/a £/a

(8,4 %) Costs substrates Transport digestate off-farm Costs land-spreading digestate own farm: Labour costs: 375,0 h/a (32,0 %) Other oper. costs: 1,0 % ((17 % rel)) of investment costs without CHP (56,5 %) Further costs (if any) Total costs:

27.644 £/a £/a 4.356 £/a 5.625 £/a 4.285 £/a Business Profit/ Losses: Payback period:

£/a 119.219 £/a

1.000.000 £

-49.364 £/a -43,4 years

Revenue 10-year projection

500.000 £

Ongoing costs without write-off

0£

Total costs including write-off

-500.000 £ -1.000.000 £

Benefits/ costs before write-off

-1.500.000 £

Business Profit/ Losses 1

0£

2

3

4

5 Year

6

7

Detail: Business Profit/ Losses 0£

-100.000 £

9

10

Invest costs (-) plus accumulated benefits/ costs before write-off

-100.000£

-200.000 £

= recovery of initial invest

-200.000£

-300.000 £

-300.000£

-400.000 £

-400.000£ -500.000£

-500.000 £

-600.000£

-600.000 £

-700.000£ 1

Figure 7-2

8

2

3

4 Year 5 6

7

8

9 10

1

2

3

4 Year 5 6

7

8

9 10

10-year Cash Flow Projection Scenario 1

52


Even without considering write-off costs, there is no business benefit (see ‘benefits/costs before writeoff’ in Figure 7-2), which indicates that the generated revenue is not even high enough to cover ongoing costs (maintenance, substrates, insurance, labour costs, etc. = ‘ongoing costs without writeoff’). As a consequence, this plant will not be able to pay back the bank loan and will even need further money from the bank to cover its losses (expressed by the negative pay-back period). In Figure 7-2, the small figure on the right at the bottom indicates possible development of the bank debt. In order to achieve a minimum Business Profit, a grant of 89% of the total investment sum would be necessary (assuming that 2 x ROCs would still be possible when taking the grant), see Table 7-8. With a single ROC only, even a grant of 100% (and consequently no need for any bank-financing) would not enable any Business Profit. The possible income would not even be high enough to cover ongoing costs (substrates, insurance, maintenance, labour, digestate spreading etc.). Table 7-8

Overview of Economic Viability and Grant Requirement in Scenario 1

Total Investment Costs: £506,921 Without grant:

Operation/Main Revenue tenance/Capital [£/a] Costs [£/a] 119,219 69,854

Business Profit/Losses [£/a] -49,364

Return on Investment -2.7%

Reflux Capital [years] 83.7

Payback Period [years] negative

Necessary Grant to achieve a shorter Payback Period. Assumption: 2*ROCs still possible when taking the grant. Grant: 89% £451,515 69,853 69,854 +1 7.0% 9.1 13.5 93% £468,902 67,952 69,854 +1,902 12.0% 6.3 8.0 95% £481,017 66,628 69,854 +3,227 19.5% 4.3 5.0 Necessary Grant to achieve a shorter Payback Period. Assumption: 1*ROCs only possible when taking the grant. Grant: < 100% 52,159 losses negative 100% £506,921 63,796 52,159 -11,637 0 0

The sensitivity analysis (Table 7-9) shows that at this site investment cost reduction has the highest potential to increase viability. However, none of the studied parameter variations results in positive Business Profit. In order to achieve a minimum Business Profit, investment costs would need to be reduced by 64% to £183,000, which is rather unlikely. With regards to the electricity value, a minimum profit would be achieved if electricity was worth 27.1 p/kWh (all other parameters unchanged), which currently is not realistic. Table 7-9

Sensitivity Analysis Scenario 1

Reference (= Scenario 1) Electrical Efficiency Degree CHP Gas Production Investment Costs Substrate Costs Electricity Value

+/- 10% +/- 5% +/- 10% +/- 5% +/- 20% +/- 10% +/- 20% +/- 10% +/- 20% +/- 10% +/- 5%

Business benefits/ losses £/a difference to reference (reference: -49,364) +/- 5,283 +/- 2,641 +/- 5,283 +/- 2,641 -/+ 15,480 -/+ 7,740 -/+ 5,529 -/+ 2,764 +/- 11,404 +/- 5,702 +/- 2,851

Payback period years negative neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg.

53


7.1.6

Recommendations

The economic modelling indicates a high risk of Business Losses when investing in the planned AD plant. A grant of a minimum of 90% would be necessary to achieve viability. However, if it is not be possible to claim 2 x ROCs when taking a grant, even 100% grant would not enable any profitability. If an AD plant is further to be considered as an option, straw should be chopped prior to using it in the barn. Replacement of sand with straw would be favourable with regards to biogas. This modelling is based on the manure without high amounts of sand only (there is technology available that can cope with high amounts of sand; but due to the high investment costs this is not viable for such a small plant). Replacement of sand with straw would require 100 t/a straw and would double both the available amount of slurry for biogas generation and the digested straw. This would increase biogas production by 20% to around 820 m³/d. However, the AD plant would still not be economically viable. Additional slurry is available in the neighbourhood. The biogas plant operator could provide storage and would give back enhanced digestate. Cows in the neighbourhood are grazing around 6 months per year during the summer time. Therefore, additional manure would be available only during the winter time. Since so far no decision is possible whether or not the slurry in the neighbourhood could be treated in the biogas plant, it is not considered in the economic modelling. However, the biogas plant will be able to digest additional slurry (plant dimensioning is generously proportioned). The potential availability of additional slurry during the winter time is an argument to decide in favour of a CHP unit with higher capacity. The additional slurry could be digested during the winter time, while some more silage would be used during the summer. Although a more detailed feasibility study would be necessary, a first assessment indicates that with a total amount of 8,000 t/a of slurry and a grant of 50% on necessary investment costs (and 2 ROCs), a business profit of around £9,000 per year and a pay-back period around 10 years could be achieved.

7.2 Site 2 (499 kW): A Vegetable Farm using Poultry Manure and Energy Crops 7.2.1

General Overview, Pre-Selection Wet/ Dry Digestion, Input Substrates and Methane Yields

Site 2 is a vegetable farm which uses poultry manure from a neighbouring farm as the main fertiliser. Potential AD substrates are poultry manure, grass and maize silage, stock feed potatoes and straw. For utilisation in the AD plant some cow slurry would be available at a neighbouring farm and Site 2 would return digestate with the same value of nutrients to the neighbour. In addition to the currently already used amount of poultry manure (referred to as poultry manure ‘1’ in Table 7-10), more poultry manure from another neighbour (referred to as poultry manure ‘2’) would be available for the AD process. Site 2 would return digestate with the same value of nutrients to that neighbour as well. Some more poultry manure could be available; however this substrate contains high amounts of sawdust and would only be suitably digestible in a dry digestion system. Up to 500 t/a straw could be available. Both wet and dry digestion are possible technical options. With dry digestion in batch-operated boxtype fermenters, slurry should not be used as its high viscosity reduces the extent to which sprinkled liquid trickles through the stacked substrate. Dry digestion might be favourable due to the high DMcontent of the substrate mix, the high amount of available straw and presence of poultry manure. Digestion of higher amounts of lignocellulosic material is often regarded unsuitable in wet digestion, 54


since phase-separation takes place, with the lignocellulosic material floating on top. Eventually, lignocellulosic material might also form a sinking layer and might cause clogging of the outflow pipes. But with dry digestion such problems do not have to be dealt with. However, dry digestion was offered at a very high price. Around three times higher investment costs would be necessary compared to the proposed wet digestion solution in the following. Even with high grants, the dry digestion concept was far away from being economically viable. Dry digestion does require higher investment in mainland Europe as well, but the difference to wet digestion is less distinct. As dry digestion needs less maintenance, has lower electricity demand, is more robust than wet digestion and can also treat substrates that need to be excluded in wet digestion (such as materials containing woody components, or contaminated with stones, plastics etc.), it can be of advantage. The concrete price is higher in the UK, which might be a key reason for the very high UK offer. For wet digestion, the amount of straw should be limited due to the high risk of material floating on top of the liquid phase and the risk of causing clogging. Table 7-10 lists the substrate mix for Scenario 2. Cow slurry is only available while the cows in the neighbourhood are housed. Table 7-11 lists the recommended substrate mix throughout the year. The ratio of grass to maize to potatoes is assumed to be constant, since potatoes could be ensiled with grass and maize for conservation. Table 7-10

1 2.1 2.2 3 4 5 6

Scenario 2: Biogas Substrate Mix and anticipated Biogas Production (annual mean)

substrates cow slurry1) poultry manure ‘1’2.1) poultry manure ‘2’2.2) grass silage maize silage stock feed potatoes straw3) biogas plant input mix

mass flow t/a 1500 1350 500 1955 4500 500 100 10,405

DM

oDM

% 8 55 55 34 31 20 86 32.5

% 6.4 41.3 41.3 29.9 29.1 18.0 79.1

specific biogas yield % DM LN/kg oDM 80 350 75 490 75 490 88 540 94 670 90 560 92 320 86.4

biogas pro- methane duction content m³/d % CH4 59 62 62 54 52 52 51 4596 54.7

1)

dairy cows in neighbourhood; assumptions: kept free range 6 months/a with no slurry collection during this time; slurry would be brought to Site 2 for AD and afterwards digestate of the same fertiliser value would be returned to that farm 2.1) poultry manure ‘1’ (from a neighbouring farm) is currently already used as fertiliser at Site 2; contains straw as litter; yearly mass flow 1200 to 1500 t/a 2.2)poultry manure ‘2’ (from another neighbouring farm) is straw based chicken manure; it would be brought to Site 2 for digestion and afterwards digestate of the same value of nutrients would be returned to that neighbouring farm 3)straw should preferably be used as litter e.g. in the poultry units before going to AD

Table 7-11 1 2 3 4 5 6

Scenario 2: Biogas Substrate Mix throughout the Year

substrates cow slurry poultry manure ‘1’ + ‘2’ grass silage maize silage potatoes straw biogas plant input mix DM input oDM input biogas production methane content

kg/d kg/d kg/d kg/d kg/d kg/d kg/d % % DM m³/d % CH4

while cows inside (6 months/a) 8,287 5,069 5,209 11,991 1,332 274 32,162 29.4 86.1 4596.4 54.9

while cows free range (6 months/a) 5,069 5,501 12,662 1,407 274 24,912 36.5 86.8 4596.4 54.6

55


7.2.2


Site 2 already uses poultry manure from another farm as fertiliser and the AD scenario includes manures from sources outside the farm. The digester size exceeds 1000 m³ and there is more than 0.4 MW thermal rated input from the biogas, Environmental Permits are required (Table 7-12). For spreading of digestate, imported slurry and manures from other farms make it necessary to apply for a Registered Exemption under Para 7, with conditions such as annual notification with certificate of benefit and risk assessment, secure storage away from water courses, and no more than 250 m³ digestate applied per Ha per annum. This farm will be located within an NVZ in the future; the NVZ regulations limit the spreading of digestate to 170 kg/ha N per year. Table 7-12


Using own + imported feedstocks & spreading digestate within farm + exporting digestate to neighbouring farms > 1000 m³ digester size & > 0.4 MW thermal rated input Biogas Plant Environmental Permit Gas Combustion Environmental Permit Beneficial Spreading of Digestate to own land + Registered Exemption Para 7 Transport Digestate off-farm

7.2.3


Wet digestion needs to take into account the high DM content of the substrate input mix and presence of poultry manure which in general can cause mechanical problems during digestion. Poultry manure contains sand which is released during hydrolysis and digestion, forms a sinking layer and deposits on the ground. A horizontal plug-flow digester would in principle be particularly suitable; sand could be continuously removed at the end of the digester. Since the horizontal digester should be followed by a second fermenter, the concept is rather expensive. However, none of the contacted companies offered this digester type for the UK market. As an alternative, a vertical digester should be chosen which can cope with presence of some sand and which preferably is equipped with an outlet for sand removal at the bottom, in order to avoid the digester being regularly emptied for removal of the deposits. In the pre-planning it was intended to propose a system with partial recirculation of liquid digestate in order to reduce the DM-content of the input. However, poultry manure and grass silage both contain considerable amounts of nitrogen resulting in too high ammonia concentration in the digester. Utilisation of recyclate could result in ammonia inhibition. Addition of water is recommended in order to limit ammonia concentration to maximum 3,000 mg/L. Water is available (spring and rain water). The proposed AD concept includes a mixing pit of 90 m³ for liquids and a solid feeder of 20 m³ for solid materials. Smaller and less expensive solid feeders are available on the market, but this dimensioning ensures that filling solids once per day into the solid feeder will be sufficient; otherwise too much labour would be necessary. Since solids are fed directly into the digester via the solid feeder it is not necessary to reduce the total DM-content of the input to 12% (no solids are added to the mixing pit). However, the DM-content inside the digester should not exceed this value in order to avoid process problems and limit energy demand for agitation. The proposed addition of water (Table 7-13) results in a (calculated) DM-content of 1000 m³ and gas production equals approximately 0.4 MW thermal rated input. The farmer will have to apply for Environmental Permit (Table 7-22). The imported slurry makes it necessary to apply for a Registered Exemption under Para 7, Environmental Permit, with conditions such as annual notification with certificate of benefit and risk assessment, secure storage away from water courses, and no more than 250 m³/(ha*a) digestate applied. The AD plant will not be located within a NVZ; NVZ regulations are not applicable, but COGAP Soil Code 1998 advises a maximum of 250 kg/(ha*a) total N. Table 7-22

Scenario 3: Environmental Permitting Requirements

Own + imported feedstock & spreading digestate within farm > 1000 m³ digester & > 0.4 MW thermal rated input Biogas Plant Environmental Permit Gas Combustion Environmental Permit Beneficial Spreading of Registered Exemption Para 7 Digestate to own land

7.3.3


The proposed AD plant (Figure 7-5) includes a main digester (effective volume 1854 m³) followed by an after-digester (not heated, effective volume 2994 m³) which at the same time serves as partial endstorage. For solid substrates, a 20 m³ solid feeder is foreseen. Smaller and less expensive solid feeders 63


are available on the market, but this dimensioning ensures that filling solids once per day into the solid feeder will be sufficient; otherwise too much labour would be necessary. heat heat consumer


grass silage and other solid material

solid feeder with screw conveyor

slurry/ manure


dilution water

electricity

CHP unit


biogas

overflow


feed-in or possibly supply to idustrial site

after-digester not heated, stirred with gas holder


recyclate

Figure 7-5


For liquids, a 90 m³ mixing pit is foreseen. In order to reduce the DM-content of the digester input, it is assumed that water will be added until the ammonia content is reduced to around 3,000 mg/L and afterwards the DM-content is further reduced by recirculation of digestate with reduced DM-content (recyclate). Unlike in Scenario 1, no solids are added to the mixing pit (solids are fed directly into the digester). It is therefore not necessary to reduce the total DM-content of the digester input to 12%. However, the DM-content inside the digester should not exceed this value in order to avoid process problems and limit energy demand for agitation. The DM-content inside the digester is not the DMcontent of the substrate input, as organic material is degraded inside the digester which at the same time results in DM-reduction of the digester content. The proposed addition of water and recyclate (Table 7-23) results in a (calculated) DM-content of 31% on total investment costs would allow business profitability if 2 x ROCs could still be claimed (Table 7-27). Reducing the Payack Period to 8 or 5 years would require grants of 54% and 69%. If falling back on 1 x ROCs, grants of below 83% would not allow any profitability. Even when reducing the Payback Period to 5 years by a grant of 92% on total investment costs, the Business Profit for the farmer would be much lower than with a grant of 50% and 2 x ROCs. Table 7-27

Grant Requirement in Scenario 3




Return on Investment 3.7


Payback Period [years] 26.0

Necessary Grant to achieve a shorter Payback Period. Assumption: 2*ROCs still possible when taking the grant. Grant: 31% £294,913 240,054 240,056 +1 7.0% 9.4 14.0 54% £513,762 216,771 240,056 +23,284 12.3% 6.3 8.0 69% £653,878 201,864 240,056 +38,191 19.8% 4.3 5.0 Necessary Grant to achieve a shorter Payback Period. Assumption: 1*ROCs only possible when taking the grant. Grant: 83% £788,019 187,593 187,594 +1 7.0% 9.4 14.0 88% £843,084 181,735 187,594 +5,859 12.3% 6.3 8.0 92% £878,351 177,983 187,594 +9,611 19.8% 4.3 5.0

The sensitivity analysis (Table 7-28) clearly points out the dominant effect of the electricity value. A 19% higher electricity value (= 17.2 p/kWh) would bring this scenario into profitability. This could be achievable at this site, as supplying electricity to the nearby industrial site would generate a higher 67


revenue per kWh. Assuming an average electricity retail price of 9 p/kWh and assuming further that the biogas plant would sell for 8.5 p/kWh, the total revenue including 2 x ROCs (2 x 4.5 p/kWh) would be 17.5 p per kWh delivered electricity. This would however require additional investment into a private electricity wire from the AD plant to the industrial site. A more detailed feasibility study would be necessary to assess this option. Reducing investment costs by 23% would also bring this AD project into profitability. The sensitivity analysis also indicates that any decline in the efficiency of the CHP unit or in the gas production will significantly influence profitability. Any failure/ inhibition of the biological process or a temporary break-down of the CHP unit would result in crucially reduced revenue. Table 7-28



7.3.6

+/- 10% +/- 5% +/- 10% +/- 5% +/- 20% +/- 10% +/- 20% +/- 10% +/- 20% +/- 10% +/- 5%


Payback period years 26.0 18.2/ 45.4 21.4/ 33.0 18.2/ 45.4 21.4/ 33.0 51.2/ 15.0 35.5/ 19.6 49.2/ 17.7 34.0/ 21.0 13.5/ 332.9 17.8/ 48.2 21.1/ 33.8

Recommendations

Although the economic modelling results in Business Loss forecast, this site has potential for an economically viable AD installation. Supplying electricity to the nearby industrial site would be a feasible and favourable option. The higher electricity value would allow business profitability even without any grant. With regards to the biological process run mainly on grass silage in this scenario, it would be favourable to add further substrates to the plant in order to avoid process imbalance including shortage of micronutrients, which can inhibit development of the microbiological population. Due to the particularly good possibility to supply heat and electricity to the industrial site in the neighbourhood, it might be an option to decide in favour of taking in waste materials. This would require higher investment, but the high possible revenues from supplying electricity and heat to the neighbourhood together with the incoming gate fees clearly promise good business profitability. Both the option to take in waste streams and the option to supply electricity to the nearby industrial site would require a more detailed feasibility study. Additional costs and more revenue would be associated with both options and the results would need to be studied more precisely.

68


If feasible, a combination of different renewable energy technologies would be favourable at this site. Compared to other renewable energy concepts, biogas generation has the advantage that energy generation is highly constant and virtually independent from weather conditions, while for instance wind power depends on the actual wind situation. If a mix of different technologies is envisaged, the continuity of energy generation from the biogas plant unit should be used as positive argument when negotiating the conditions for energy sales to the grid.

7.4 Site 4 (105 kW): A 600 LU dairy farm using slurry, manure, grass and wheat, and having some digestate storage capacity already 7.4.1


Site 4 is a dairy farm. Straw and sawdust are used as litter material. Cattle slurry, grass silage, cereal silage and crop grain would be available for biogas generation (Table 7-29). Cultivation of maize is not suitable in this location close to the coast. Cows are kept in three different places and all are kept free range during the summer months. The AD plant would be placed close to the first site (Site A) where the majority of the cows are kept. The two other sites are 5.6 km (Site B) and 3.3 km (Site C) away. Two options are possible: utilisation of all slurry/ manure from the three sites or utilisation of slurry from the main site only. Despite the additional costs for transport of slurry/ manure from the two further away locations to the AD plant, the economic modelling indicates that digestion of all available substrates can contribute to the economic benefit. This option is therefore discussed in the following. During the time when stock is kept free range, only limited amounts of slurry are available. Crop grain and a higher proportion of grass silage could be digested during this time (Table 7-30). Table 7-29

1 2 3.1 3.2 4 5 6

Site 4: Available biogas substrates and anticipated biogas production (annual mean) mass flow t/a 4960 350 75 14 500 500 100 6499

substrates cow slurry (liquid)1) solid cow manure2) straw3.1) sawdust3.2) grass silage whole crop wheat silage crop grain biogas plant input mix

DM

oDM

% 8 22 86 75 31 38 85 15.1

% 6.4 17.2 79.1 70.5 27.3 35.3 79.9 13.0

specific biogas yield % DM LN/kg oDM 80 350 78 330 92 320 94 88 540 93 570 94 730 85.8

biogas pro- methane duction content m³/d % CH4 59 59 51 54 53 53 1048 55.1

1)

site A (main site): 330 LU dairy cows, all kept free range for 230 d/a, during this time animals are in for 6 h/d while milked; site B (5.6 km away from site A): slurry from 120 LU cows, kept free range for 230 d/a with no slurry collection during this time; site C (3.3 km away from site A): slurry from 80 LU cows, free range for 230 d/a with no slurry collection during this time 2)65 LU cows (= 40 LU at site B, 25 LU at site C, no solid manure at site A) 3.1)used as litter; straw should be chopped to be better degradable in AD, gas yields are for chopped straw 3.2)used as litter; no relevant biogas yield

Table 7-30 1 2 3

Scenario 4: Substrate mix while animals are housed and while cows are kept free range

substrates cow slurry solid cow manure straw (litter) saw dust (litter)

kg/d kg/d kg/d kg/d

while cows inside (4.5 months/a) 28,932 959 454 73

while cows free range (7.5 months/a) 4,530 959 59 18

69


4 5 6

grass silage whole crop wheat silage crop grain biogas plant input mix DM input oDM input biogas production methane content

7.4.2

kg/d kg/d kg/d kg/d % % DM m³/d % CH4

662 662 31,742 10.8 82.9 1048.3 56.9

1788 1788 436 9,577 23.4 88.4 1048.3 54.1


Site 4 is proposing to use substrates from its own farms and spreading the digestate to its own farms. The digester size is exceeding 1000 m³ but there is less than 0.4 MW thermal rated input from the biogas. The farm slurry/ manure which at present is being spread to land is classed as a non waste byproduct, but is classified as waste after digestion. The farmer will have to apply to the Environment Agency. For the Exemptions there will be no cost, but the large digester requires an Environmental Permit (Table 7-31). The farm is not within a current or future NVZ. However, COGAP Soil Code 1998 advises maximum of 250 kg/(ha*a) total N. Table 7-31



7.4.3

Own feedstock & spreading digestate within farm > 1000 m³ digester & < 0.4 MW thermal rated input Environmental Permit Free Para 5 Exemption Free Para 12 Exemption if less than between 50 – 250 t/(ha * a) If less than 50 t/ha a simplified procedure is used


A concept comparable to Scenario 1 is proposed. As a low-cost alternative to a solids feed system, it is suggested to add the solids to the mixing pit. This concept requires the DM-content of the input mix to be reduced to around 12%, in order to assure pumpability of the feedstock. As in Scenario 1, addition of fresh water and utilisation of recyclate is possible. During the time when animals are housed, no dilution is necessary. For the summer months it is suggested to add enough water to reduce the calculated resulting ammonia content in the digester to below 3,000 mg/L NH4-N. For further reduction of the DM-content in the mixing pit recyclate could be used. Table 7-32 recommends addition of water and recirculation of digestate with reduced DM-content (recyclate) in a ratio 1 : 8 during the time when animals are kept free range. A 90 m³ mixing pit is assumed. From the mixing pit, substrates would be pumped into a reinforced concrete digester, equipped with horizontal and vertical agitators and with an effective volume of 1,854 m³, allowing for a minimum hydraulic retention time of 56 days during periods when high amounts of slurry are fed into the digester and of 80 days while more energy crops are fed. The proposed concept does not include an after-digester.

70


CHP unit

heat

electricity

feed-in




animal barns slurry

solid substrates


dilution water



recyclate

Figure 7-7


Table 7-32

Scenario 4: Biogas Plant Feeding and Key Process Parameters

substrates Table 7-30 dilution water recyclate AD input DM-content input organic loading rate hydraulic retention time digestate production*) DM-content digestate


while stock inside (135 d/a) 31,742 31,742 10.8 1.5 56 30,423 7.0

stock free range (230 d/a) 9,577 1,370 10,999 21,947 12.2 1.1 80 9,629 9.9

*)


A concrete slurry container is available in close proximity to the AD site and could be used as partial end-storage for digestate (2427 m³). In order to assure storage capacity for 182 days, a total volume of 4343 m³ minimum would be required. The economic modelling takes into account investment costs for 1916 m³ extra digestate storage volume. Slurry from the main site could be fed directly into the AD plant. At the other two sites, intermediate slurry storage is already available (around 760 m³ at site B and around 100 m³ at site C). Slurry could be taken out for example once a week in order to be transported to the main site. A 20 m³ tanker is available for transport. There is no slurry pipeline between the three different sites.

7.4.4


Among the CHP units available on the market, a unit equipped with a MAN gas engine and an installed capacity of 104 kWel is chosen. The actual efficiency degree, the production of electricity and heat, and the finally available energy amounts which can generate income are listed in Table 7-33. However, there is no reasonable possibility for heat utilisation; potential consumers are too far away. Table 7-33





Generation

electricity 803.90 MWh/a 92 kWel

heat 930.50

MWh/a

71


Demand AD process Losses1) Available surplus

73.16 12.86 717.89

MWh/a (= 9.1%) MWh/a MWh/a

373.65 111,37 445.48

MWh/a MWh/a MWh/a

(= 40.2%)

1)


Material and energy flows in Scenario 4 are shown in detail in the Annex. For spreading of digestate, at least 10 ha of arable land and 120 ha of grass land are available, which is sufficient to utilise the digestate (see Table 7-34). No additional spreading equipment is necessary. Table 7-34 nutrients



N: 33.45 t/a N: 28.43 t/a 6,333 t/a necessary: available own farm:

P2O5: 11.84 t/a K2O: 37.88 t/a P2O5: 11.84 t/a K2O: 37.88 t/a nutrientseff: 4.49 kg N/t; 1.87 kg P2O5/t; 5.98 kg K2O/t 113.7 ha (minimum for N250) sufficient arable + grass land

1)


7.4.5

Economic Viability

The biogas plant will be completely bank financed, there is no spare own capital available. Sufficient silage storage capacity is already available. Investment in storage capacity for wheat grain is required. As mentioned above, there is some capacity for digestate storage already available on farm, so that only surplus digestate storage capacity needs investment. Details of the economic modelling can be found in the Annex. Table 7-35 summarises the results. Without grant, an AD plant would result in too long a Payback Period and significant Business Losses. After 10 years, more than £300,000 of the initial investment still remain to be recovered (Figure 7-8).

72


Table 7-35

Summary Economic Modelling Scenario 4

Scenario 4


Manure Grass Straw Cereals Others Dilution Total

Annual mass flow [t/a] 4.960 350 500 75 100 500 14 315 6.814

cattle (liquid manure) 0 solid cow manure grass silage (general) straw (in slurry/ manure) crop grain 0 whole crop wheat silage sawdust (in slurry) dilution water

Main digester Amount: 1 Effective digester volume: 1854 m³ Organic loading rate (annual mean): 1,2 kg oDM/m³·d Theoretical retention time (annual me 69 d After-Digester: Effective digester volume m³ Organic loading rate: #DIV/0! Theoretical retention time: d Digestate Storage: Eco/Manure Bags + usable Existing Effective storage volume: 4.387 m³ Retention time (annual mean): 8,7 months Mass reduction of input: 7,1 % Gas yield and gas utilisation: Biogas - yearly flow rate: 382.615 m³/a Methane content 55,1 % CHP: Gas Engine 104 kW Runtime of CHP unit: 8.000 h/a Demand of ignition fuel oil: 0 L/a Electric power: Electric efficiency of CHP: 38,1 % Electricity production: 803.902 kWh/a Demand of biogas plant: 73.155 kWh/a (9,1 %) Transformation and feed-in losses: 12.862 kWh/a Electricity for sale: 717.885 kWh/a Heat: Thermal efficiency of CHP: 44,1 % Heat production: 930.501 kWh/a Demand of biogas plant: 373.646 kWh/a (40,2 %) Heat losses (from theor. avail. heat): 111.371 kWh/a ((20 % rel)) Available heat for consumers: 445.484 kWh/a (47,9 %) Actually used heat by consumers: 0 kWh/a

Daily mass flow [t/d] 13,59 0,96 1,37 0,21 0,27 1,37 0,04 0,86 18,67

DM

oDM

[%FM] 8% 22 % 31 % 86 % 85 % 38 % 75 % % 14,4 %

[%DM] 80 % 78 % 88 % 92 % 94 % 93 % 94 % % 85,8 %

Daily Input oDM [kg oDM/d] 870 165 374 163 219 484 27 0 2.301


Biogas Yield [L/kg oDM] 350 330 540 320 730 570 0 0

Costs substrates Transport digestate off-farm Costs land-spreading digestate own farm: Labour costs: 520,0 h/a Other oper. costs: 1,0 % of investment costs without CHP Further costs (if any) Total costs:

Methane content [%] 59 % 59 % 54 % 51 % 53 % 53 % % % 55,15 %

Daily flow rate Daily flow rate biogas methane [m³/d] [m³/d] 304 180 54 32 202 109 52 27 160 85 276 146 0 0 0 0 1.048 578


470.054 £ £ £ 470.054 £


Biogas Yield [m³/t FM] 22,40 56,63 147,31 253,18 583,27 201,44 0,00 0,00

2009


11.465 £/a 13.094 £/a 11.946 £/a 16.452 £/a 7.051 £/a £/a

5,5 4,5 4,5 0,0 14,5


Revenue from electricity 14,5 p/kWh 104.093 £/a Gate fees for waste £/a Revenue from heat usage 4,7 p/kWh £/a Digestate fertiliser value (manure: improved fertiliser value only) N: Manure 12,0 ct/kg N 2.017 £/a N: Other biomass 56,0 ct/kg N 3.328 £/a P: 24,0 ct/kg P 1.459 £/a K: 23,2 ct/kg K 1.805 £/a Total revenue: 112.702 £/a

4.586 £/a 4.714 £/a 7.717 £/a £/a £/a £/a 43.168 £/a £/a 2.654 £/a 7.800 £/a 3.864 £/a

Business Profit/ Losses: Payback Period:

£/a 134.511 £/a

1.500.000 £

-21.809 £/a 32,0 years

Revenue

10-year projection 1.000.000 £

Ongoing costs without write-off Total costs including write-off Benefits/ costs before write-off

500.000 £ 0£ -500.000 £ -1.000.000 £ -1.500.000 £ 1 0£

2

3

4

5 Year

6

7


-50.000 £

9

10


-100.000£

-100.000 £


-200.000£

-150.000 £

-300.000£

-200.000 £

-400.000£

-250.000 £

-500.000£ 1

Figure 7-8

8

Business Profit/ Losses

2

3

4 Year 5 6

7

8

9 10

1

2

3

4 Year 5 6

7

8

9 10


73


A minimum Business Profit would be achieved with a 41% grant on total investment costs, if 2 x ROCs would still be possible (Table 7-36). However, if falling back on 1 x ROCs, the total revenue would be considerably lower, resulting in a situation in which not even 100% grant would allow a minimum profit. Table 7-36





Return on Investment 2.4%



Necessary Grant to achieve a shorter Payback Period. Assumption: 2*ROCs still possible when taking the grant. Grant: 41% £193,592 112,701 112,702 +1 7.0% 8.9 12.9 58% £274,512 103,585 112,702 +9,118 11.7% 6.3 8.0 72% £336,465 96,605 112,702 +16,092 19.0% 4.3 5.0 Necessary Grant to achieve a shorter Payback Period. Assumption: 1*ROCs only possible when taking the grant. Grant: < 100% 80,397 losses negative 100% £470,054 81,555 80,397 -1,157 0 0

With a higher electricity value, the economic viability would be significantly better (Table 7-37). A minimum profit could be achieved by a 21% higher electricity value (17.54 p/kWh), which clearly indicates the significant influence of this parameter. Reducing the investment costs also has good potential to achieve a more viable AD installation. If the total investment costs could be reduced by 30%, this AD project would result in no losses. Table 7-37



7.4.6

+/- 10% +/- 5% +/- 10% +/- 5% +/- 20% +/- 10% +/- 20% +/- 10% +/- 20% +/- 10% +/- 5%


Payback period years 32.0 19.3/ 92.9 24.1/ 47.6 19.3/ 92.9 24.1/ 47.6 76.6/ 17.1 46.9/ 23.0 77.5/ 20.1 45.3/ 24.7 13.2/ negative 18.7/ 109.8 23.6/ 49.5

Recommendations

Without grant an AD plant at Site 4 would hardly be economically viable. However, if an electricity value around 17.5 p/kWh could be achieved, the project would be feasible even without grant. With no higher electricity value, a grant of 41% on total investment costs would enable a minimum profit and a grant of 58% would reduce the payback period to 8 years, if 2 x ROCs could still be claimed. With 1 x ROCs only, the project would result in Business Losses even with 100% grant on total investment. 74


Regarding the AD process requirements, straw should be chopped before using it as litter material for the animals. Sawdust should be replaced by straw as litter material. Recycling of nutrients with improved fertiliser value through anaerobic digestion would be particularly favourable at this site since this farm is located in an area with general nutrient shortage. An AD plant would clearly have particular environmental benefits at this site. A major drawback on the economic viability is the lack of potential heat consumers. As additional substrates, some food wastes from restaurants and hotels in the region could be available. Stricter legislative regulations would apply. Digestion of food waste is not considered in this scenario. It is worth mentioning that digestion of wheat grain has only a very small effect on the profitability of an AD plant at this site if there is no grant (very few hundred £ per year). There is higher revenue from generated electricity, but also the necessary investment costs are higher as some storage for grain is necessary. However, with a grant and 2 x ROCs available, the benefit from crop digestion is distinct, as with all other substrates. If higher revenue per kWh electricity can be generated, it is clearly advantageous to include grain like other energy crops into the digestion concept.

7.5 Site 5 (250 kW): A 1000 LU cow farm using cow slurry and silage 7.5.1


Site 5 is a dairy farm. Presently, the animal barns are newly established, and integration of a biogas plant could be a further option within the farm concept. The potential biogas plant would be run mainly on cattle slurry with addition of some left-over potatoes (Table 7-38). Less slurry is produced during periods when a part of the herd is kept free range. Around 50% of the animals are out for half of the year. Co-digestion of potatoes is suitable during this time. However, biogas generation cannot be completely equalized throughout the year (Table 7-39); during the summer time the biogas production will be only 71% of the amount in the winter time. Table 7-38

Site 5: Available substrates and anticipated biogas production (annual mean)

substrates 1 cow slurry (liquid manure)1) 2 straw (in slurry)2) 3 potatoes biogas plant input mix 1)

mass flow t/a 16000 1170 500 17,670

DM

oDM

% 8 86 20 13.5

% 6.4 79.1 18.0 11.5

specific biogas yield % DM LN/kg oDM 80 350 92 320 90 560 85.5

slurry without litter; 1000 LU dairy cows, of which 50% are kept free range for 6 months

biogas pro- methane duction content m³/d % CH4 59 51 52 1932 55.1

2)

used as litter material for cows

75


Table 7-39 1 2 3

Site 5: Recommended substrate mix when cows are kept inside and while kept free range

substrates slurry straw (in slurry/ litter) potatoes biogas plant input mix DM input oDM input biogas production methane content

kg/d kg/d kg/d kg/d % % DM m³/d % CH4

while all cows housed (6 months/a) 55,249 4,040 59,289 13.3 85.3 2,260 55.4

50% of cows free range (6 months/a) 32,609 2,385 2,717 37,711 13.8 85.8 1,608 54.8

In order to avoid digester failure, dimensioning of the AD plant needs to take into account the higher material flows and higher gas production during the winter months. It has also to be considered that, besides reduced gas generation, the electrical efficiency of the CHP engine will be lower during the summer, as the engine is run on reduced power. This will further reduce the amount of electricity produced. Some intermittent slurry storage might further equalize biogas generation throughout the year, but large and expensive storage capacities would be necessary. In addition, it is preferable to digest slurry as fresh as possible, since stored slurry will yield significantly less methane.

7.5.2


Site 5 is proposing to use slurry collected from its own farms plus potato waste and spreading the digestate to its own farms. The digester exceeds the current limit of 1000 m³ for simpler permitting requirements, and also the thermal rated input from the biogas will be in excess of 0.4 MW (Table 7-40). The farm slurry which at present is being spread to land is classed as a non waste by-product, but is classified as waste after digestion because there has been further processing to recover biogas for the production of energy. The farm is not within a current or future NVZ. However, COGAP Soil Code 1998 advises maximum of 250 kg/ha total N per year. Table 7-40



7.5.3

Own feedstock & spreading digestate within farm > 1000 m³ digester & > 0.4 MW thermal rated input Environmental Permit Environmental Permit Free Para 12 Exemption if less than between 50 – 250 t/(ha * a)


Cow slurry should preferably be fed directly into the biogas plant, passing a reception pit. The suggested concept (Figure 7-9) includes a reinforced concrete reception pit of 90 m³. Potatoes should be added to the reception pit. A grinder pump is proposed, with this no special potato pre-treatment needs to be foreseen.

76


CHP unit

heat

electricity

feed-in




animal barns slurry

reception pit with mixer and grinder pump

solid substrates (potatoes)

Figure 7-9

1 digester heated, stirred, with gas holder, 38°C


Proposed AD Plant Scenario 5

A digester with 2669 m³ effective volume and digestate storage capacity for 182 days are included. The maximum organic loading rate of the digester is 2.5 kg oDM/(m³*d) and the minimum hydraulic retention time 43 days (Table 7-4). This is tolerable for manure plants, while energy crops or other energy rich substrates would require longer retention times, depending on their characteristics. No secondary digester is included in the concept. More details can be found in the Annex. Table 7-41

Scenario 5: Key Process Parameters

AD input DM-content input organic loading rate hydraulic retention time digestate production DM-content digestate

kg/d % kg oDM/(m³*d) d kg/d %

while stock inside (181 d/a) 59,289 13.3 2.5 43 56,445 9.1

stock free range (184 d/a) 37,711 13.8 1.7 67 35,688 9.0

The maximum digestate in 182 days is 9764 m³ (necessary storage capacity). For digestate storage, plastic sheeting Manure Bags/ Flexistores are chosen as a low cost option. Presently the animal barns are newly established. Slurry storage capacity is needed anyway. When building an AD plant, no extra slurry storage (or only a much reduced volume) would be necessary in the dairy units. However, without the AD project the farmer would probably decide in favour of a flushing system to remove manure followed by slurry storage under the barn, which is economically advantageous in the dairy unit. With an AD project, a more expensive scrape system would be necessary but there would be no requirement for slurry storage under the barns, which would reduce costs. Cost shifts in the planning of the new dairy barns are not taken into account in the assessment of the economic viability of the AD unit. Digestate cannot be stored under the barns. The following modelling includes full necessary digestate storage capacity and does not take into account possible cost savings within the dairy unit for reduced slurry storage requirements. The results of the economic modelling therefore indicate the viability of the AD unit in this case.The actual economic benefit of the whole farm would probably be better, since the dairy unit would save costs.

7.5.4


The capacity of the installed CHP unit needs to be high enough to cope with the higher gas generation during the winter months. The chosen 250 kW MAN engine would run on 90% of full power during half of the year and on 58% only during the other months. The annual mean efficiency degree, the

77


production of electricity and heat, and the energy amounts which can generate income are listed in Table 7-42. Table 7-42

Scenarios 5: Energy Generation (annual mean)





electricity 1461.66 127.16 23.39 1311.11

heat 1780.42 787.50 168.80 824.13



(= 44.2%)

1)


There are four potential heat consumers: the farm house, two cottages and an office building. Throughout the whole year enough biogas heat is produced to replace all other heat sources. It is assumed that 144.0 MWh/a heat can be used, which replaces 14,400 litres oil per year. Substrate inputs and material outputs of Scenario 5 are listed in detail in the Annex. The total amount of digestate cannot be spread to the arable land of the farm, but there is enough grass land for utilising the surplus digestate (Table 7-43). Slurry spreading equipment is already available on farm. Table 7-43 nutrients





1)


7.5.5

Economic Viability

Details on necessary investment costs, ongoing costs and income streams are given in the Annex. Costs represent full necessary AD costs, including digestate storage. No already available on-farm components are assumed. Table 7-44 summarises the results. This slurry based AD plant would generate a good Business Profit and would result in a fully acceptable Payback Period even without grant. The initial investment sum would be recovered within 8.1 years. The 10-year projection indicates an accumulated Business Profit of £407,270 for the total period (Figure 7-10). Scenario 5 has a sound economic basis indicated not only by an economic viability without grants. The sensitivity analysis (Table 7-46) underlines this finding. Even in worst case options there is still a buffer for acceptable payback periods.

78


Table 7-44

Summary Economic Modelling Site 5

Scenario 5


Manure Straw Vegetables Total

Annual mass flow [t/a] 16.000 1.170 500 17.670

cattle (liquid manure) straw (in slurry) stock feed potatoes

Main digester Amount: Effective digester volume: Organic loading rate (annual mean): Theoretical retention time (annual me After-Digester: Effective digester volume Organic loading rate: Theoretical retention time: Digestate Storage Effective storage volume: Retention time (annual mean): Mass reduction of input: Gas yield and gas utilisation: Biogas - yearly flow rate: Methane content CHP: Gas Engine Runtime of CHP unit: Demand of ignition fuel oil: Electric power: Electric efficiency of CHP: Electricity production: Demand of biogas plant: Transformation and feed-in losses Electricity for sale: Heat: Thermal efficiency of CHP: Heat production: Demand of biogas plant: Heat losses (from theor. avail. heat): Available heat for consumers: Actually used heat by consumers:

Daily mass flow [t/d] 43,84 3,21 1,37 48,41

DM

oDM

[%FM] 8% 86 % 20 % 13,5 %

[%DM] 80 % 92 % 90 % 85,5 %

Daily Input oDM [kg oDM/d] 2.805 2.536 247 5.588


1 2669 m³ 2,1 kg oDM/m³·d 53 d

Biogas Yield [L/kg oDM] 350 320 560


705.025 m³/a 55,1 % 250 kW 8.000 h/a 0 L/a 37,6 % 1.461.658 kWh/a 127.164 kWh/a 23.387 kWh/a 1.311.107 kWh/a 45,8 % 1.780.424 kWh/a 787.503 kWh/a 168.797 kWh/a 824.125 kWh/a 144.000 kWh/a


23.528 £/a 17.535 £/a 20.163 £/a 28.774 £/a 12.332 £/a £/a 9.411 £/a 6.312 £/a 14.032 £/a £/a £/a £/a


7.500 £/a £/a -1.083 £/a 18.750 £/a 6.810 £/a Business Profit/ Losses: Payback Period:

£/a 164.064 £/a

40.727 £/a 8,1 years

Revenue

10-year projection

1.500.000 £


1.000.000 £ 500.000 £


0£ -500.000 £


-1.000.000 £ -1.500.000 £ -2.000.000 £ 1 450.000 £ 400.000 £ 350.000 £ 300.000 £ 250.000 £ 200.000 £ 150.000 £ 100.000 £ 50.000 £ 0£

2

3

4

5 Year

6

7

Detail: Business Profit/ Losses 300.000£ 200.000£ 100.000£ 0£ -100.000£ -200.000£ -300.000£ -400.000£ -500.000£ -600.000£ -700.000£ -800.000£ 1

Figure 7-10

2009 5,5 4,5 4,5 0,0 14,5

Revenue from electricity 14,5 p/kWh 190.111 £/a Gate fees for waste £/a Revenue from heat usage 4,7 p/kWh 6.739 £/a Digestate fertiliser value (manure: improved fertiliser value only) N: Manure 12,0 ct/kg N 6.458 £/a N: Other biomass 56,0 ct/kg N 590 £/a P: 24,0 ct/kg P 273 £/a K: 23,2 ct/kg K 620 £/a Total revenue: 204.791 £/a

2.500.000 £ 2.000.000 £

Daily flow rate Daily flow rate biogas methane [m³/d] [m³/d] 982 579 812 414 138 72 1.932 1.065


m³ d

Methane content [%] 59 % 51 % 52 % 55,14 %


822.122 £ £ £ 822.122 £

#DIV/0!

9.680 m³ 7,3 months 5,0 %

Biogas Yield [m³/t FM] 22,40 253,18 100,80

2

3

4

5 6 Year

7

8

9 10

8

9

10



= recovery of initial invest 1

2

3

4 Year 5 6

7

8

9 10


A Payback Period of 5 years would be possible with 32% grant if 2 x ROCs could still be claimed (Table 7-45). However, with 1 x ROCs only, a significantly higher grant would be necessary to even 79


achieve a Payback Period of 8 years while the Business Profit for the farmer would still be lower than when refusing the grant and claiming 2 x ROCs, resulting in little attractiveness of any grant in this case. Table 7-45

Overview of Economic Viability and Grant Requirement in Scenario 5



Business Profit/Losses [£/a] +40,727




Necessary Grant to achieve a shorter Payback Period. Assumption: 2*ROCs still possible when taking the grant. Grant: 1% £4,111 163,614 204,791 +41,177 12.0% 6.3 8.0 32% £261,435 135,444 204,791 +69,347 19.4% 4.3 5.0 Necessary Grant to achieve a shorter Payback Period. Assumption: 1*ROCs only possible when taking the grant. Grant: 45% £373,244 123,204 145,792 +22,588 12.0% 6.3 8.0 63% £514,649 107,724 145,792 +38,068 19.4% 4.3 5.0

With this slurry based AD plant using very few left-over potatoes, substrate costs are of little influence (Table 7-46). Reduction of investment costs and a higher electricity value would result in significant further improvement of economic viability. Table 7-46



7.5.6

+/- 10% +/- 5% +/- 10% +/- 5% +/- 20% +/- 10% +/- 20% +/- 10% +/- 20% +/- 10% +/- 5%

Business benefits/ losses £/a difference to reference (+40,727) +/- 17,608 +/- 8,804 +/- 17,608 +/- 8,804 -/+ 24,973 -/+ 12,487 -/+ 1,500 -/+ 750 +/- 38,022 +/- 19,011 +/- 9,506


Recommendations

Site 5 clearly has very good potential for an AD facility. An AD plant can be fully recommended both with regards to economics and process technology. Even without any grant the biogas plant would be economically viable. Acceptance of a grant is only advisable if this does not endanger that 2 x ROCs can still be claimed. This slurry based AD plant has only very limited risk of any process imbalance. In addition, the environmental benefit of slurry based AD plants is to be considered. As mentioned above, the surplus Business Profit of the whole farm would be even higher than the calculated Business Profit of the AD unit, since the AD plant enables cost savings in the dairy unit when establishing the new dairy barns (reduced slurry storage requirement).

80


When planning the new barns, aspects related to the future biogas plant should already be considered. For higher gas yield the manure should be used as fresh as possible. It should be fed directly into the digester and after the digestion it should be stored. In order to remove the manure from dairy barns, a scrape system instead of a flush system should be chosen. The use of a flush system would result in dilution of manure and consequently larger and more expensive digesters and storage space. Complete equalisation of biogas generation throughout the year is not possible with the given substrates. Storage of large amounts of slurry prior to digestion is not recommended since it will be too expensive. A biogas plant at Site 5 could further profit from substrates especially available during the summer time, while a part of the breeding stock is kept free range. It should be carefully evaluated which additional substrates could be available for digestion and which technology would be required.

7.6 Site 6 (250 kW): A Pig Farm using Pig Slurry and Energy Crops 7.6.1


Site 6 is a pig farm with some beef cattle and some grass silage available. Possible biogas substrates are listed in Table 7-47. Biogas production should be equalized throughout the year; Table 7-48 compiles the relevant data. Table 7-47

1 2 3.1 3.2 4

Scenario 6: AD substrates and anticipated biogas production (annual mean)

substrates pig slurry washing water pigs beef cattle slurry1) straw in pig slurry2) straw in cattle slurry2) grass silage input mix AD plant

mass flow t/a 17500 1908 1500 100 100 1792 22,900

DM

oDM

% 6 0 12.5 86 86 25 8.1

% 4.9 0 9.9 79.1 79.1 22.0 6.8

specific biogas yield % DM LN/kg oDM 82 500 0 0 79 330 92 320 92 320 88 540 84.1

1)

biogas pro- methane duction content m³/d % CH4 60

2035

300 LU, ½ year outside, no slurry while stock free range; half of slurry passes weeping wall, half doesn’t

Table 7-48 1 2 3 4

59 51 51 54 57.6 2)

used as litter

Scenario 6: Biogas substrate throughout the year

substrates pig slurry washing water pigs beef cattle slurry straw (in slurry) grass silage biogas plant input mix DM input oDM input biogas production methane content

kg/d kg/d kg/d kg/d kg/d kg/d % % DM m³/d % CH4

while cattle inside (6 months/a) while cattle free range (6 months/a) 47,945 47,945 5,227 5,227 8,287 827 274 3,170 6,621 65,456 60,067 8.3 7.9 83.6 84.6 2035.4 2035.4 57.8 57.4

81


7.6.2


Site 6 is proposing to use slurries and silage collected from its own farm and spreading the digestate to its own farm. The digester size is > 1000 m³ and the CHP engine is > 0.4 MW thermal rated input. The farm slurry which at present being spread to land is classed as a non waste by-product, but is classified as waste after digestion as there has been further processing to recover biogas for energy production. The farmer will have to apply to the Environment Agency (Table 7-49). The farm is not within a current or future NVZ. However, COGAP Soil Code 1998 advises maximum of 250 kg/(ha*a) total N. Table 7-49



7.6.3

Using own feedstocks & spreading digestate within farm > 1000 m³ digester size & > 0.4 MW thermal rated input Environmental Permit Environmental Permit Free Para 12 Exemption if less than between 50 – 250 t/(ha*a)


Slurries and grass silage should be fed into the digester (effective volume 2,669 m³) after passing the reception pit (newly planned: 90 m³ in direct proximity to plant; in addition, there is already a 36 m³ mixing pit available and 5,630 m³ of slurry storage under the barn, which offers enough intermediate storage for the high slurry amount prior to the AD process). CHP unit

heat

electricity

feed-in




animal barns slurry


solid substrates (grass silage)

1 digester heated, stirred, with gas holder, 38°C

Proposed AD Plant Scenario 6

Table 7-50

Scenario 6: Key Process Parameters kg/d % kg oDM/(m³*d) d kg/d %

digestate storage landspreading

Figure 7-11

AD input Table 7-48 DM-content input organic loading rate hydraulic retention time digestate production DM-content digestate

digestate

while stock (beef cattle) inside (181 d/a) 65,456 8.3 1.7 39 62,896 4.6

stock free range (184 d/a) 60,067 7.9 1.5 42 57,507 3.9

For this slurry based plant the mimimum hydraulic retention time of 39 days is acceptable at this low organic loading rate (Table 7-50); no after-digester is included in the concept. Slurry storage under the 82


barns is not usable as storage for AD digestate. Only an 855 m³ steel slurry container is usable. In order to store digestate for 182 days, investment in extra storage capacity of around 10,000 m³ is foreseen.

7.6.4


The selected 250 kW MAN engine will run at 81% of full power. After self-consumption of the AD process and losses during transport and transformation, 1457.4 MWh of electricity and 820.7 MWh of biogas heat are available as potential revenue source (Table 7-51). There is particularly good potential for heat utilisation from biogas generation: 20 houses in the village and the farm pig unit currently consume 66,000 L oil per year for heating (= 660,000 kWh/a). Although the AD plant could deliver up to 820,650 kWh/a, there won’t be enough heat during the winter whereas during the summer there is surplus (for detailed heat balancing see in the Annex). The economic modelling assumes that 613,000 kWh/a biogas heat would be used. There is enough land for spreading the digestate (Table 7-52). Table 7-51






electricity 1617.56 134.26 25.88 1457.42

heat 1951.34 962.61 168.09 820.65



(= 49.3%)

1)


Table 7-52 nutrients



N: 117.40 t/a P2O5: 52.15 t/a K2O: 70.82 t/a N: 99.79 t/a P2O5: 52.15 t/a K2O: 70.82 t/a 21,965 t/a nutrientseff: 4.54 kg N/t; 2.37 kg P2O5/t; 3.22 kg K2O/t necessary: 399.2 ha (minimum for N250) available own farm: 200 ha arable land + 485 ha grass land

1)


7.6.5

Economic Viability

The modelling assumes a completely bank-financed AD plant. Aside from an already existing container which could be used for partial digestate storage (855 m³, which is only 8% of the necessary digestate storage capacity, and saves only £12,500 investment costs), no reduction of necessary investment is assumed. Slurry storage under the barns is not acceptable for digestate storage. For grass silage as AD feedstock, there is enough storage capacity already available for the indicated amount, so no investment in AD feedstock storage is assumed. With a Business Profit of nearly £50,000 per year at a Payback Period of below 8 years, economic viability of this AD project can be clearly achieved (Table 7-53). The projection forecasts that a total Business Profit of £495,940 can be achieved within 10 years (Figure 7-12). 83


Table 7-53

Summary of Economic Viability Scenario 6

Scenario 6


Manure Grass Straw (Water) Total

Annual mass flow [t/a] 1.500 17.500 1.792 200 1.908 22.900

beef cattle slurry (liquid) 0 pig slurry grass silage (general) straw (in slurry) washing (pigs)

Main digester Amount: 1 Effective digester volume: 2669 m³ Organic loading rate (annual mean): 1,6 kg oDM/m³·d 41 d Theoretical retention time (annual me After-Digester: Effective digester volume m³ Organic loading rate (annual mean): #DIV/0! Theoretical retention time (annual me d Storage: Eco/Manure Bags + usable Existing Effective storage volume: 10.922 m³ Retention time (annual mean): 6,3 months Mass reduction of input: 4,1 % Gas yield and gas utilisation: Biogas - yearly flow rate: 742.908 m³/a Methane content 57,6 % CHP: Gas Engine 250 kW Runtime of CHP unit: 8.000 h/a Demand of ignition fuel oil: 0 L/a Electric power: Electric efficiency of CHP: 37,8 % Electricity production: 1.617.557 kWh/a Demand of biogas plant: 134.257 kWh/a Transformation and feed-in losses: 25.881 kWh/a Electricity for sale: 1.457.419 kWh/a Heat: Thermal efficiency of CHP: 45,6 % Heat production: 1.951.338 kWh/a Demand of biogas plant: 962.606 kWh/a Heat losses (from theor. avail. heat): 168.085 kWh/a Available heat for consumers: 820.648 kWh/a Actually used heat by consumers: 613.620 kWh/a


DM

oDM

[%FM] 13 % 6% 25 % 86 % % 8,1 %

[%DM] 79 % 82 % 88 % 92 % % 84,1 %

Daily Input oDM [kg oDM/d] 406 2.359 1.080 434 0 4.278




Methane content [%] 59 % 60 % 54 % 51 % % 57,6 %

26.561 £/a 17.020 £/a 20.163 £/a 30.681 £/a 13.149 £/a £/a 10.624 £/a 6.127 £/a 15.529 £/a £/a £/a £/a


40.320 £/a £/a 2.401 £/a 18.750 £/a 7.355 £/a Business Profit/ Losses: Payback Period:

£/a 208.678 £/a

49.594 £/a 7,7 years

Revenue

10-year projection


1.500.000 £ 1.000.000 £ 500.000 £


0£ -500.000 £


-1.000.000 £ -1.500.000 £ -2.000.000 £ -2.500.000 £ 1

2

3

4

5 Year

6

7

Detail: Business Profit/ Losses 300.000£ 200.000£ 100.000£ 0£ -100.000£ -200.000£ -300.000£ -400.000£ -500.000£ -600.000£ -700.000£ -800.000£

500.000 £ 400.000 £ 300.000 £ 200.000 £ 100.000 £ 0£ 1

Figure 7-12

5,5 4,5 4,5 0,0 14,5

Revenue from electricity 14,5 p/kWh 211.326 £/a Gate fees for waste £/a Revenue from heat usage 4,7 p/kWh 28.717 £/a Digestate fertiliser value (manure: improved fertiliser value only) N: Manure 12,0 ct/kg N 8.644 £/a N: Other biomass 56,0 ct/kg N 4.367 £/a P: 24,0 ct/kg P 1.715 £/a K: 23,2 ct/kg K 3.502 £/a Total revenue: 258.272 £/a

2.000.000 £

600.000 £

2009


3.000.000 £ 2.500.000 £

Daily flow rate Daily flow rate biogas methane [m³/d] [m³/d] 134 79 1.179 708 583 315 139 71 0 0 2.035 1.172


876.590 £ £ £ 876.590 £



2

3

4

5 6 Year

7

8

9 10

8

9

10




1

2

3

4 Year 5 6

7

8

9 10


84


A grant of 30% on total investment requirement would reduce the Payback Period to 5 years if double ROCs would still be available (Table 7-54). With single ROCs however, any grant of below 17% would result in Business Losses and a minimum grant of 44% would be necessary to achieve a payback of 8 years. Taking a grant of 62% would reduce the payback to 5 years, but the Business Profit would still be lower than when refusing all grant and claiming 2 x ROCs instead. Table 7-54








Necessary Grant to achieve a shorter Payback Period. Assumption: 2*ROCs still possible when taking the grant. Grant: 30% £259,471 180,728 258,272 +77,544 19.6% 4.3 5.0 Necessary Grant to achieve a shorter Payback Period. Assumption: 1*ROCs only possible when taking the grant. Grant: 17% £148,451 192,687 192,688 +1 7.0% 9.3 13.8 44% £384,823 167,226 192,688 +25,462 12.2% 6.3 8.0 62% £540,856 150,418 192,688 +42,270 19.6% 4.3 5.0

Reduction of investment costs and a higher electricity value would result in significant further improvement of economic viability (Table 7-55). A 20% higher electricity value would nearly double the Business Profit and would reduce the Payback Period to below 6 years. A 20% reduction on necessary investment costs would reduce the Payback Period to a similar range but would not result in a comparable increase of Business Profit. Table 7-55



7.6.6

+/- 10% +/- 5% +/- 10% +/- 5% +/- 20% +/- 10% +/- 20% +/- 10% +/- 20% +/- 10% +/- 5%

Business benefits/ losses £/a difference to reference (+49,594) +/- 19,580 +/- 9,790 +/- 19,580 +/- 9,790 -/+ 26,336 -/+ 13,168 -/+ 8,064 -/+ 4,032 +/- 42,265 +/- 21,133 +/- 10,566


Scenario 6 - Option 2: Additional Energy Crops as AD Feedstock

It is one envisaged option at Site 6 to close the beef cattle business and to concentrate on cultivation of energy crops for biogas production. Up to 7,168 t/a of grass silage and 1,759 t/a of maize silage were indicated to be possible if there were no beef cattle kept anymore (Table 7-56).

85


Table 7-56

1 2 3 4

Scenario 6 – Option 2 (Additional Energy Crops): AD Substrates and Biogas Production

substrates pig slurry washing water pigs straw (in pig slurry) grass silage maize silage input mix AD plant

mass flow t/a 17500 1908 100 7168 1759 28,435

DM

oDM

% 6 0 86 25 30 12.2

% 4.9 0 79.1 22.0 28.2 10.6

specific biogas yield % DM LN/kg oDM 82 500 0 0 92 320 88 540 94 670 87.2

biogas pro- methane duction content m³/d % CH4 60

4492

51 54 52 55.1

The additional energy crops would require investment in extra storage capacity (silage clamps). A much larger AD facility would be necessary. It needs to be taken into account that compared to digestion of slurry longer hydraulic retention times are necessary for efficient digestion of energy crops and higher organic loading rates are achieved. AD processes run on high amounts of energy crops are less stable compared to slurry based processes. Energy crops are substrates with high costs and special attention should be paid not to loose any energy content due to process imbalance or too short retention in the system. In addition, practical experience of farmers has indicated that the size of the main digester should not significantly exceed 1,500 m³ when digesting high amounts of energy crops. Moreover, there is an increased risk of stratification in the digester at this site, due to the low DM-content of the pig slurry. For Scenario 6 – Option 2 two main digesters followed by an after-digester are proposed (Table 7-57). The after-digester can be taken into account as partial digestate storage, but additional digestate storage capacity is necessary. Details of the concept are given in the Annex. Table 7-57

Scenario 6 – Option 2 (Additional Energy Crops): Key Process Parameters

effective volume organic loading rate: hydraulic retention time:

m³ kg oDM/(m³*d) d

2 Main digesters 2 x 1,854 = 3,707 2.2 45

1 After-digester 2,760 1.4 37

The installed 499 kW CHP would run on 86% of full capacity. Despite much higher energy generation and a revenue of nearly £534,000 per year (which is more than twice the revenue of the first option), the Business Profit would be significantly lower compared to the option without additional energy crops. A Payback Period of more than 12 years is calculated (Table 7-58). The 10-year Business Profit would be below £200,000 (Figure 7-13). This example demonstrates that increasing the size of an AD plant does not necessarily result in higher Business Profit. Higher investment costs and higher substrate costs can outweigh the higher revenue from generated energy. It is not only the investment in the AD plant that needs to be taken into account. In particular necessary investment in feedstock storage (silage clamps) in this scenario has considerable effect on the reduced profitability.

86


Table 7-58

Summary Economic Modelling Scenario 6 – Option 2 (with additional energy crops)

Scenario 6 - Option 2: with 7.135 t/a additional energy crops Input

Manure Grass Maize Straw (Water) Total

12. August 2008

Annual mass flow [t/a] 17.500 7.168 1.759 100 1.908 28.435

pig slurry grass silage (general) maize silage straw (in slurry) washing (pigs)

Main digester Amount: 2 Effective digester volume: 3707 m³ Organic loading rate: 2,2 kg oDM/m³·d 45 d Theoretical retention time (annual me After-Digester (not heated): Effective digester volume 2760 m³ Organic loading rate: 1,4 kg oDM/m³·d Theoretical retention time: 37 d Storage (After-digester + Eco/Manure Bags + usable Existing) Effective storage volume: 12.477 m³ Retention time: 6,0 months Mass reduction of input: 7,3 % Gas yield and gas utilisation: Biogas - yearly flow rate: 1.639.722 m³/a Methane content 55,1 % CHP: Gas Engine 499 kW Runtime of CHP unit: 8.000 h/a Demand of ignition fuel oil: 0 L/a Electric power: Electric efficiency of CHP: 38,1 % Electricity production: 3.443.758 kWh/a Demand of biogas plant: 278.944 kWh/a (8,1 %) Transformation and feed-in losses: 55.100 kWh/a Electricity for sale: 3.109.714 kWh/a Heat: Thermal efficiency of CHP: 43,6 % Heat production: 3.940.889 kWh/a Demand of biogas plant: 1.243.032 kWh/a (31,5 %) Heat losses (from theor. avail. heat): 512.593 kWh/a ((19 % rel)) Available heat for consumers: 2.185.264 kWh/a (55,5 %) Actually used heat by consumers: 660.000 kWh/a

6.000.000 £ 5.000.000 £ 4.000.000 £ 3.000.000 £ 2.000.000 £ 1.000.000 £ 0£ -1.000.000 £ -2.000.000 £ -3.000.000 £ -4.000.000 £ -5.000.000 £ -6.000.000 £

oDM

[%FM] 6% 25 % 30 % 86 % % 12,2 %

[%DM] 82 % 88 % 94 % 92 % % 87,2 %


Daily Input oDM [kg oDM/d] 2.359 4.320 1.359 217 0 8.255


Costs substrates Transport digestate off-farm Costs land-spreading digestate own farm: Labour costs: 1996,0 h/a Other oper. costs: 1,0 % of investment costs without CHP Further costs (if any) Total costs:

Methane content [%] 60 % 54 % 52 % 51 % % 55,12 %

Daily flow rate Daily flow rate biogas methane [m³/d] [m³/d] 1.179 708 2.333 1.260 911 473 69 35 0 0 4.492 2.476


1.571.720 £ £ £ 1.571.720 £



2009


51.512 £/a 27.372 £/a 30.430 £/a 55.010 £/a 23.576 £/a £/a

5,5 4,5 4,5 0,0 14,5


Revenue from electricity 14,5 p/kWh 450.908 £/a Gate fees for waste £/a Revenue from heat usage 4,7 p/kWh 30.888 £/a Digestate fertiliser value (manure: improved fertiliser value only) N: Manure 12,0 ct/kg N 7.730 £/a N: Other biomass 56,0 ct/kg N 20.202 £/a P: 24,0 ct/kg P 8.137 £/a K: 23,2 ct/kg K 16.007 £/a Total revenue: 533.873 £/a

20.605 £/a 9.854 £/a 33.060 £/a £/a £/a £/a 205.255 £/a £/a 15.020 £/a 29.940 £/a 13.587 £/a


£/a 515.221 £/a

18.651 £/a 12,3 years

Revenue

Ongoing costs without write-off Total costs including write-off Benefits/ costs before write-off

2

3

4

5 Year

6

7

8

9

0£ -200.000£ -400.000£ -600.000£ -800.000£ -1.000.000£ -1.200.000£ -1.400.000£ -1.600.000£ 2

3

4

5 6 Year

7

8

9 10

10



Detail: Business Profit/ Losses

1

Figure 7-13

DM

10-year projection

1 200.000 £ 180.000 £ 160.000 £ 140.000 £ 120.000 £ 100.000 £ 80.000 £ 60.000 £ 40.000 £ 20.000 £ 0£



1

2

3 4 Year 5 6 7

8 9 10

10-year Cash Flow Projection Scenario 6 – Option 2

87


7.6.7

Recommendations

Scenario 6 based on pig slurry and a small amount of already available grass silage would clearly be economically viable. No grant would be necessary, although a grant could further encourage the farmer to invest in AD. However, even a high grant would be beneficial only in case that 2 x ROCs could still be claimed, otherwise all grant should be rejected. Closing the beef cattle unit and concentrating on energy crops would result in higher revenues from electricity sales, but the higher necessary investment (including silage storage capacity) and the high substrate costs would not allow higher Business Profit. The results of the economic modelling indicate a significantly longer Payback Period. In addition it needs to be taken into account that when deciding in favour of closing the beef cattle business, the farm will not have revenue from the beef unit anymore. This aspect is not considered in the economic modelling above, but it is relevant regarding the whole farm business. As a further option Site 6 indicated the possibility to take in further slurry amounts from the neighbourhood. Based on a first assessment (750 LU up to 3 km away, all kept free range for 6 months per year), this clearly would be advisable. As additional benefit, Site 6 could return digestate with improved fertiliser value to its neighbours. However, a more detailed feasibility study would be necessary to assess this option. The number of animals in the neighbourhood, the time for which the stock is kept free range, the distance to other farms, already available digestate storage capacity at neighbouring farms and further aspects all influence the result. If the farm decides to use manures from other farms then a Registered Exemption under Para 7, Environmental Permit, will be required, with conditions such as annual notification with certificate of benefit and risk assessment, secure storage away from water courses, and no more than 250 m³ digestate applied per Ha per annum. Some food waste could also be available at this site: yeast from a local brewery, pudding and whey. Although methane yields of those materials are high, they are not considered in the modelling. This would also require a more detailed feasibility assessment.

7.7 Site 7 (75 kW): A Cow Dairy Farm using Slurry, Manure and small amounts of Energy Crops 7.7.1


Site 7 is a farm which is embedded in a larger complex including facilities with educational and research purposes. There are different buildings, kitchens, farm land and animal barns. In Scenario 7, the biogas plant input is a mix of cattle slurry, horse manure and energy crops (Table 7-59). Sheep manure is not usable, as the animals are outside and the dung cannot be collected. Assuming that during the time when cows are kept free range the slurry amount drops to 20% of the amount which would be collected if cows where housed, complete equalization of biogas generation throughout the year is possible. Table 7-60 compiles the relevant data. Presently the dairy cow barns are newly established, which offers the possibility to integrate an AD plant in the concept.

88


Table 7-59

1 2 3 4 5 6

Scenario 7: Available substrates and anticipated biogas production (annual mean) mass flow t/a 4066 360 30 300 200 100 5056

substrates cattle slurry1) horse manure straw (in slurry)2) grass silage maize silage whole crop cereal biogas plant input mix

1)

dairy cows, kept free range for 230 days

Table 7-60 1 2 3 4 5 6

oDM

% 8 28 86 30 33 38 12.8

% 6.4 21.0 79.1 26.4 31.0 35.3 10.7



2)

used as litter material for cattle

Scenario 7: Biogas substrate mix when cows are kept inside and free range

substrates cattle slurry horse manure straw (in slurry/ litter) grass silage maize silage whole crop cereal silage biogas plant input mix DM input oDM input biogas production methane content

7.7.2

DM

kg/d kg/d kg/d kg/d kg/d kg/d kg/d % % DM m³/d % CH4

while cows inside (4.5 months/a) 22,384 986 165 38 26 13 23.612 9.5 80.3 629.1 57.9

while cows free range (7.5 months/a) 4,501 986 33 1,285 856 428 8.090 18.5 85.4 629.1 54.2


Scenario 7 is utilising cattle slurry, horse manure and energy crops collected from its own farm and spreading the digestate to its own farm. There is less than 0.4 MW thermal rated input from the biogas. The digester could be kept below 1000 m³; however according to our studies a larger reactor was the cheapest one available in the UK market. With a digester < 1000 m³ the farmer could apply to the Environment Agency for Exemptions for the complete AD facility and there would be no cost, but the larger digester would need an Environmental Permit (Table 7-61). Site 7 is not located within an NVZ. But COGAP Soil Code 1998 advises maximum of 250 kg/(ha*a) total N. Table 7-61



Own feedstock & spreading digestate within farm (> 1000 m³) digester & < 0.4 MW thermal input if > 1000 m³ Environmental Permit if < 1000 m³ Free Para 12 Exemption, includes storage of Manure & Slurry Free Para 5 Exemption Free Para 12 Exemption if less than between 50 – 250 t/(ha * a) If less than 50 t/ha a simplified procedure is used

If the site decides to use manures from another farm then a Registered Exemption under Para 7, Environmental Permit, will be required, with conditions such as annual notification with certificate of 89


benefit and risk assessment, secure storage away from water courses, and no more than 250 m³ digestate applied per ha per annum. If the site decides to use food waste from its own kitchens or from off-site, then the plant will come under ABP regulations and will require to pasteurise the materials, and undergo inspections from Animal Health Department.

7.7.3


This biogas plant would be the smallest unit in the range of scenarios within this study. A concept comparable to Scenario 1 is proposed (Figure 7-14). All substrates could be mixed in the 90 m³ reception pit. In order to assure pumpability of the material (DM-content < 12%), water and recyclate would need to be added to the mixing pit during the time when only little slurry is available as dairy cows are kept free range (Table 7-62). During months with high slurry availability no water or recyclate would need to be added. The digester with an effective volume of 1,184 m³ allows for a hydraulic retention time of 81 days during the months with high energy crops dosage, which is appropriate. The hydraulic retention time is reduced to 48 days during months with high slurry feeding and only little energy crops addition, which is acceptable. No secondary digester is necessary. CHP unit

heat

electricity

feed-in




animal barns slurry

solid substrates


dilution water



recyclate

Figure 7-14


Table 7-62


substrates Table 7-60 dilution water recyclate AD input incl. recyclate DM-content input organic loading rate hydraulic retention time digestate production*) DM-content digestate


while stock inside (135.5 d/a) 23,612 0,0 0,0 23,612 9.5 1.5 48 22,821 6.4

stock free range (229.5 d/a) 8,090 1,370 4,546 14,005 12.0 1.1 81 8,668 8.3

*)


The concept includes digestate storage capacity for minimum 182 days (maximum digestate in 182 days: 3,329 m³). It is worth mentioning that the annual mean digestate in 182 days is 2,413 m³ only. However, during winter months high amounts of slurry pass the plant and need storage after the process. The proposed storage capacity takes this into account. The modelling assumes that no additional storage capacity for the energy crop feedstock is necessary. 90


7.7.4


Among the available CHP units, the selected MAN engine with an installed electric capacity of 75 kW will run at 69% of full power. After self-consumption of the AD unit and energy losses (transport/ transformation), 373.4 MWh of electricity and 286.1 MWh of biogas heat would be available. In principle the buildings of the affiliated education/ research facilities offer good potential for biogas heat utilisation. There are two possible locations for the biogas plant: close to the affiliated buildings or close to the barns. It seems more favourable to build the AD plant next to the barns. Slurry could be fed directly into the biogas plant and there is no risk of odour nuisance for the other facilities. However, if the AD facility was placed in direct proximity to the dairy cow barns, the assumed distance to the heat consumers would be around 1 km. Heat supply would technically be feasible but the rather small amounts of available heat (especially in the winter months, for details see in the Annex) would economically not justify investment in heat pipes over this distance. The economic modelling assumes that only some of the heat (equivalent to 500 L oil) would be used in the nearby dairy unit (warm water heating, milking parlour). Presently, an electric boiler is used for water heating. Enough land is available for digestate spreading (Table 7-64). Table 7-63






electricity 415.81 35.76 6.65 373.40

heat 618.61 282.01 50.49 286.11



(= 45.6%)

1)


Table 7-64 nutrients





1)


7.7.5

Economic Viability

Economic viability is not given (Table 7-65). Within 10 years the calculated total Business Loss of this scenario accumulates to around £472,000 (Figure 7-15). Even without considering write-off, the AD unit would not even generate enough revenue to cover the ongoing costs (substrates, maintenance, labour, insurance etc.), see ‘Benefits/Costs before write-off’ in Figure 7-15. As a consequence, it would not be possible to pay back the bank credit, which results in higher bank debts throughout the years.

91


Table 7-65

Summary Economic Modelling Scenario 7

Scenario 7


Manure Grass Maize Straw Cereals Dilution Total

Annual mass flow [t/a] 4.066 360 300 200 30 100 314 5.370

cattle (liquid manure) 0 horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage dilution water


Daily mass flow [t/d] 11,14 0,99 0,82 0,55 0,08 0,27 0,86 14,71

DM

oDM

[%FM] 8% 28 % 30 % 33 % 86 % 38 % % 12,0 %

[%DM] 80 % 75 % 88 % 94 % 92 % 93 % % 83,0 %

Daily Input oDM [kg oDM/d] 713 207 217 170 65 97 0 1.469


1 1186 m³ 1,2 kg oDM/m³·d 64 d

Biogas Yield [L/kg oDM] 350 350 540 670 320 570 0



11.727 £/a 12.629 £/a 11.199 £/a 16.257 £/a 6.967 £/a £/a

2009 5,5 4,5 4,5 0,0 14,5

4.691 £/a 4.546 £/a 3.992 £/a £/a £/a £/a


23.085 £/a £/a 1.751 £/a 5.625 £/a 3.861 £/a BusinessProfit/ Losses: Payback Period:

£/a 106.331 £/a

-47.202 £/a -39,9 years

Revenue

10-year projection 500.000 £


0£

-1.000.000 £

Total costs including write-off Benefits/ costs before write-off

-1.500.000 £


-500.000 £

1 0£ -50.000 £ -100.000 £ -150.000 £ -200.000 £ -250.000 £ -300.000 £ -350.000 £ -400.000 £ -450.000 £ -500.000 £


Revenue from electricity 14,5 p/kWh 54.142 £/a Gate fees for waste £/a Revenue from heat usage 4,7 p/kWh 234 £/a Digestate fertiliser value (manure: improved fertiliser value only) N: Manure 12,0 ct/kg N 1.675 £/a N: Other biomass 56,0 ct/kg N 1.425 £/a P: 24,0 ct/kg P 608 £/a K: 23,2 ct/kg K 1.045 £/a Total revenue: 59.129 £/a

1.000.000 £

2

3

4

5 Year

6

7

8


9

10


-100.000£


-200.000£ -300.000£ -400.000£ -500.000£ -600.000£ -700.000£ 1

Figure 7-15

Daily flow rate Daily flow rate biogas methane [m³/d] [m³/d] 250 147 72 40 117 63 114 59 21 11 55 29 0 0 629 349


m³ d

Methane content [%] 59 % 55 % 54 % 52 % 51 % 53 % % 55,55 %


464.489 £ £ £ 464.489 £

#DIV/0!

3.423 m³ 8,5 months 5,4 %

Biogas Yield [m³/t FM] 22,40 73,50 142,56 207,83 253,18 201,44 0,00

2

3

4 Year 5 6

7

8

9 10

1

2

3

4 Year 5 6

7

8

9 10


92


A minimum grant of 91% would be necessary to bring this project into profitability (Table 7-66). However, if falling back on 1 x ROCs, not even a grant of 100% on total investment cost would allow any Business Profit. The sensitivity analysis (Table 7-67) does not indicate a potential to achieve profitability. Investment costs would need to be cut down to below £160,000, which does not seem within feasibility. The parameter ‘electricity value’ would need to be 83% higher (at 27.3 p/kWh) in order to allow avoid Business Losses, which currently seems not very realistic. Table 7-66

Grant Requirement Scenario 7




Return on Investment -3.2%


Payback Period [years] negative

Necessary Grant to achieve a shorter Payback Period. Assumption: 2*ROCs still possible when taking the grant. Grant: 91% £423,168 59,128 59,129 +1 7.0% 9.0 13.1 94% £435,551 57,747 59,129 +1,838 11.8% 6.3 8.0 96% £444,748 56,721 59,129 +2,409 19.2% 4.3 5.0 Necessary Grant to achieve a shorter Payback Period. Assumption: 1*ROCs only possible when taking the grant. Grant: < 100% 42,326 losses negative 100% £464,489 54,519 42,326 -12,192 0 0 Table 7-67


Reference (= Scenario 7) Electrical Efficiency Degree CHP or Gas Gas Production Investment Costs Substrate Costs Electricity Value

7.7.6

+/- 10% +/- 5% +/- 20% +/- 10% +/- 20% +/- 10% +/- 20% +/- 10% +/- 5%

Business benefits/ losses £/a difference to reference (-47,202) +/- 5,015 +/- 2,508 -/+ 14,376 -/+ 7,188 -/+ 4,617 -/+ 2,308 +/- 10,828 +/- 5,414 +/- 2,707

Payback period years negative neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg. neg./ neg.

Scenario 7 – Option 2 and 3: Taking in different amounts of food waste to the AD Plant at Site 7

It is one option to take in food waste to improve economic viability of an AD plant at Site 7. Higher electricity and heat production together with the incoming gate fees for accepting wastes considerably increase the revenue. Higher heat generation would justify transport of heat to the buildings in the education/ research area. The economic modelling assumes that biogas heat would be transported for 1 km from the plant to the main buildings, where it would replace 62,000 L of oil per year. However, when accepting food waste, the plant would come under the ABP regulation requiring hygienisation. The necessary hygienisation equipment results in much higher investment costs, details are given in the Annex. A potential amount of 1,000 food waste per year was indicated. This would not bring the AD project into economic viability (Table 7-68). With 4,000 t/a food waste, this scenario would be economically viable (Table 7-69). In order to achieve a minimum positive Business Profit, the economic modelling indicates that at least 2,800 t/a food waste would be necessary at this site. 93


Table 7-68

Scenario 7 – Option 2 (with 1,000 t/a Food Waste): Summary Economic Modelling

Scenario 7 + 1000 t/a food waste

12. August 2008

Input

Manure Grass Maize Straw Cereals Dilution Total

Annual mass flow [t/a] 4.066 360 300 200 30 100 1.000 314 6.370

cattle (liquid manure) 0 horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage 0 food waste dilution water


Table 7-69


DM

oDM

[%FM] 8% 28 % 30 % 33 % 86 % 38 % 28 % % 14,5 %

[%DM] 80 % 75 % 88 % 94 % 92 % 93 % 85 % % 83,6 %


1 1854 m³ 1,1 kg oDM/m³·d 88 d

Daily Input oDM [kg oDM/d] 713 207 217 170 65 97 652 0 2.121




32.154 £/a 48.479 £/a 11.946 £/a 45.795 £/a 19.627 £/a £/a

Dilution Total


12.861 £/a 17.452 £/a 7.031 £/a £/a £/a £/a


23.085 £/a £/a 3.373 £/a 7.800 £/a 18.372 £/a Business Profit/ Losses: Payback Period:

£/a 247.975 £/a

-79.905 £/a 103,2 years

Scenario 7 – Option 3 (with 4,000 t/a Food Waste): Summary Economic Modelling 12. August 2008

Input

Grass Maize Straw Cereals

2009 5,5 4,5 4,5 0,0 14,5

Revenue from electricity 14,5 p/kWh 95.361 £/a Gate fees for waste 45.000 £/a Revenue from heat usage 4,7 p/kWh 18.266 £/a Digestate fertiliser value (manure: improved fertiliser value only) N: Manure 12,0 ct/kg N 1.675 £/a N: Other biomass 56,0 ct/kg N 4.410 £/a P: 24,0 ct/kg P 1.717 £/a K: 23,2 ct/kg K 1.641 £/a Total revenue: 168.071 £/a

Scenario 7 + 4000 t/a food waste

Manure

Daily flow rate Daily flow rate biogas methane [m³/d] [m³/d] 250 147 72 40 117 63 114 59 21 11 55 29 300 180 0 0 929 529


m³ d

Methane content [%] 59 % 55 % 54 % 52 % 51 % 53 % 60 % % 56,99 %


1.308.441 £ £ £ 1.308.441 £

#DIV/0!

3.803 m³ 8,1 months 6,7 %


Annual mass flow [t/a] 4.066 360 300 200 30 100 4.000 1.129 10.185

cattle (liquid manure) 0 horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage 0 food waste dilution water



DM

oDM

[%FM] 8% 28 % 30 % 33 % 86 % 38 % 28 % % 17,3 %

[%DM] 80 % 75 % 88 % 94 % 92 % 93 % 85 % % 84,3 %


1 2669 m³ 1,5 kg oDM/m³·d 84 d

Daily Input oDM [kg oDM/d] 713 207 217 170 65 97 2.608 0 4.077

1.631.621 £ £ £ 1.631.621 £

m³ #DIV/0! d


5.063 m³ 6,8 months 8,2 % 667.533 m³/a 58,5 % 250 kW 8.000 h/a 0 L/a 37,8 % 1.475.336 kWh/a 126.879 kWh/a 23.605 kWh/a 1.324.852 kWh/a 46,1 % 1.799.286 kWh/a 536.894 kWh/a 186.873 kWh/a 851.311 kWh/a 610.346 kWh/a

43.975 £/a 50.914 £/a 20.163 £/a 57.107 £/a 24.474 £/a £/a 17.590 £/a 18.329 £/a 14.163 £/a £/a £/a £/a



Methane content [%] 59 % 55 % 54 % 52 % 51 % 53 % 60 % % 58,47 %

Daily flow rate Daily flow rate biogas methane [m³/d] [m³/d] 250 147 72 40 117 63 114 59 21 11 55 29 1.200 720 0 0 1.829 1.069

Revenues: Year of commissioning: Wholesale electricity price ROC Second ROC Others Total electricity value

2009 5,5 4,5 4,5 0,0 14,5


Revenue from electricity 14,5 p/kWh 192.104 £/a Gate fees for waste 180.000 £/a Revenue from heat usage 4,7 p/kWh 28.564 £/a Digestate fertiliser value (manure: improved fertiliser value only) N: Manure 12,0 ct/kg N 1.675 £/a N: Other biomass 56,0 ct/kg N 13.367 £/a P: 24,0 ct/kg P 5.043 £/a K: 23,2 ct/kg K 3.429 £/a Total revenue: 424.181 £/a


23.248 £/a £/a 12.443 £/a 18.750 £/a 22.357 £/a £/a 323.514 £/a


100.667 £/a 7,6 years

94


7.7.7

Recommendations

Without high grant the AD process based on substrates from the own farm in Scenario 7 would not be economically viable. In addition to farm substrates, a small quantity of vegetable waste/ kitchen waste from affiliated facilities and from schools in the village might be available. Higher revenue is generated when accepting food waste for digestion, but necessary surplus investment for food waste tretament needs to be taken into account. The economic modelling indicates a minimum of around 3,000 t/a food waste needs to be available on long terms in order to assure a minimum profitability. Planning of the new barns should consider some aspects related to the biogas process. No slurry storage under the barns should be foreseen. Slurry should be fed directly into the digester. In order to remove the manure from dairy barns, a scrape system instead of a flush system should be chosen. The use of a flush system would result in dilution of manure and significantly larger and more expensive digesters and end storage. Comparable to Scenario 5, the economic modelling does not take into account possible cost reductions in the dairy unit. Since the animal barns currently are newly estabilshed, an AD plant offers the possibility to foresee less slurry storage capacity in the dairy unit, as slurry would be fed into the digester and stored after digestion. However, without AD the farm would probably decide in favour of a flushing system to clean the barns, which in the dairy unit is economically more favourable than a scrape system, but would hardly be acceptable for the AD project. It would require a more detailed feasibility study to take into account cost shifts in the dairy unit and balance the whole farm business profit. A biogas plant at this site could be of additional benefit for the future development of AD in Cornwall. The affiliated education/ research facilities assure that many visitors get into contact with AD technology which could inspire farmers to decide in favour of a biogas plant at their own farm.

7.8 Site 8 (861 kW): A Community Based AD Plant digesting Wastes, Slurry and Energy Crops At Site 8, a community based biogas plant is envisaged. Potential substrates are sewage sludge from the municipal water purification plant, fish waste, different food wastes and by-products from food processing, and slurry and energy crops from farms in the surrounding.

7.8.1

Preliminary Note: Co-digestion of Sewage Sludge with other Substrates

In the UK, co-digestion of sewage sludge with food residues from municipal waste was trialled by Thames Waste Management in the late 90’s through to 2002. However when the Animal By-Products Legislation came into force, it was decided that mixed sourced food waste was no longer acceptable for application to farmland; source separation was required. It was still acceptable to spread sewage sludge from water treatment plants because this came under the EU Water Directive and the specific regulations affecting sludge, as listed in Chapter 3.6. The requirement for pasteurisation also presented design difficulties for existing plants. Hence there has been no development of co-digestion of food waste and sewage sludge for the past five years. 95


Other factors are that the original driver for water treatment works to co-digest was that they had spare digester capacity that could be taken up by new food wastes, however new trends in AD in the water industry are tending towards shorter retention times which do not suit other wastes. In recent years there has also been a trend towards thermal treatment of sludges. Although it is technically feasible to co-digest sewage sludge with food wastes for landspreading to farmland, in practice the plant would have to work under two separate regulatory regimes, the Water Framework Directive for sewage sludge and Environmental Permitting for other wastes (see Chapter 3, in particular Chapter 3.6 for sewage sludge and Chapter 3.3 for other wastes). This has not been successfully tried in the UK, and the cost of the administration of such a scheme would be very high in comparison to the value of the energy and nutrients from the sewage sludge. However, since crops grown for digestion are not classed as wastes, these could be mixed with sewage sludge, so coming under regulations for the latter only. Alternatively, the sludge could be excluded in the community based digestion plant, so that the Environmental Permitting regulations would apply. Food buyers from major retailers are also becoming increasingly reluctant to accept crops grown on land on which sewage sludge has been spread, although this is a marketing issue rather than a real health risk. In conclusion, it is recommended that sewage sludge is not co-digested with other wastes.

7.8.2


Table 7-70 compiles AD substrates for Scenario 8. It is recommended to carry out precise waste analyses before taking key decisions in this project. For the economic modelling of this study waste material characteristics including gas yields are taken into account as they were indicated by Site 8 (according to results of a pre-study). Sewage sludge was excluded as AD input (Chapter 7.8.1). Cardboard was mentioned as possible additional substrate at costs of £30/t. Cardboard is not considered in the modelling; it is not particularly favourable in the AD process. In addition, availability of some pastry waste at gate fees of £20/t was mentioned; this would be favourable, however it could not be considered anymore in the modelling. For fish waste and meat waste gate fees of £40/t and for food waste and depackaged food waste gate fees of £30/t are considered as revenue in the modelling; gate fees were indicated by Site 8. Table 7-70

1 2 3 4 5 6

Scenario 8: AD substrates and anticipated biogas production (annual mean)

substrates cow slurry maize silage meat waste fish waste food waste depackaged food waste biogas plant input mix

mass flow t/a 31,200 7,300 2,080 150 300 1,500 42,530

DM

oDM

% 10 29 25 30 25 25 14.7

% 8.0 27.3 20.0 24.0 20.0 20.0 11.5



According to the information received from Site 8, silage costs would be at £35/t. For slurry collection annual costs of £31,200 were given. For digestate delivery £46,530 are assumed in the following.

96


7.8.3

Plant Design and Equipments, Digestate Management

Co-digestion of the mentioned waste streams brings this plant under the ABP Regulations requiring pasteurisation of the materials (see Chapter 3.2). The pre-treatment facilities need to include waste reception, control and conditioning followed by pasteurisation. The level of contamination of substrate has not been included in this study. The proposed AD unit includes two main digesters offering a total digestion volume of 5,338 m³ (effective volume after allowing for a freeboard of 0.5 m) followed by one After-Digester with an effective volume of 2,760 m³ (Table 7-71). The total hydraulic retention time in the system is 69 days. Table 7-71


Annual AD throughput DM-content input (annual mean) 2 main digesters, effective volume: Organic loading rate (annual mean) Hydraulic retention time (annual mean) 1 After-digester (heated), effective volume: Organic loading rate (annual mean) Hydraulic retention time (annual mean) Annual digestate production DM-content digestate Digestate in 182 days (mean) Planned digestate storage capacity:

t/a % kg oDM/(m³*d) d kg oDM/(m³*d) d t/a m³/a % m³

42,530 14.7 2 x 2,669 = 5,338 m³ 2.5 44 2,760 m³ 2.1 25 39,218 37,350 7.7 18,624 4 x 4,410 = 17,640 m³

Digestate production within 182 days is calculated at 18,624 m³. Some storage is probably available at the neighbouring farms which supply the fresh slurry. The economic modelling assumes investment in digestate storage of 17,640 m³ which itself offers storage capacity for 172 days. In case there is not enough space available directly at the AD plant location, it is recommended to build digestate storage capacity off-site or possibly on land of cooperating farms. Digestate should be spread to land. Nutrients and possible contaminations of the incoming waste streams should be determined. The economic modelling assumes nutrient contents for all waste materials according to an average literature figure (see Annex). The digestate fertiliser value is determined with £4.65 per tonne digestate, which already includes 15% losses of nitrogen during transport/ storage/ spreading. This results in a total value of £182,208 per year in digestate. Of this however, £126,645 originate from slurry taken in from farmers, resulting in a difference of £55,563 from additional substrates (maize, waste). In order to encourage neighbouring farmers to cooperate on long terms with the centralised AD plant, it is recommended not to charge any costs for the digestate. Cooperation of neighbouring farmers is an important aspect on the viability of this scenario. Farmers contribute slurry and silage as input substrates and spread the digestate to their land. Offering farmers an additional benefit is of advantage for the partners, both the farmers and the AD plant.

7.8.4

Energy Production

For the valorisation of biogas a CHP unit equipped with a Jenbacher gas engine and an installed electrical capacity of 861 kW is selected. After self-consumption of the AD process and the hygienisation unit, and losses during energy transportation/ transformation, 5092.5 MWh/a electricity and 3288.8 MWh/a biogas heat would be available. Within a distance of 1.2 km it is assumed that 97


potential customers require 3,000 MWh/a of heat, which is equivalent to 300,000 L oil for heating (60 to 100 houses). However, during the winter months there will be too little heat from the AD facility to cover all demand. Both the self-consumption of the AD plant and the heat demand from customers are higher during this time. During the summer months however, there will be surplus biogas heat. Details on the assumed heat balancing are given in the Annex. The calculation results in a total biogas heat utilisation of 2741.3 MWh/a, which would displace 274,130 L oil per year. Table 7-72



1,474,083 m³/a installed capacity: 861 kWel electrical 38.6%

Energy content: 14,740.8 MWh/a runtime: 8000 h/a at 82.6 % of full power thermal 47.1%

Generation Demand AD + hygienisation Losses1) Available surplus

electricity 5689.96 506.41 91.04 5092.51

heat 6942.93 2882.71 771.44 3288.78



(= 41.5%)

1)


7.8.5

Economic Viability

Scenario 8 is economically viable (Table 7-73). With a Payback Period of 10.3 years, the average annual Business Profit of £75,692 accumulates to more than £750,000 within 10 years (Figure 7-16). Table 7-73

Summary Economic Modelling Scenario 8 12. August 2008

Scenario 8 Input

Manure Maize Wastes

Total

cow slurry (liquid) maize silage meat waste 0 fish waste 0 food waste 0 depackaged food waste

Annual mass flow [t/a] 31.200 7.300 2.080 150 300 1.500 42.530

Main digester Amount: 2 Effective digester volume: 5338 m³ Organic loading rate: 2,5 kg oDM/m³·d Theoretical retention time (annual me 44 d After-Digester (heated): Effective digester volume 2760 m³ Organic loading rate: 2,1 kg oDM/m³·d Theoretical retention time: 25 d Storage (Eco/Manure Bags Flexistore) Effective storage volume: 17.640 m³ Retention time: 5,7 months Mass reduction of input: 7,8 % Gas yield and gas utilisation: Biogas - yearly flow rate: 2.632.887 m³/a Methane content 56,0 % CHP: Gas Engine 861 kW Runtime of CHP unit: 8.000 h/a Demand of ignition fuel oil: 0 L/a Electric power: Electric efficiency of CHP: 38,6 % Electricity production: 5.689.961 kWh/a Demand of biogas plant: 506.406 kWh/a (8,9 %) Transformation and feed-in losses: 91.039 kWh/a Electricity for sale: 5.092.515 kWh/a Heat: Thermal efficiency of CHP: 47,1 % Heat production: 6.942.931 kWh/a Demand AD plant and hygienisation: 2.882.708 kWh/a (41,5 %) Heat losses (from theor. avail. heat): 771.442 kWh/a ((19 % rel)) Available heat for consumers: 3.288.780 kWh/a (47,4 %) Actually used heat by consumers: 2.741.278 kWh/a

Daily mass flow [t/d] 85,48 20,00 5,70 0,41 0,82 4,11 116,52

DM

oDM

[%FM] 10 % 29 % 25 % 30 % 25 % 25 % 14,7 %

[%DM] 80 % 94 % 80 % 80 % 80 % 80 % 78,4 %



Costs substrates incl. collection costs Delivery costs Labour costs: 3444,0 h/a Other oper. costs: 1,5 % of investment costs without CHP Further costs (if any) Total costs:

Daily Input oDM [kg oDM/d] 6.838 5.452 1.140 99 164 822 13.430

3.157.036 £ £ £ 3.157.036 £

86.176 £/a 82.841 £/a 62.774 £/a 110.496 £/a 47.356 £/a £/a 34.470 £/a 29.823 £/a 54.624 £/a £/a £/a £/a

Biogas Yield [L/kg oDM] 350 670 450 450 460 650

Biogas Yield [m³/t FM] 28,00 182,64 90,00 108,00 92,00 130,00

Methane content [%] 59 % 52 % 60 % 60 % 60 % 65 % 55,99 %

Daily flow rate Daily flow rate biogas methane [m³/d] [m³/d] 2.393 1.412 3.653 1.899 513 308 44 27 76 45 534 347 7.213 4.039

Revenues: Year of commissioning: Wholesale electricity price ROC Second ROC Others Total electricity value

2009 5,5 4,5 4,5 0,0 14,5


Revenue from electricity 14,5 p/kWh 738.415 £/a Gate fees for waste (as indicated by the site) 143.200 £/a Revenue from heat usage 4,7 p/kWh 128.292 £/a Digestate fertiliser value not considered. Assumption: digestate is offered to farmers without any costs. Actual fertlizer value: 4,6 £/t digest. (182.208 £/a) (of this originat. from slurry: 126.645 £/a) Total revenue:

1.009.906 £/a

286.700 £/a 46.530 £/a £/a 51.660 £/a 40.764 £/a £/a 934.214 £/a

Business Profit/ Losses: Payback period:

75.692 £/a 10,3 years

98


15.000.000 £

Revenue

10-year projection 10.000.000 £


5.000.000 £


0£ -5.000.000 £


-10.000.000 £ -15.000.000 £ 1 800.000 £

2

3

4

5 Year

6

7

8

10


Detail: Business Profit/ Losses

700.000 £

0£

600.000 £

-500.000£

500.000 £

-1.000.000£

400.000 £ 300.000 £

-1.500.000£

200.000 £

-2.000.000£

100.000 £

-2.500.000£


-3.000.000£

0£ 1

Figure 7-16

9


2

3

4

5 6 Year

7

8

9 10

1

2

3 4 Year 5 6 7

8 9 10


A grant of around £532,000 (17% of total investment costs) would reduce the Payback Period to 8 years if double ROCs could still be obtained (Table 7-74). A 5-year Payback Period would require 43% grant. However, if falling back on single ROCs, all grants below 45% would not even allow a minimum Business Profit but would result in Losses. A Payback Period of 8 years would require 63% grant (nearly £2,000,000), while the Business Profit of the project would still be lower than when refusing all grant and claiming double ROCs instead. Table 7-74

Grant Requirement Scenario 8

Total Investment Costs: £3,157,036 Without grant:

Operation/Main Revenue tenance/Capital [£/a] Costs [£/a] 934,214 1,009,906





Necessary Grant to achieve a shorter Payback Period. Assumption: 2*ROCs still possible when taking the grant. Grant: 17% £531,961 876,539 1,009,906 +133,368 12.1% 6.3 8.0 43% £1,363,524 786,380 1,009,906 +233,526 19.5% 4.3 5.0 Necessary Grant to achieve a shorter Payback Period. Assumption: 1*ROCs only possible when taking the grant. Grant: 45% £1,415,523 780,742 780,743 +1 7.0% 9.2 13.6 63% £1,973,148 720,285 780,743 +60,459 12.1% 6.3 8.0 74% £2,346,941 679,758 780,743 +100,986 19.5% 4.3 5.0

Investment cost reduction has potential to further increase the anticipated Business Profit (Table 7-75). On the other hand, at 20% higher necessary investment costs no Business Profit would be able anymore (£75,692-98,940 = -23,248). Also the electrical efficiency of the CHP unit and the actual gas 99


production are of significant influence. With 10% less efficiency or 10% lower gas production nearly no Business Profit would be left. As in all other scenarios, the value of electricity is of decisive influence. A 10% higher value would nearly double the Business Profit. A 20% higher electricity value, which would than be at 17.4 p/kWh, would triple the average annual Business Profit to £223,375 (=75,692+147,683). Table 7-75


Reference (= Scenario 8) Electrical Efficiency Degree CHP or Gas Production Investment Costs Substrate Costs Gate Fees Electricity Value

7.8.6

+/- 10% +/- 5% +/- 20% +/- 10% +/- 20% +/- 10% +/- 20% +/- 10% +/- 20% +/- 10% +/- 5%

Business benefits/ losses £/a difference to reference (+75,692) +/- 68,379 +/- 34,190 -/+ 98,940 -/+ 49,470 -/+ 57,340 -/+ 28,670 +/- 28,640 +/-14,320 +/- 147,683 +/- 73,841 +/- 36,921


Recommendations

It is recommended not to digest sewage sludge together with wastes from food processing, slurry and energy crops (Chapter 7.8.1). The regulatory regime is complicated and it might on longer terms be possible that spreading sewage sludge to land, even after digestion, will not be allowed anymore, a development which currently takes place in Europe. The digestate blend of an AD facility treating both sewage sludge and other materials would than need to be completely excluded from being spread to agricultural land. This would not only result in high amounts of wastes to be disposed off, but would also create a system with considerable constant losses of valuable nutrients originating from materials such as maize silage or food waste. The best possible solution for the sewage sludge will be a combination of ‘material utilisation’ (fertiliser) for as long as possible and disposal or ‘thermal valorisation’ (exogenous combustion or other thermal processing after water content reduction) if required. Reducing the water content of the wet sludge by thickening or dewatering (gravitational or mechanical processes such as centrifuges, presses, vacuum filtration), in any case means lowering transport costs. Drying is further beneficial. Dried sewage sludge can easily be used as organic fertiliser and would be appropriate for thermal processing as well. Sewage sludge drying in general is expensive and only viable with higher throughputs. In addition, problems resulting from self-inflammation of dry sludge occur and need special attention and expensive provision. As a low-cost option, which is robust, reliable and particularly favourable for small sludge throughputs, floor-heated solar drying (in membrane covered greenhouse) is recommended. Biogas heat from the AD facility in Scenario 8 would be valorised in the floor-heating. Leading international companies are Hans Huber AG (www.huber.co.uk), and Thermo-System GmbH (www.thermo-system.com). The first one is already present in the UK market and the latter indicated 100


interest in UK projects. Within this project, Hans Huber AG placed a complete offer including necessary investment in facilities for sludge dewatering, drying, earth work, labour costs, plus ongoing costs and thermal and electrical energy requirements. The offer is not part of this report. The studied AD scenario is based on digestion of slurry, maize silage, food processing wastes and food wastes. The economic modelling indicates that economic viability is given. A grant of 20% would reduce the payback period to below eight years and would facilitate decision in favour of this project. Utilisation of electricity on-site could increase the electricity value and would further improve viability of the scenario. This however requires more detailed feasibility studies. However, it needs to be pointed out that due to the very limited time of this project a basic study only was possible within this piece of work. As mentioned above, the sensitivity analysis indicates that 20% higher necessary investment costs would bring this project from profitability into losses. Offers from companies varied greatly and even much higher costs were given. This community based AD plant would generate additional benefits. Environmental aspects include greenhouse gas reduction by renewable energy generation and valorisation of waste materials together with reduced transport for mostly local waste materials. It also opens an additional market for local farmers. In addition, the economic modelling includes labour costs of approximately £52,000 per year. It is recommended to offer all digestate without any costs to cooperating farmers in order to assure their willingness to cooperate on long terms. Slurry and energy crop availability, and agricultural digestate acceptance, are key success factors in this scenario. All waste materials should be analysed in detail before further planning. This should include analysis such as DM-content, oDM-content, nutrients, contaminations but also determination of the total methane potential. Only then a detailed feasibility together with the detailed technology description can be given.

101


8 Recommendations to Future Rural Biogas Plant Operators 8.1 On-farm AD and the Farm Management 8.1.1

Integration of a Biogas Plant into the Farm Concept

Digestion of slurry, manure and organic wastes, and where possible co-digestion of energy crops such as grass, maize, whole crop silage, can become a source of additional income for farmers and at the same time contributes towards a more sustainable national energy concept. In addition, anaerobic digestion improves the fertiliser value of the processed substrates and significantly reduces odour emissions. If well integrated into the farm concept, the biogas plant has mostly positive interactions with the rest of the farm business. This includes the supply of feedstock, provision of digestate offsetting fertiliser cost, use of labour in slack time of the farming year and cheaper supply of heat. Investment in a biogas plant is long-term fixed and should be carefully assessed. It is not possible to fix a financially stricken farm business through a biogas plant. For the project financier, which is usually a bank, not only the usual credit examinations as credit-worthiness, solvency are of crucial interest, but also the technical feasibility and especially the assessed economic viability of the planned plant, and also the integration of the AD project into the business shape.

8.1.2

General Technical Recommendations concerning Farm Management

When barn systems are newly established, some aspects relevant for biogas production should already be taken into account. The use of flush systems to remove the manure from dairy barns can have economic advantages within the dairy unit and is less labour-intensive than other systems. In addition, flush systems remove practically all of the manure, while water-free systems do not clean the barns as efficiently. However, dilution of manure with water will require significantly larger and therefore more expensive AD facilities. Dilution can also increase the stratification risk within the digester, with straw or other lignocellulosic material forming a thick mat on top, while sand accumulates at the bottom [Burke, 2001]. Scrape systems are more favourable. They collect the manure by scraping it to a sump without changing its consistency. Slurry should be fed directly into the digester. The common storage place under the barn is therefore unsuitable as a pre- and after-storage space. A weeping wall is also not necessary. Any gravity separator will remove an amount of degradable organic material that could be converted into biogas. In addition, the separation process alters the carbon to nitrogen ratio of the streams. While a significant proportion of the organic carbon is retained with the separated solids, an equal percentage of the nitrogen and phosphorus is not. Up to 80% of the COD and 30% of the total nitrogen and phosphorus can be found in the solids removed by a screen and sedimentation process [Burke, 2001]. If possible and economically feasible, the farm management should strive to use litter material favourable in the digestion process. Woody material does not generate significant amounts of biogas. Straw is more favourable than wood shavings or sawdust. Straw should be chopped prior to using it as litter material in the stable. Sand will clog pipes, damage equipment and fill the digestion tank. Slurry retains sand that precipitates in the digester when organics are degraded and the solids concentration is 102


reduced. If the presence of sand cannot be avoided, equipment for sand removal needs to be foreseen in the AD concept, which increases the necessary investment costs. With sand accumulating at the bottom of a fermenter, the effective digester volume will continuously be reduced, which can have negative effects on process stability. Agricultural biogas production has the advantage of generating a digestate with improved fertiliser value and being low in pollutants, which facilitates its valorisation. However, since most of the nitrogen is available in the form of ammonia, digestate spreading technologies should be given special attention. Ammonia losses should be kept to a minimum. The air pollutant ammonia (NH3), causing terrestrial eutrophication, originates mainly from the agricultural sector, and most of it comes from manure and slurry. In the UK, more than 80% of ammonia comes from agriculture and nitrogen enrichment threatens about a third of valuable UK ecosystems [Defra, 2002b].

8.2 Planning and Approval 8.2.1

Decision-making Criteria

In order to make a sustainable decision, a potential biogas plant operator should be well-informed about technical issues, biological issues, financial aspects and regulatory framework implications. In addition to information from literature, the future plant operator can participate in study tours or in a biogas training course. A future biogas plant operator should be well aware of the fact, that no AD plant is a stand-alone unit but it will require continuous attention. The planning of the plant should be as detailed as possible and sufficient time should be allowed before taking decisions. The situation of the farm business should be analysed in detail and the future biogas plant operator should have information about the available technical systems on the market and about the different configurations of the installations. Conversation with several providers should take place. Available substrates should be determined as precisely as possible because they are the basis for the further planning process, including the necessary approval procedure and the offers from biogas plant suppliers. A detailed feasibility study is favourable prior to taking decisions. Analysis of the available substrates such as chemical analysis and determination of the potential biogas yield provide a better planning basis. It is favourable to decide in favour of technologies from companies which provide support and process guarantees. The percentage of operating time of the CHP unit is crucial. Yeatman [2007] assessed that full support from the technology provider raises the generator running time from an industry average of 65% to over 90%.

8.2.2

Co-digestion of Wastes

An agricultural biogas plant operator needs to decide if he is willing to take in wastes to his farm. Codigestion of food waste will bring the plant under ABP regulations (Chapter 3.2), which require pasteurisation of the materials. Treatment of wastes therefore needs extra equipment, but it can be economically viable. Besides higher investment costs (mainly due to the necessary hygienisation

103


technology), co-digestion also requires more regular analysis of the AD process. All incoming wastes need to be controlled. However, co-digestion of wastes can be beneficial due to two revenue streams:

additional revenue from increased gas yield

gate fees

Results of Scenario 7 of this study indicate that when taking in food waste to an agricultural AD plant, at least 3000 t/a should be available in order to justify the higher investment costs. Gate fees will vary according to waste type and local or regional outlets. Gate fees for green waste range between £20 and £45 and for food waste they are upwards of £45 [Andersons, 2008]. WRAP has assessed that 6.7 million tonnes of household food waste is produced each year in the UK [WRAP, 2008]. Without source-separation, most of this household food waste will hardly find its way to an agricultural AD plant. Food waste from supermarkets, catering waste from restaurants and hotels and residues from food processing are examples of possible substrates for on-farm AD. Further potential substrates include: apple/ cereal mash (distillery waste), yeast, fruit/ grape pomace, grain cleanings, molasses, oilseed cake, potato mash/ peals, whey, old bread, bakery waste, meat waste, bowel contents, vegetable leftovers, food leftovers, fat from deep fryer. In order to avoid process problems and assure that the digestate is of sufficient quality to be spread to land, agricultural biogas plants should reject material containing plastics, metals or woody components, see Chapter 4.5.

8.2.3

Optimisation of the Approval Procedure and Connection to the Grid

The future biogas plant operator should be aware of the relevant regulatory regulations and the necessary licences. Chapter 3 provides an overview. It is important to contact the Local Authority Planning Department at an early stage and involve them in the selection of the location, types and amounts of substrates and wastes involved, transport movements, and details of the process. The Local Authority will assess the application and might carry out a consultation with local stakeholders. Good cooperation with the Local Authority will facilitate the approval procedure. Concerning connection to the power grid, contact with the Distribution Network Operator (DNO) which in Cornwall is Western Power Distribution (WPD) in the early development stages of a renewable energy generation project is extremely important to ensure that the desired connection date can be met. It can typically take several months from first contact with WPD to the actual energisation of the connection (see Chapter 5). If grid reinforcement is found to be necessary, there is (unlike in many other countries) no possibility to connect the AD plant to the grid before completion of the reinforcement, which may cause delays. For connection to the grid, a higher capacity should be applied for during the planning phase than the actual calculated capacity of the installations. The DNO will carry out a feasibility study and any necessary reinforcement of the grid before the connection is possible. There are costs associated with the staged connection process that is described in Chapter 5.3.2. If the anticipated capacity of the AD facility increases during the project planning phase or later during the completion phase, e.g. due to inaccuracies in the first assessments, due to more substrates being available after changes in the farm 104


management, due to additional substrates being available at neighbouring farms or due to the decision to take in wastes, it will be more favourable if the higher capacity is still covered by the feasibility study undertaken by the DNO and the consequent reinforcement of the grid. Otherwise the procedure process will need to be restarted which will cause additional costs and delays. For small farm-scale biogas plants, it seems reasonable to apply for a capacity which is at least 25% higher than the anticipated power output of the facility. In case of high uncertainties it might be suitable to apply even for a higher capacity. There might be some additional costs in this procedure, as the feasibility study might be more expensive and also the necessary grid reinforcement might be higher. However, there will be no technical problems to connect a facility when the actual capacity is smaller than the planned one. But if the actual capacity exceeds the planning figure the connection might be refused and it will be re-assessed if additional reinforcement of the grid is necessary. All expenses so far still need to be settled and the restarted connection process will result in additional costs. The delay might be even more significant. The better the potential biogas substrates and their methane yields can be assessed during the planning phase the better is the dimensioning of the AD plant and all accompanying elements, including the connection to the grid.

8.3 Successful Operation of the Biogas Plant 8.3.1

Expertise on the AD Process

In order to operate a biogas plant safely and highly efficient, every plant operator must have detailed knowledge about the biogas process. This helps to avoid "feeding errors" and to correctly interpret measurement data. To monitor the process, control of pH values and digester temperature is imperative but it might not be enough. Digestion of co-substrates in general requires more attention and additional analytical routines, while AD processes run on manure and slurry are more robust and less susceptible to failure. Contact to other biogas plant operators and exchange of knowledge are beneficial. “AD neighbourhoods” with meetings on a regular basis and provision of support when necessary strengthen the individual site and facilitate dealing with any problems.

8.3.2

Effort and Labour

The operator must accomplish multiple activities in different intervals. The activities vary in time; there are daily routines (e.g. control feedstock supply, note gas meter conditions, control engine operation hours, check engine oil level, inspect electrical room, switchgear cabinet, check fermenting temperature), weekly duties (check digester filling conditions, control submerged propellers), monthly activities (operate all valves, in order to avoid sedimentation), half-yearly tasks (examine gas magnet valve function and contamination), and annual tasks (remove stones from the reception pit; control and rinse gas lines; control fittings). The operator must be aware of the fact that in case of illness another well-informed person must be able to ensure at least the basic regular biogas plant operation. As a rule of thumb goes that the necessary labour is between 4 to 5 hours per installed kW. This is the necessary labour for the actual plant operation, and does not include activities such as production of 105


energy crops or spreading of digestate. The higher the complexity degree of the plant the more labour is necessary. Some automation is possible at larger plants, but no biogas plant can run fully automated. Slurry based plants require the lowest amount of effort and labour. Handling of different types of materials requires more time. Process imbalances not only reduce energy generation but also require extra attention and extra labour time. It is more favourable to allow some labour time on a routine basis than to be obliged to deal with problems. Major biogas plant maintenance should preferably be carried out by avoiding the winter period. The winter months offer a higher heat utilisation potential. Moreover, in general higher slurry amounts for treatment are available during this time and this period also includes the three half hours of peak electricity demand relevant for the triad benefit (see Chapter 4.1.4).

8.3.3

Long-term Viability of the Installation

An AD plant is a long-term investment. It needs to generate revenue over many years. While keeping the running costs as low as possible, the biogas plant operator should concentrate on maintaining high process stability and high gas production. The case studies of this report indicate that lower gas generation and lower efficiency of the CHP unit can significantly reduce business profit. Regular maintenance of the technical equipment, especially of the engine, should be carried out. Since in the UK there is no guaranteed feed-in tariff for electricity, the economic viability of an AD installations strongly depends on the value of the generated electricity. When supplying electricity to the grid, the wholesale electricity price can be higher if the buying electricity company is willing to pay ‘embedded benefits’ which can include so-called triad benefits (see Chapter 4.1.4). Embedded generators reduce the power load which licensed electricity companies impose on the National Grid. Each embedded generator actually feeding in electricity during the so-called triad half hours reduces the triad charges which the electricity company needs to settle for using the National Grid. However, this will only be achieved if the CHP unit of the embedded generator is operational during the relevant triad periods (see Chapter 4.1.4). The benefit for the licensed electricity company will be at maximum if the AD plant operates at its maximum output during the triad periods. However, the relevant three half hours are not known in advance and it is not easy to predict exactly when the triads are going to occur. Usually they will be at 17:00, 17:30 or 18:00 on winter weekdays except Friday [Wikipedia, 2008]. The electricity supplier might provide information on when the triad half hours will likely be. Biogas is an energy source which in general cannot be stored over longer times on site without very high additional storage costs. While it might be more feasible with other energy sources to achieve high triad avoidance payments by engaging in schemes where generators are switched on especially during the triad hours, this seems less attractive for AD facilities. A biogas plant operator should try to focus on constant electricity production. In particular it is not advisable to try to increase the biogas yield during specific periods by higher substrate input, as process imbalance can affect the biogas output over longer times. The sensitivity analyses of the case studies of this report indicate that any decline in the efficiency of the CHP unit or in the gas production will significantly influence profitability of the AD unit. Any failure or inhibition of the biological process or a temporary break-down of the CHP unit will result in reduced revenue. 106


The AD plant needs attention and labour on a regular basis. The biogas plant operator should be aware that problems with both the technical equipment and the biological process can occur. The technical equipment needs maintenance. In order to avoid process failure, the process stability should be monitored and the plant performance should be regularly assessed. On-site analyses or external laboratory analyses may seem expensive, but are an important element in achieving and maintaining a high plant performance. AD processes run on slurry/ manure basis in general show high process stability and very low risk of process imbalance due to the buffering characteristics of the substrates. Shortage or lack in slurry results in digestion processes which are more susceptible to biological imbalance and hence require more attention and regular analysis. Taking in wastes is an option which can improve the profitability of an AD plant. However, farmbased biogas plants should reject all waste which would result in a digestate which cannot be spread to land. Hazardous components can also harm the biological process by negatively affecting the microbial consortium. Woody components, plastics and stones can also cause process problems and require extra pre-treatment of the waste streams.

107


9 Conclusions 9.1 Current status of AD in the United Kingdom within a European Context England and Wales have seen only marginal development of farm-based AD in the last years. In the context of a rapidly growing biogas industry in Europe, economic returns in different countries and at different locations are increasingly important. In countries within the EU where there has been a political will to promote agricultural use of AD, different policies have been adopted to improve the economic viability of the process. Denmark was the first European country to encourage widespread use of AD with the Biogas Action Programme in 1988, which focussed on construction and monitoring of AD plants, information activities, R&D support, but also included economic measures to encourage investments, e.g. grants of up to 40% of capital costs, long-term low-interest loans, tax exemptions and feed-in tariffs for bio-electricity. As a result, there are now 20 centralised and over 35 farm-scale plants for digestion of slurry and organic waste treating over 1 million tonnes of animal slurry per year. Electricity generation was the favoured use for the biogas because prices were guaranteed for plants built during the time the scheme was in operation (1998-2002). No new centralised plants have been established since 2002, and the development of farm-scale plants has slowed down. The setback is caused by a shift in energy and environmental policies, limited availability of organic wastes and the fact that there is no longer a guaranteed price for the electricity generated [Banks et al., 2007]. Germany has experienced an unprecedented introduction of biogas plants onto farms since 1991 with the “Feed in Law” and more so in 2000, when the ‘Renewable Energy Law’ came into force. This required the grid providers to connect plants and buy the energy at a fixed price, with small-size installations being paid higher prices. Financial incentives, subsidies for renewable energy production and especially the guaranteed price for electricity over a 20-year period were the main drivers to widespread introduction of anaerobic digestion in German agriculture. However, since the electricity price is particularly high when energy crops are used as feedstock and the scheme is generally focused towards high energy generation, natural agricultural residues from plants and animals and in particular not-farm based organic materials were displaced by energy crops to a large extent and the average size of farm-based AD facilities has increased. As a consequence, but mainly due to world market shifts, prices for energy crops have drastically risen. In particular plant operators digesting energy crops which cannot be produced on own farmland in sufficient amount, today face a risk of reduced profitability of their AD installation. AD development in Europe indicates that, where there has been no incentive policy, use of AD on farms is usually very limited; when incentives previously in place are removed, uptake stagnates; and when progressive long-term policies are implemented, farmers have shown to be willing to adopt the technology [Banks et al., 2007]. Improving reliability in income streams from energy generation, in particular by introducing guaranteed renewable energy feed-in tariffs and policies scheduled on long terms have proven to be the most effective mechanisms. According to Banks et al. [2007], even with subsidies digestion of animal manures as a single substrate is not common in Europe, and countries with successful manure digestion schemes have achieved this either by permitting the import of wastes onto the farm or offering bonus subsidies for the use of energy crops. Both measures improve the energy efficiency of the AD process by increasing 108


the volumetric methane production. However, concerns have been expressed that when offering subsidies for energy crops, attention could concentrate on energy production at the expense of improving manure management [Banks et al., 2007]. Many German farmers have now even dropped their livestock enterprise and are concentrating on the production of energy from crops as it seemingly pays better than livestock farming. Unlike in other countries, in the UK there is no extra payment for electricity generated from energy crops. With the ROCs mechanisms, it is rather unlikely that energy crops will be grown to a large extend specifically as biogas feedstock. Co-digestion of waste streams could make a useful contribution to the successful operation of on-farm biogas production in the UK, while at the same time this also contributes to sustainability by returning the digestate back to land as part of the nutrient cycle [Yeatman, 2007]. Moves to tighten NVZ restrictions reinforce the potential benefits of an anaerobic digestion plant on livestock units [Yeatman, 2007]. However, more NVZs alone will probably not result in significantly more AD plants. Like Denmark, Finland was declared a nitrate sensitive zone, and faces one of the most stringent requirements in relation to manure management, with 12 months storage for slurry. But unlike Denmark, Finland did not offer assistance or incentives for the construction of AD plants and farm-scale AD remained limited to some individual cases [Banks et al., 2007].

9.2 Assessment of the eight pre-selected potential Biogas Plants in Cornwall 9.2.1

Technical Feasibility and total potential Energy Generation

Anaerobic digestion is technically feasible in all eight analysed scenarios in Cornwall. For each of the eight different sites, Table 9-1 compiles substrate types, the anticipated methane production, the installed capacity of the CHP unit and the calculated energy generation. The available electricity and heat indicates the energy which is available for consumers or feed-in, after self-consumption of the AD process and energy losses during transport and transformation. Two scenarios have a potential power generation of approximately 400 kWel (installed capacity 499 kWel). Two scenarios generate approximately 50 kWel and Scenario 4 reaches 92 kWel. The calculated power generation of the two remaining farm-based scenarios (Scenario 3 and 5) is around 150 to 170 kWel; Scenario 5 needs a higher installed capacity because biogas generation cannot be equalised throughout the year. The community based Scenario 8 has a calculated power output of 650 kWel. Scenario 1 to 8 have a potential total methane generation of 12,318 m³ CH4/d, with a gross energy content of 44,961 MWh/a. At a total installed capacity of 2.304 MW, the actual electricity generation of the CHP units would be 17,057.8 MWh/a, which equals a power of 1.947 MW. Of this, approximately 90% or 15,345.0 MWh/a of electricity would be available after self-consumption of the AD process and losses, and would actually displace electricity from other sources. This corresponds to a power supply of 1.752 MW. Regarding heat generation, after self-consumption of the AD process and losses during transport, up to 11,022.2 MWh/a biogas heat would be available to consumers. The modelling assumes that 4,752.1 MWh/a biogas heat could actually be valorised by supply to consumers, which is 43% of the total potential. This amount of biogas heat would displace 475,210 litres heating oil per year. 109


Table 9-1

Anticipated Methane and Energy Production of the eight Biogas Plants of this study

scenario/ substrates

1 cow slurry, grass and maize silage 2 cow slurry, poultry manure, silage, potatoes, straw 3 cow manure, grass silage, straw 4 cow slurry, manure, grass, wheat 5 cow slurry, potatoes 6 (option 2) pig slurry, grass and maize silage 7 (option 1) cow slurry, horse manure, silage 8 cow slurry, maize silage, wastes (meat, fish, food) Total

CH4 production m³ CH4/d 363.9

energy content (gross) MWh/a 1328.1

Installed capacity CHP unit kWel 75

Output power CHP kWel 50

Electricity generation CHP unit MWhel/a 436.93

Available Avaielectricity1) lable heat1) MWhel/a MWhth/a 393.24 362.28

Assumed heat to customer MWhth/a 141.00

2515.6

9182.1

499

400

3507.55

3181.35

2689.35

120.00

931.1

3398.5

190

148

1298.23

1165.81

940.85

940.85

578.1

2110.0

104

92

803.90

717.89

445.48

0.0

1065.0

3887.4

250

167

1461.66

1311.11

824.13

144.00

2476.4

9038.7

499

393

3443.76

3109.71

2185.26

660.00

349.4

1275.5

75

47

415.81

373.40

286.11

5.00

4038.6

14,740.8 861

650

5689.96

5092.51

3288.76

2741.28

1,947

17,057.80

15,345.022) 11,022.22

4,752.13

12,318.1 44,961.1 2,304

1)

Actually available energy after self-consumption of the AD process and losses during transport/ transformation 2) This corresponds to a power supply of 1,751.7 kWel

Different approaches exist to determine reduction of greenhouse gas (GHG) emissions when implementing renewable energy technologies. It is not within the scope of this study to review the various methods; but an indication of the GHG reduction potential of the studied scenarios might be of interest. The most important GHG parameters are CO2, CH4, N2O and NH3 and their global warming potential (GWP) is expressed as CO2 equivalent emission (g CO2 eq/kWh). The GWP of methane for example is 23 times higher than that of CO2. For biogas generation in a CHP unit (electricity and heat) GHG factors were determined as follows [Plöchl and Schulz, 2006; Jungmeier et al., 1999]:

Biogas from manure/ slurry/ agricultural by-products: -525 g CO2 eq/kWh (includes emissions of +50 – +100 g CO2 eq/kWh for building and running the digesters, additional material transport compared to conventional manure management and savings related to improved manure management, mainly reduced GHG emissions during storage, of -500 – -700 g CO2 eq/kWh)

Biogas from energy crops: +100 to +200 g CO2 eq/kWh (includes emissions during substrate cultivation and transport for an average distance of 10 km)

Biogas from manure/ slurry/ agricultural by-products + energy crops: -100 to +100 g CO2 eq/kWh

Those factors are based on total energy generation with CHP units, assuming a conversion in 1/3 electricity and 2/3 heat. GHG factors referring to electricity only are not suitable as electrical and thermal output are not independent from each other. In the studied AD scenarios, the proportion of energy crops is low compared to manures; a biogas GHG factor of -100 g CO2 eq/kWh is assumed.

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Energy from fossil sources has higher GHG factors. According to Öko-Institut [2006], energy from brown coal has a GHG emission factor of 1,060 g CO2 eq/kWh, energy from oil 875 g CO2 eq/kWh, and energy from natural gas 400 g CO2 eq/kWh. In the UK, electricity production from gas was 36%, from coal 38% in 2006, and very little from oil, with the rest being from nuclear power (18%) and other sources [BERR, 2007]. Hard coal has around 20% lower emissions than the abovementioned brown coal. A GHG factor of +630 g CO2 eq/kWh is assumed in the following for UK fossil energy. Biogas energy in the studied scenarios reduces GHG emissions by 730 g CO2 eq/kWh (630 g for direct displacement of fossil fuel usage and 100 g for GHG reduction by improved manure management). Thus, the 15,345.0 MWh/a surplus electricity generated from methane capture at Site 1 to 8 could displace 11,202 tonnes CO2 equivalent per year (this includes 9,667 t/a CO2 equivalent for direct fossil fuel displacement). The assumed heat utilisation (4,752.1 MWh/a) further increases the figure to a total of 14,671 tonnes CO2 equivalent displaced per year. The more heat can actually be used, the higher is the displacement of CO2 equivalent. In addition, energy generated with high proportions of manures and agricultural by-products has considerably higher GHG reduction factors, as the effects of improved manure management are more dominant, as discussed above. The total energy generation potential of Scenario 1 to 8 can be summarised as follows:

At an installed capacity of 2.30 MW, the 8 CHP units would generate 1.95 MW (= 17,058 MWh/a) of electricity. Of this, 1.75 MW (= 15,345.0 MWh/a) could actually be fed into the grid, the rest being self-consumption of the AD facility and energy losses (0.20 MW).

The assumed biogas heat valorisation would displace at least 475,000 litres of heating oil per year.

Implementation of Scenario 1 to 8 would reduce greenhouse gas emissions by approximately 15,000 tonnes CO2 equivalent per year.

Better heat utilisation would further improve environmental benefits.

9.2.2

Economic Assessment

Among the studied 8 scenarios, all four scenarios with an installed capacity below 200 kWel are economically not viable (without grant). The economic modelling forecasts business losses for Scenario 1, 3, 4 and 7, see Table 9-2 and Figure 9-1. In scenario 3 (190 kW) it is the necessary investment in additional silage storage capacity which reduces the profitability of the AD project. At the other four sites (2, 5, 6, and 8), where the installed capacity of the CHP unit reaches or exceeds 250 kW, an AD project would be economically viable. Aside from the community based Scenario 8, the most profitable AD plants would be Scenario 5 and Scenario 6-1, both with an installed capacity of 250 kW and both slurry-based projects (Scenario 5 with cow slurry and Scenario 6-1 mainly with pig slurry). Those two biogas plants have a sound economic basis and a Payback Period of around 8 years. Scenario 6-1 benefits from good potential for biogas heat valorisation. Scenario 5 is economically viable despite the fact that biogas generation cannot be equalised throughout the year. During the summer months, while a part of the dairy cows is kept free range, less energy is generated than during the winter months. Digestion of additional substrates during the summer would further improve profitability of this scenario. Scenario 2 and Scenario 6-2 (installed capacity 499 kW), which both include co-digestion of high amounts of energy crops, have significantly higher business volume but result in lower Business Profit 111


and longer Payback Periods compared to the 250 kW-scenarios. Clearly the necessary investment in silage storage capacity reduces profitability of those two 499 kW-scenarios. Table 9-2 Scenario

1 2 3 4 5 6-1 6-2 7 8

Overview Economic Viability Scenario 1 to 8

Through- Installed Total put1) Capacity Investment t/a kWel £ 2,350 75 506,921 10,405 499 1,364,085 4,263 190 953,176 6,499 104 470,0542) 17,670 250 822,122 22,900 250 876,590 28,435 499 1,571,720 5,056 75 464,489 42,530 861 3,157,036

1)

Dilution water (if added) not considered

Investment Storage Energy Crops % of total invest 11.4 25.1 15.3 3.0 0.0 0.0 21.5 0.0 0.0

Operation/ Maintenance/ Capital Costs £/a 119,219 476,692 271,430 134,511 164,064 208,678 515,221 106,331 934,214

Revenue

£/a 69,854 505,889 240,056 112,702 204,791 258,272 533,873 59,129 1,009,906

Business Profit/ Losses £/a -49,364 +29,198 -31,374 -21,809 +40,727 +49,594 +18,651 -47,202 +75,692

Payback Period years negative 10.7 26.0 32.0 8.1 7.7 12.3 negative 10.3

2)

Digestate storage capacity partially already available on farm

1.000.000 £/a

Revenue

750.000 £/a Ongoing costs without write-off

500.000 £/a 250.000 £/a


0 £/a -250.000 £/a


-500.000 £/a -750.000 £/a -1.000.000 £/a 1

Figure 9-1

2

3

4

5 6-1 Scenario

6-2

7

8


Summary of Profitability AD Scenario 1 to 8

The two slurry-based 250 kW-plants (Scenario 5 and Scenario 6-1) do not require grants to achieve a Payback Period of around 8 years. This result is also due to high available slurry amounts all year round, while at other sites very little slurry is collected during the warmer season when animals are kept free range. If 2 x ROCs could still be claimed when accepting a grant, those two scenarios would particularly benefit from a grant of 30% on total investment cost; this would reduce their Payback Period to around 5 years (Table 9-3). This could be justified by the argument that those scenarios focus on improved slurry/ manure management, which is particularly favourable for the environment (high greenhouse gas reduction, see Chapter 9.2.1). Utilisation of high amounts of energy crops requires higher grants. To achieve a Payback Period of around 8 years, Scenario 2 (499 kW) requires 20% grant and Scenario 3 (190 kW) needs 55% grant.

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A grant of 60% results in a more attractive Scenario 4 (104 kW). However it needs to be taken into account that the economic modelling includes some investment cost reduction in this scenario as appropriate partial digestate storage capacity is already available in proximity to the favoured AD plant location. Table 9-3 Scenario

1 2 3 4 5 6-1 7 8

Grant Requirements Scenario 1 to 8

Installed Total Capacity Investment kWel £ 75 506,921 499 1,364,085 190 953,176 104 470,054 250 822,122 250 876,590 75 464,489 861 3,157,036

Necessary grant (in % of total investment) to achieve a Payback Period of 8 years with 2 x ROCs with 1 x ROCs 93% (100%)1) 19% 85% 54% 88% 58% (100%)1) 1% 45% 0% 44% 94% (100%)1) 17% 63%

Necessary grant (in % of total investment) to achieve a Payback Period of 5 years with 2 x ROCs with 1 x ROCs 95% (100%)1) 45% 90% 69% 92% 72% (100%)1) 32% 63% 30% 62% 96% (100%)1) 43% 74%

1)

Despite 100% grant there would still be Business Losses and no Profit for the farmer

However, if taking a grant means falling back on 1 x ROCs, much higher grants would be required in all scenarios. The individual case studies in Chapter 7 discuss the effects in more detail. Not only are much higher grant sums necessary to reduce the Payback Periods, but in particular the total Business Profit of the farmer is in general lower than when refusing all grant and claiming 2 x ROCs instead. This is exemplarily visualised in Figure 9-2 under the assumption of 50% grant for all scenarios. Availability of the grant results in clearly improved profitability of the individual scenarios if double ROCs are still possible. With single ROCs however, even with 50% grant the profitability is lower than without grant but double ROCs instead. Business Profit/ Losses without grant and with 50% grant

250.000 £/a

without grant and 1 x ROCs

200.000 £/a 150.000 £/a

50% grant and 1 x ROCs

100.000 £/a 50.000 £/a 0 £/a

without grant and 2 x ROCs

-50.000 £/a -100.000 £/a

50% grant and 2 x ROCs

-150.000 £/a -200.000 £/a 1

Figure 9-2

2

3

4

5 6-1 Scenario

6-2

7

8

Scenario 1 to 8: Business Profit/ Losses without grant and with 50% grant on total investment costs, assuming that either 2 x ROCs or only 1 x ROCs could be claimed

113


This clearly underlines the dominant influence of the electricity value on the economic viability of AD installations in the UK. If farmers are to invest in AD technology, every risk of loosing the second ROC is likely to reduce their willingness. When comparing economic viability of AD installations in the UK with digestion facilities in other countries it is clearly not sufficient to regard the revenue from the generated electricity alone. With the 2 x ROCs concept the electricity value itself is high compared to other countries. Currently biogas electricity generates revenues of 8.4 to 28 ct/kWh in Germany, 16.5 ct/kWh in Spain, 30 ct/kWh in Italy, 11 to 14 ct/kWh in France, 14 to 18 ct/kWh in Croatia and 28 ct/kWh in Switzerland. However, it is one result of this study that currently the necessary investment costs in the UK are much higher than for example in Germany. This includes AD plant buildings and equipments but in particular also any necessary substrate storage capacity. Compared to other countries, especially digestion of energy crops thus faces smaller profitability in the UK due to high necessary investment for additionally required substrate and digestate storage. The fewer storage capacity for substrates and for digestate is necessary the better is the economic viability of the studied scenarios.

9.3 Possible Barriers and Chances for on-farm AD in the UK and Cornwall Due to the current development in UK policy and in particular the double ROCs concept, the number of biogas plants in the UK will probably rise significantly in the next years [Andersons, 2008]. However, biogas technologies need to be established. Renewable energy technologies need confidence if investments shall increase. This is particularly the case at the smaller end of the technologies such as biogas and biomass/ CHP/ electricity units of a few hundred kW [Toke, 2007].

9.3.1

Chances for Farmers and Industries

Biogas production reduces greenhouse gas emissions and contributes to an environmentally sound waste management treatment concept. Every well-run biogas plant contributes to fight the global warming and reduces pollution of the environment. In addition to the positive environmental aspects, an economically viable biogas plant is a source of additional income for farmers. Anaerobic digestion has the potential to strengthen rural areas and at the same time offers opportunities for a growing AD industry. In England and Wales, approximately 67 million tonnes of manures are collected annually [Chambers et al., 2000], a potential source of organic material for use as feedstock in anaerobic digesters. Codigestion of energy crops and/ or waste materials offers the possibility to increase gas yields. In particular co-digestion of energy crops, which can easily be stored on farm throughout the year, gives the energy producer much more control over his electrical output and overcomes the possibly greatest drawback with dairy or beef farm biogas plants, which is the reduction of manure supply during the summer months [Yeatman, 2007]. However, energy crop storage and co-digestion of wastes both require higher investment and need careful evaluation. The United Kingdom is an interesting market for the biogas industry. With the double ROCs concept the profitability of a biogas plant and hence the interest in the technology will drastically increase from 2009 on. While there are only a limited number of UK companies, more and more companies from abroad show interest in UK projects.

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Companies with many years of experience and a significant number of reference projects offer AD concepts which have proven to be reliable. As there is constant development in the AD sector, new concepts might also be worth to be considered. The potential future biogas plant operator should try to gain detailed knowledge about the biogas process and the technology, in order to be able to make a sustainable decision if a biogas plant fits into the farm concept and if yes, which technology will be best suited.

9.3.2

Uncertainties on Income from Electricity for UK Biogas Plant Operators

There is no direct subsidy for renewable energy produced in the UK. Energy producers rely on the value of ROCs to supplement the wholesale electricity price that they receive. The absence of a guaranteed price for energy also makes it more difficult to obtain good financing conditions from banks. Main elements of risk in forecasting the value of the electricity to the biogas plant are:

The value at which the ROCs are traded is unsure. The value of ROCs is determined by the degree of shortfall in the supply of renewable energy by companies that supply electricity. The more renewable energy is produced in the UK, the lower will the value of ROCs be.

There is the possibility that renewable targets in the UK are achieved or exceeded with the effect that ROCs become a buyers (not a seller) market, resulting in reduced prices. This is unlikely under present conditions, unless a very large infrastructure project was approved, on the scale of the Severn Barrage.

Wholesale electricity price variations caused by global economic, political or climatic influences may have an influence.

Changes in Government Policy may affect the AD branch and the economic viability of biogas plants. There is a possibility, though very unlikely, that the 2 x ROCs awarded for biogas may be amended by Parliament after the Energy Bill becomes law.

According to the State Aid Rules, at present a recipient of a government grant would not receive 2 x ROCs but would fall back on single ROCs (see Chapter 9.3.4).

A rising number of AD installations can lead to higher market prices for substrates, a factor which according to the German experience made in the last years, can negatively influence profitability of biogas plants relying on availability of substrates that cannot be produced on own land. On-farm AD installations using mainly substrates from their own land or substrates taken in on long-term contract basis face a reduced risk concerning the long-term profitability of the facility. To make some provision for customers willing to treat wastes, e.g. the UK subsidiary of the company EnviTec seems to engage to some extent in ensuring that biogas plants have access to suitable wastes [Day, 2008].

9.3.3

Possible Advantages of a Guaranteed Feed-in Tariff

Agricultural biogas production will be economically more viable with the double ROCs concept than with single ROCs. Certainly if farmers are to invest in biogas generation, a guaranteed Renewable Energy Feed-in Tariff would prepare the conditions of confidence in income streams; however, under present arrangements this is unlikely to happen [Toke, 2007]. A guaranteed feed-in tariff for renewable electricity would have several benefits:

115


It enables precise assessment and reliability of income streams from renewable energy for the generator.

It is less difficult to be obtained in particular for very small generators: claiming ROCs usually involves an agent and broker to sell the ROCs at auction or requires negotiation to sell the ROCs to a licensed electricity company.

A guaranteed feed-in tariff is an additional incentive to save electricity: with the feed-in system all electricity would be exported to the grid and the electricity required by the farm would be bought back; buying back less from the grid reduces costs [Williams, 2008].

With the double ROCs concept, ROCs can be claimed for all electricity generated, regardless if electricity is used on site or if it is exported to the grid. The actual sales price for export to the grid (assumed in this study: 5.5 p/kWh) is lower than the electricity retail price. As a consequence electricity used on site has a higher value than electricity sent to the grid. This results in a situation in which a site with high own electricity demand can benefit more from an AD facility than a site with low own electricity consumption (e.g. due to electricity saving efforts). This is exemplarily demonstrated in Table 9-4, assuming two identical sites A and B, but Site B requiring 50% less electricity for its own farm than Site A. Both sites have the same revenue from ROCs, but Site A can achieve a higher total benefit as it displaces more expensive electricity from the grid with biogas electricity. Table 9-4

Example of possible benefit from AD electricity of two sites with different own electricity demand under the double ROCs concept (assuming that biogas electricity is used to cover own electricity demand)

Total electricity output AD: 500,000 kWh

Revenue from electricity

Site A Utilisation electricity on site (own farm): 100,000 kWh Export to grid: 400,000 kWh Total benefit from electricity Site A Site B Utilisation electricity on site (own farm): 50,000 kWh Export to grid: 450,000 kWh Total benefit from electricity Site B 1)

=15.1 p/kWh total electricity value

2)

export to grid 2 x ROCs (5.5 p/kWh) (9.0 p/kWh)

Savings (replacement of electricity from the grid with AD electricity) less electricity retail for own farm (8.5 p/kWh)

-

£9,000

£8,500

£22,000 £22,000

£36,000 £45,000

£8,500

-

£4,500

£4,250

£24,750 £24,750

£40,500 £45,000

£4,250

£75,5001)

£74,0002)

=14.8 p/kWh total electricity value

This would not be the case with a guaranteed feed-in tariff: as the feed-in tariff would be higher than the retail price from the grid, both sites would export all electricity and would achieve the same benefit from the generated electricity. In this example Site A would need a feed-in tariff of 15.1 p/kWh in order to achieve the same total benefit than with the double ROCs concept, whereas Site B would achieve the indicated benefit with a feed-in tariff of 14.8 p/kWh. Currently up to approximately 22.4 p/kWh biogas electricity can be achieved in some European countries, see Chapter 9.2.2.

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9.3.4

Grants

Grants are an appropriate means to encourage UK farmers in taking the opportunity to make themselves suppliers of energy. Grants would not only reduce the payback period, but would also make it easier to obtain financial support from banks. Reduction of green house gas emissions, decline in fossil fuel availability and concerns over national energy security are strong arguments in favour of renewable energy. However, it should be carefully assessed, which energy type is best suitable to be promoted by national or regional funding schemes and also farmers should carefully consider which areas of energy production they want to get involved with. Production of biodiesel and bioethanol can only work on large scale and plants in UK would be mostly run on imported feedstock, which makes the concept less sustainable. It is worth mentioning that biogas generation, especially when based on feedstock already available on farm or on waste materials, is a different concept. At present, according to the State Aid Rules the recipient of a government grant would not be eligible for 2 x ROCs from 1 April 2009 on but would receive single ROCs only. A biogas plant operator would be forced to choose between accepting the government grant and loosing the second ROC or deciding in favour of 2 x ROCs but having to refuse the government grant. Otherwise it could be constructed as a double state aid support. The results of this study clearly indicate that accepting a grant but loosing the second ROC can be of considerable negative effect on the profitability. Results indicate further, that many agricultural AD plants will require grants to be economically viable. Falling back on a single ROC when accepting a grant, has likely a significant negative effect on a more widespread use of agricultural AD. It is one result of the economic modelling that when using energy crops, the necessary investment for substrate storage capacity particularly affects the profitability of the biogas plant adversely. If substrate storage is already available on farm, digestion of energy crops is economically viable with the 2 x ROCs concept. AD plant operators willing to digest additional energy crops need an extra grant. An additional grant related directly to biomass storage would clearly be favourable. It needs to be assessed if accepting a grant for biomass storage still bears the risk of falling back to single ROCs when using the biomass for energy production.

117


10 References and Acknowledgements 10.1 List of References Adas: The safe sludge matrix – Guidelines for the application of sewage sludge to agricultural land. Booklet published by Adas, BRC (British Retail Consortium) and Water UK, 3rd edition, April 2001 – download from the official website of the company Adas (www.adas.co.uk/) Andersons – The Andersons Centre (author: Graham Redman): A detailed economic assessment of anaerobic digestion technology and its suitability to UK farming and waste systems. Project carried out for the National Non-Food Crops Centre, Leicestershire, 2008 Banks, C.J.; Salter, A.M.; Chesshire, M.: Potential of anaerobic digestion for mitigation of greenhouse gas emissions and production of renewable energy from agriculture: barriers and incentives to widespread adoption in Europe. Water Science & Technology, vol. 55, no. 10, 2007, pp. 165-173 BERR: UK Energy in brief July 2007. Department for Business Enterprise & Regulatory Reform (Ed.), National Staitistics Publication, 2007 BERR: Official website of the Department for Business Enterprise & Regulatory Reform. URL www.berr.gov.uk/, web site visited on 5 July 2008 Burke, D.A.: Dairy Waste Anaerobic Digestion Handbook. Environmental Energy Company, Olympia, 2001 Chambers, R.J.; Smith, K.A.; Pain, B.F.: Strategies to encourage better use of nitrogen in animal manure. Soil Use and Management, vol. 16, 2000, pp. 157-161 Day, J. (company EnviTec, UK subsidiary): personal communication per e-mail on 12 June 2008 Defra – Department for Environment, Food & Rural Affairs (Ed.) [2002a]: Manure planning in NVZs. Defra booklet, London, 2002 Defra – Department for Environment, Food & Rural Affairs (Ed.) [2002b]: Ammonia in the UK – key points. Defra booklet, London, 2002 EA (Environment Agency): The Water Frame Directive – not only a question of quality. Position Statement, 2003 – (download under http://www.environment-agency.gov.uk/commondata/acrobat/wfd2_908132_1290978.pdf) EA (Environment Agency): Anaerobic digestion of agricultural manure and slurry. EA briefing note, April 2008 e-roc: Website of the online auction platform for ROCs, URL www.e-roc.co.uk/, web site visited on 3 July 2008 EurObserv'ER (Ed.) [2007a]: State of renewable energies in Europe. 7th report of EurObserv'ER, 2007 EurObserv'ER (Ed.) [2007b]: Biogas barometer – 5.35 Mtoe valorised in European Union in 2006. Systèmes Solaires – Le Journal des Énergies Renouvellables, vol. 179, 05/2007, pp. 51-61 FNR – Fachagentur Nachwachsende Rohstoffe e. V. (Ed.): Handreichung Biogasgewinnung und –nutzung. Gülzow, Germany, 2005 Foster, T.: Generating a Return. Presentation given at the Micro-Hydro Seminar, SmartestEnergy (company), 2007 Jungmeier, G.; Canella, L.; Spitzer, J.; Stiglbrunner, R.: Treibhausgasbilanz der Bioenergie – Vergleich der Treibhausgasemissionen aus Bioenergie-Systemen und fossilen Energiesystemen. Graz, 1999 – here cited from Plöchl and Schulz [2006] Juniper – Juniper Consultancy Services for Renewables East (authors: Austermann, S.; Archer, E.; Whiting, K.J.): Anaerobic digestion technology for biomass projects – commercial assessment. 2007 KTBL – Kuratorium für Technik und Bauwesen in der Landwirtschaft (Ed.): Faustzahlen Biogas. Darmstadt, Germany, 2007 Nix, J.: Farm management pocketbook. Imperial College London, 38th edition (2008), published September 2007 OFGEM: Official website of OFGEM. URL www.ofgem.gov.uk/, web site visited on 4 July 2008 Öko-Institut (Ed.): GEMIS – Gesamt-Emissions-Modell Integrierter Systeme (series), Öko-Institut and University of Kassel, 1987-2006+ – here cited from Plöchl and Schulz [2006] Plöchl, M.; Schulz, M.: Ökologische Bewertung der Biogaserzeugung und –nutzung. In: Biogas in der Landwirtschaft – Leitfaden für Landwirte und Investoren im Land Brandenburg. MLUV Ministerium für Ländliche Ernährung, Umwelt und Verbraucherschutz Land Brandenburg (Germany) (Ed.), Potsdam, 2006, pp. 49-52

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Scott, N.C.: European practices with grid connection, reinforcement, constraint and charging of renewable energy projects. Highlands and Islands Enterprise, Xero Energy, Report no. 1008/001/001C, Glasgow, 2007 SmartestEnergy: Official website of the company. URL www.smartestenergy.com/, web site visited on 8 July 2008 Toke, D.: Making the UK renewables programme fitter. World Future Council, submission to the 2007 Renewables Obligation reform consultation, August 2007 Turvey, R.: Ensuring adequate generation capacity. Utilities Policy, vol. 11, no. 2, 2003, pp. 95-102 Ward, A.J.; Hobbs, P.J.; Holliman, P.; Jones, D.L.: Optimisation of the anaerobic digestion of agricultural resources. Bioresource Technology, 2008 – in press Wikipedia: Wikipedia – the free Encyclopaedia. URL http:/en.wikipedia.org/, site visited on 8 July 2008 Williams, G.: The energy and climate change bills. Short paper for the Farming, Food and Bio-diversity Group – 3CAP, 05 August 2008 WPD [2007a]: Connection considerations for distributed generation. Publication from Western Power Distribution, 2007 – download from the official website of the company (www.westernpower.co.uk) WPD [2007b]: Long term development statement for Western Power Distribution (South West) plc’s electricity distribution system. Western Power Distribution, Bristol, November 2007 WPD: Official website of Western Power Distribution. URL www.westernpower.co.uk/, web site visited on 5 July 2008 WRAP: Official website of the Waste & Resources Action Programme. URL www.wrap.org.uk/, web site visited 20 August 2008 Yeatman, C.O.: The profitable use of anaerobic digestion (AD) on UK farms. Nuffield Farming Scholarship Trust, 2007

10.2 Acknowledgements IBBK in cooperation with David Collins acknowledge the Cornwall Agri-food Council Group and Cornwall Enterprise for the possibility to carry out this project. In particular we thank Nicky Garge for help and support, which assured good progressing of this project. Contributions from members of the steering group during and after the progress meetings also were very helpful. All participating farmers and responsible contact persons of the studied scenarios were very helpful and cooperative. Collaboration of contacted companies is also gratefully acknowledged. The Annex contains an overview of companies with major contributions to the results of this study. In particular we thank Michael Chessire from Greenfinch for his help and comments. Provision of full necessary cost details for specific AD equipment by Susan Stewart and Owen Yeatman from Biogas Nord is specially acknowledged.

119

Economic Modelling of AD in Cornwall – Annexes

11 Annexes 11.1 Abbreviations a ABP ABPR AD B BERR CCL CH4 CHP CAC CNG COD COGAP CV d Defra DM DNO DTI DUOS EA eff. EP ETR EU FM FYM GEMA GHG GWP h IBBK K ktoe kW kWe kWt L LN LEC LNG LU

year(s) Animal By-Products Animal By-Products Regulations Anaerobic Digestion (internal factor for economic calculations, refers to position “buildings” in write-off) Department for Business Enterprise & Regulatory Reform Climate Change Levy methane Combined Heat and Power Cornwall Agri-food Council Compressed Natural Gas Chemical Oxygen Demand Code of Good Agricultural Practice Calorific Value day(s) Department for Environment, Food and Rural Affairs Dry Matter Distribution Network Operator, in Cornwall WPD (former) Department of Trade and Industry, predecessor of today’s BERR Distribution Use of System tariff Environmental Agency effective Environmental Permitting Engineering Technical Report European Union fresh material Farm Yard Manure Gas and Electricity Markets Authority Green House Gas Global Warming Potential hour(s) Internationales Biogas und Bioenergie Kompetenzzentrum – International Biogas and Bioenergy Centre of Competence (internal factor for economic calculations, refers to position ‘CHP unit: gas engine’ or ‘dual fuel engine’ in write-off) kilo tonnes oil equivalent kilowatt (1 kW = 103 W) kilowatt electrical (refers to electric power produced) kilowatt thermal (refers to thermal power produced) litre(s) norm litres (= litres at norm pressure 1.013 bar and norm temperature 0°C) Climate Change Levy (CCL) Exemption Certificate Liquefied Natural Gas livestock unit(s)

120


m³N MBT MSW MW MWe MWt NGV NVZ oDM OFGEM Para PES PFI POC PPC PSA REA REGO RHD RO ROC RPI SSSI t T WFD WML WPD WRAP

norm cubic metre(s) (= cubic metre(s) at norm pressure 1.013 bar and norm temperature 0°C) Mechanical Biological Treatment (of MSW) Municipal Solid Waste megawatt (1 MW = 106 W) megawatt electrical (refers to electric power produced) megawatt thermal (refers to thermal power produced) Natural Gas Vehicle Nitrate Vulnerable Zone Organic Dry Matter Office of Gas and Electricity Markets, working for the GEMA paragraph Public Electricity Supplier, in England and Wales synonymous to the Regional Electricity Company Private Finance Initiative Point of Connection (electricity grid) Pollution Prevention and Control Permit Pressure Swing Adsorption Renewable Energy Association Renewable Energy Guarantee of Origin Right Hand Drive Renewables Obligation Renewable Obligation Certificate Retail Prices Index Site of Special Scientific Interest tonne(s) (1 t = 1000 kg) (internal factor for economic calculations, refers to position “technology” in write-off) Water Framework Directive Waste Management Licence Western Power Distribution Waste & Resources Action Programme

121


11.2 Economic Modelling: General Assumptions The economic modelling is based on the values compiled in Table 11-1. Table 11-1

Assumptions of the Economic Modelling

parameter

unit

basis for calculation

runtime CHP unit

h/a

8000 h/a

excess capacity CHP

kWel

+ 20% to calculated necessary CHP capacity

installed CHP capacity

kWel

upon availability in UK market, with minimum capacity = calculated necessary capacity + excess capacity

electric efficiency degree CHP

%

site-specific, depends on installed capacity of CHP unit, engine type; reduced efficiency if engine does not run on full power

thermal efficiency degree CHP

%

site-specific, see ‘electrical efficiency degree’

ignition fuel for dual fuel engine

L/a

10% of total energy going to CHP unit (90% of energy converted in the CHP unit is from biogas and 10% from ignition fuel)

costs ignition fuel

£/a

52 p/L

electrical energy demand of biogas plant

kWhel/a

site-specific, dependant on necessary equipment and size of digestion plant

thermal energy demand of biogas plant

kWhth/a

site-specific, dependent on digestion temperature, surface of digesters, insulation, and if digesters are above ground, in house or underground, and dependant on surrounding temperature; thermal energy demand is calculated per month and average monthly Cornish temperatures are utilised for calculations

revenue for electricity sales

p/kWhel

total package of 14.5 p/kWhel: 5.5 p/kWhel wholesales electricity price (including embedded benefits, triad benefits, LECs) + 9 p/kWhel for ROCs (2 x ROCs, with ROC’s value of 4.5 p/kWhel), see Chapter 6.2.2

retail price electricity from grid

p/kWhel

9 p/kWhel

costs oil for heating purposes

£/a

52 p/L

value heat utilisation

p/kWhth

4.68 p/kWhth, which is 90% of what would be the costs when using oil for heating (10 kWhth biogas heat have the energy content of 1 L heating oil); only the actually used heat has an economic value

actually utilised heat

kWhth/a

site-specific, according to available heat from the biogas plant and actual heat demand of consumers, the individual pattern is studied for each month

heat losses during transport and transformation

%

site-specific, according to the distance of heat consumers from the CHP unit

write-off ‘construction’

a

20 years

write-off ‘technology’ (without engine)

a

12 years

write-off ‘dual fuel engine’

a

4.5 years

write-off ‘gas engine’

a

7.0 years

rate of interest

%

7%

costs for plant design, information, approval

£

3-5% of investment ‘construction’ + ‘technology’ + ‘CHP’, depending on size and type of the plant

122


unforeseen investment costs

£

5% of investment ‘construction’ + ‘technology’ + ‘CHP’

costs for grid connection

£

site-specific

insurance

£/a

1.5% of total investment costs

costs for maintenance and repair for ‘construction’

£/a

2% of investment costs ‘construction’

costs for maintenance and repair for ‘technology’

£/a

3% of investment costs ‘technology’

costs for maintenance and repair for ‘CHP’

£/a

1.2 ct per generated kWh electricity (0.96 p/kWhel)

labour costs

£/a

15 £/h

substrate costs

£/a

see Chapter 6.2.2

fertiliser value of digestate

£/a

for digestate originating from manure/ slurry, an improved fertiliser value and not the actual total fertiliser value is priced since those nutrients would be spread to land with or without the biogas plant (also see Chapter 4.5), but the AD process improves availability of the nutrients and this is priced with 12.0 ct/kg N for nutrients originating from other substrates: 56.0 ct/kg N, 55.0 ct/kg P2O5 (= 24.0 ct/kg P), 28 ct/kg K2O (= 23.2 ct/kg K) only nutrients spread to land are considered and from the total nutrients in the fresh digestate, losses for N are taken into account (losses of ammonia NH3/NH4-N during storage and spreading; assumption: 15% loss of N)

exchange rate £/EUR necessary capacity end-storage

0.8 £/EUR m³

for 182 days (6 months)

parameters for sensitivity analysis

see Chapter 6.3

necessity of grants

see Chapter 6.3

123


11.3 Site-specific Annexes If not indicated otherwise, all following data represent annual mean values. However, the effects of different biogas plant feeding patterns during times when animals are kept free range and during times when animals are housed are considered in the modelling where necessary (dimensioning of digesters, necessary storage capacity, higher CHP capacity if equalisation of gas production is not possible throughout the year, etc.). Equalisation of biogas generation is possible throughout the year in most of the scenarios, by digesting higher amounts of other substrates during the time when less slurry is available. However, it should be taken into account that during periods when animals are housed, the total mass and volume flow to the biogas plant and the amount of generated digestate is higher, since the biogas yield per tonne or cubic metre slurry is in general lower than per unit of other substrates. Moreover, addition of water or recirculation of recyclate in order to adjust the DM content or ammonia concentration inside the digester might not be necessary during the whole year. Dimensioning of all components must be according to the varying necessities throughout the year.

124

Economic Modelling of AD in Cornwall – Annex: Scenario 1

11.3.1

Annex to Site 1

Input Substrates: Scenario 1 Type Manure cattle (liquid manure) Grass grass silage (general) Maize maize silage Straw straw (in slurry) Dilution dilution water Total incl. dilution water

Fresh Matter 1.100 500 650 100 720 3.070

Recyclat Recyclate Total Sub + Dilut + Rec

t/a t/a t/a t/a t/a t/a

Density 1,00 t/m³ 0,64 t/m³ 0,72 t/m³ 0,15 t/m³ 1,00 t/m³ #BEZUG!

Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 % 0,0 %

1,05 t/m³

Gas Yield/ oDM 350 L/kg oDM 540 L/kg oDM 670 L/kg oDM 320 L/kg oDM L/kg oDM

2.067 t/a 5.136 t/a

Input FM 1.100 500 650 100 720 3.070


DM [%FM] 8% 34 % 29 % 86 % % 17,3 %

Input [DM] 88 t/a 170 t/a 189 t/a 86 t/a t/a 533 t/a

0,0 %

2.067 t/a 5.136 t/a

4,09 % 12,0 %

85 t/a 617 t/a

Gas Yield/ FM 22 m³/ t FM 162 m³/ t FM 183 m³/ t FM 253 m³/ t FM m³/ t FM

Methane Content 59 % 54 % 52 % 51 % % 53,2 %

Flow Biogas 68 m³/d 221 m³/d 325 m³/d 69 m³/d m³/d 683 m³/d 249.460 m³/a

Flow Methane 40 m³/d 120 m³/d 169 m³/d 35 m³/d m³/d 364 m³/d 132.806 m³/a

while stock inside 227,5 d/a 4,31 t/d 1,22 t/d 1,59 t/d 0,39 t/d 1,51 t/d 6,12 t/d 15,15 t/d 12,1 %

stock outside 137,5 d/a 0,86 t/d 1,61 t/d 2,10 t/d 0,08 t/d 2,74 t/d 4,90 t/d 12,29 t/d 11,9 %

53,4 % 365 m³/d 8.164 kg/d 8,79%

52,9 % 362 m³/d 6.534 kg/d 6,94%

oDM [%DM] Input [oDM] 80 % 193 kg/d 88 % 410 kg/d 94 % 485 kg/d 92 % 217 kg/d % kg/d 89,4 % 1.305 kg/d %

water [t/a] 1.012 330 462 14 720 2.537

kg/d


1.982 t/a 4.519 t/a

Daily Gas Yield and Reduction of Biomass (annual mean): Manure Grass Maize Straw Dilution Total

cattle (liquid manure) grass silage (general) maize silage straw (in slurry) dilution water

DM content of input mixture: oDM content of input mixture: Proportion of digestable dry substance: Assumed gas yield from input: Assumed methande content: Density of Biogas Loss of Water (evaporation) Mass of produced Biogas Total reduction/ loss (water+biogas) Reduction of oDM Daily amount of digestate: DM in digestate: oDM in digestate: DM-content digestate: oDM-content digestate

Input [oDM] Percentage oDM [%] 193 kg oDM/d 14,78% 410 kg oDM/d 31,41% 485 kg oDM/d 37,20% 217 kg oDM/d 16,61% kg oDM/d 0,00% 1.305 kg oDM/d 100,00% 17,35% 15,52% 89,45%

Variation throughout the year cattle (liquid manure) grass silage (general) maize silage straw (in slurry) dilution water Recyclate Total incl recyclate DM-content input incl. dilution and recyclate

0,52 m³/kg oDM 53,24% 1,23 kg/m³ 0,028 kg/m³ 840,6 kg/d 859,8 kg/d 840,6 kg/d 7.550 kg/d 618 kg/d 464,3 kg/d 8,19% 6,15%

19,14 kg Condens./d

reduction: 10,22% mass reduction: 57,62% DM reduction: 64,42% oDM

Flow Biogas equalised, Methane content: Flow Methane Daily amount digestate DM-content digestate

energy content 1.328,1 MWh/a

Nutrients from manure and other substrates: Manure cattle (liquid manure) Grass grass silage (general) Maize maize silage Straw straw (in slurry) Total From manure From other substrates

Substrate DM 88 170 189 86 533

t/a t/a t/a t/a t/a

N 56,8 kg/ t DM 25,6 kg/ t DM 13,6 kg/ t DM 6,4 kg/ t DM 23,41 kg/ t DM

P2O5 18,4 kg/ t DM 8,7 kg/ t DM 5,5 kg/ t DM 3,5 kg/ t DM 8,33 kg/ t DM

K 2O 69,2 kg/ t DM 34,9 kg/ t DM 16,9 kg/ t DM 1,81 kg/ t DM 28,85 kg/ t DM

N

P2O5 5, t/a 4,35 t/a 2,56 t/a 0,55 t/a 12,46 t/a 5,55 t/a 6,92 t/a

K2O 1,62 t/a 1,48 t/a 1,04 t/a 0,3 t/a 4,44 t/a 1,92 t/a 2,52 t/a

Main Digester / Second Digester / Digestate Storage Main Digester:

1 item

Diameter: Height/ Length: Freeboard Effective digester volume: Organic loading rate input (annual mean): Theoretical retention time (annual mean): oDM of Input oDM of Outflow

16,0 m 6,4 m 0,5 m 1.186 m³ 1,1 kg oDM/m³·d 80 days

Diameter: Height: Freeboard Effective digester volume: Organic loading rate input (annual mean): Theoretical retention time (annual mean):

1.305 kg oDM/d 464 kg oDM/d

Flow rate substrate into digester: Flow rate recyclate Total flow rate into digester Surplus volume due to bubbles, foam etc. Theoretic. volume in digester Flow rate effluent digester NH4-N Organic loading while stock inside: Th. retention time while stock inside: Organic loading while stock outside: Th. retention time while stock outside:

No After-Digester item

After-Digester:

oDM of Input: oDM of Outflow:

8,4 m³/d 5,7 m³/d 14,1 m³/d 5,0 % 14,8 m³/d 12,9 m³/d

0,0 m 0,0 m 0,0 m m³ #DIV/0! days 464 kg oDM/d 464 kg oDM/d

Flow rate into digester:

12,9 m³/d

Surplus volume due to bubbles, foam etc. Theoretic. volume in digester Flow rate effluent without recyclate

5,0 % 13,5 m³/d 7,2 m³/d

2,23 g/L 1,2 kg oDM/m³·d 75 days 1,0 kg oDM/m³·d 92 days

Organic loading while stock inside: Th. retention time while stock inside: Organic loading while stock outside: Th. retention time while stock inside:

6,09 t/a 5,93 t/a 3,19 t/a 0,16 t/a 15,36 t/a 6,25 t/a 9,12 t/a

storage capacity mimimum for already available and usable Storage: Eco/Manure Bags

182 days 0,0 m³ "Existing"

Mass flow from digested substrate: 2755,7 t/a Mass flow of recyclate 2066,78 t/a Total mass flow 4822,48 t/a Total flow rate of material for storage: 2624,5 m³/a minus Existing: Necessary storage capacity total 1415,0 m³ Necessary Surplus to after-digester 1415,0 m³ 1415,0 m³ No. of Eco/Manure Bags 1 item Lengh 24,0 m 24,0 m Width 2,5 m Height: 1.440 m³ Storage volume total: 1.440 m³ Storage time (annual mean): 6,6 months Relevant digestate for storage (amount varies while stock in/out) Maximum digestate 182 days 1.415 m³ 1.415 m³ Minimum storage volume Digestate production: Mass flow digestate 2755,7 t/a Flow rate digestate 2624,5 m³/a

#DIV/0! days #DIV/0! days

Balancing of CHP-Unit CHP Type:

Gas Engine Electrical efficiency: Thermal efficiency: Daily production of electricity: Daily production of heat: Electrical power of CHP: 20% excess capacity: Power CHP + excess capacity: possible runtime of CHP at full power: Total efficiency of CHP: Coefficient of CHP:

75 kW

363,9 m³ CH4/d 32,9 % 48,3 % 1.197 kWh/d 1.757 kWh/d 50 kW 10 kW 60 kW 16,0 h/d 81,2 % 0,68

WAHR lower than efficiency at full power, as engine is not run at full power 436.933 kWh/a 641.455 kWh/a

actual runtime CHP: 8.000 h/a with % of full power: 5.826 h/a (at higher electr. eff. degree, but engine would be switched on/off)

72,8 %

125


Balancing of process energy demand (electrical and thermal energy): Scenario 1 Electrical energy demand for biogas process: Thermal energy demand for biogas process: Calculation of thermal energy demand for biogas process: Digester:

1

Month

0,04 0,060 W/mK 12 cm 0,49 W/m²K 724 m² 0 m² 8,5 kWh/(d*K)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

outside

Heat transmission coefficient: Insulation: heat conductance λ thickness: Insulation index k-value: Surface of Digesters: Surface of storage tank (if heated only): Loss of heat total: Process temperature:

38 °C

8,4 %

36.702 kWh/a

32,0 %

204.979 kWh/a

∆T K 32 32 31 29 27 24 22 22 24 26 29 31

Heat Loss kWh/day 273,3 275,1 263,1 248,7 227,4 203,5 189,9 188,2 200,1 221,4 250,4 262,3

Feed temperature °C 9 9 10 12 15 17 19 20 18 16 12 10

Heating energy kWh/day 282,9 282,9 273,1 253,6 224,4 204,9 185,3 175,6 195,1 214,6 253,6 273,1

Process energy kWh/day 667,5 669,5 643,5 602,7 542,1 490,1 450,3 436,5 474,3 523,2 604,8 642,5 incl. 20% heat losses from CHP to digester 204.979 kWh/a

Total:

Heat utilisation: Heat produced by CHP: Process energy demand for biogas plant: Theoretically available surplus heat: Losses during transformation and transport: Real available surplus heat: Monthly distribution of available surplus heat:

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total

actually available 905 kWh/d 903 kWh/d 925 kWh/d 958 kWh/d 1.009 kWh/d 1.052 kWh/d 1.085 kWh/d 1.096 kWh/d 1.065 kWh/d 1.024 kWh/d 957 kWh/d 925 kWh/d 362.275 kWh/a

641.455 kWh/a 204.979 kWh/a 436.475 kWh/a 74.201 kWh/a

17 %

362.275 kWh/a need (customer) 496 kWh/d 499 kWh/d 430 kWh/d 377 kWh/d 324 kWh/d 318 kWh/d 304 kWh/d 293 kWh/d 299 kWh/d 377 kWh/d 431 kWh/d 494 kWh/d 141.000 kWh/a

56,48%

actually used 496 kWh/d 499 kWh/d 430 kWh/d 377 kWh/d 324 kWh/d 318 kWh/d 304 kWh/d 293 kWh/d 299 kWh/d 377 kWh/d 431 kWh/d 494 kWh/d 141.000 kWh/a

% distribution need 10,91 9,91 9,45 8,02 7,12 6,77 6,69 6,45 6,36 8,28 9,18 10,86


Calculation of available heat (kWh): produced Surplus heat Heat theoretical 54.480 33.787 49.207 30.460 54.480 34.530 52.722 34.640 54.480 37.675 52.722 38.021 54.480 40.521 54.480 40.947 52.722 38.494 54.480 38.260 52.722 34.579 54.480 34.562 641.455 436.475

real (after loss) 28.043 25.282 28.660 28.751 31.270 31.557 33.632 33.986 31.950 31.756 28.700 28.686 362.275

total (kWh/a)

Utilisation of electrical power: Electrical power produced by CHP: Electrical power demand by biogas plant: Demand for farm and/ or house: Transformation and feed-in losses Available surplus electrical power:

436.933 kWh/a 36.702 kWh/a x 6.991 kWh/a

FALSCH electrical power bought from the grid electrical power bought from the gridWAHR

36.702 0x

0

393.240 kWh/a

Investment costs: Scenario 1 K,T,B

Unit

B B

lump total total

Mixing pit with mixer, 90 m³ Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.) incl. recyclate

1/2 T, 1/2 B T

total total

21.537 19.974

Vertical digester (complete with mixer, heating circuit, sensors, covering, gas storage)

1/3 T, 2/3 B

total

130.661

B T T

£/ m3 total total

K

total

B

total

14.059 14.059

T T T

total total total

22.701 27.967 4.941 55.609

B

£/ m

350

96

33.600 33.600

B

lump £/ m3

5,0 % 1.179 m³/a

391.622 49,0 £/m³

19.581 57.762 77.343

Planning, Approval, Grid Connection, Earth Works Plant design, information, approval procedure, etc. (lump sum in % of invest for construct + technology + CHP) Grid Connection, incl. cables and cable trenching 100 m to next transformer station Earth works, walk way preparation (concrete surface is available already)

Amount

Costs per Unit 5,0 %

Costs [£]

391.622 £

Feeding technology

19.581 6.375 12.000 37.956

41.511

Digester 130.661

Storage of digestate Eco/Manure bags Mixing equipment Piping system digestate

1.440 m³ 1 1

20,2 £/m³ 5.500 3.200

37.788

Cogeneration Unit (CHP) CHP (complete package with engine, generator, measuring and control technology)

75 kW

78.394 78.394

Separate Buildings Working platform, container module, housing pumps and equipment

Technology Plant Electrical equipment Gas equipment (incl. desulphurication, gas quality analysis, condensate pit, gas pipes etc.) Heating equipment (heating circuits, heating pumps, valves, heat supply lines to tank)

Other Technology Local heat distribution system to heat consumers

Other investment costs Unforeseen costs (lump sum in % of investment construct + technology + CHP) Substrate Storage for additional AD feedstock: Silage

Investment costs total:

506.921

Personal contribution: Grant:

Total without VAT

29.088 5.500 3.200

0 0%

0

506.921

126


Cost of Capital/ Ongoing Costs: Scenario 1

reference

Write-off:

Construction/ Buildings

276.868 £

20 years

Technology

151.659 £

12 years

12.638 £/a

78.394 £

7, years

11.199 £/a

Rate of interest:

253.461 £

7,0 %

17.742 £/a

Insurance:

506.921 £

1,5 %

7.604 £/a

276.868 £/a

2,0 %

5.537 £/a

151.659 £/a

3,0 %

4.550 £/a

436.933 kWh/a

0,96 p/kWhel.

4.195 £/a

CHP unit: Gas engine

Maintenance/ Repair

Construction/ Buildings Technology CHP

annual costs 13.843 £/a

Costs for Substrates Costs for substrates are only considered if AD causes additional costs. Costs include necessary effort and labour, machinery. Any gate fees are not listed here Substrate Costs

Manure

cattle (liquid manure

1.100 t/a

0,0 £/t

£/a

Others

grass silage (gener

500 t/a

22,5 £/t

11.250 £/a

maize silage

650 t/a

25,0 £/t

16.250 £/a

straw (in slurry)

100 t/a

0,0 £/t

£/a

dilution water

720 t/a

0,2 £/t

144 £/a

Total Costs Substrates

27.644 £/a

Transport costs digestate off-farm (e.g. material given back to neighbours after AD) Costs for land-spreading digestate on-farm (difference to slurry without AD): Labour costs plant (without digestate spreading, basic substrate production): Other operating costs (lump sum of investment costs without CHP):

0,0 £/t

£/a

1.556 t/a

t/a

km

2,8 £/t

4.356 £/a

375 h/a

15,0 £/h

5.625 £/a

428.527 £/a

1,0 %

4.285 £/a

Total Costs of Capital/ Ongoing Costs

119.219 £/a

Benefits of biogas production: Scenario 1 2009

Year of commissioning :

Wholesale electricity price

5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH

Total electricity value

incl. LECs, ebedded benefits, triad benefits WAHR

14,5 p/kWh


393.240 kWh/a

0,145 £/kWh

57.020 £/a

141.000 kWh/a

0,047 £/kWh

6.599 £/a

Gate fees for waste

£/a

Revenue from selling/ using the heat Improved fertiliser value manure (N):

15 % Losses

4.716 kg N/a

0,12 €/kg N

453 £/a

15 % Losses

5.878 kg N/a

0,56 €/kg N

2.633 £/a

2.516 kg P2O5/a

0,55 €/kg P2O5

1.107 £/a

9.119 kg K2O/a

0,28 €/kg K2O

Digestate fertiliser value

N (N from substr. without manur


P (P from substrates without manure): K (K from substrates without manure):

Digestate fertiliser value Total revenues:

Business Profit/ Losses: Return on investment: Reflux/ reflow of capital: Payback period:

2.043 £/a 69.854 £/a

-49.364 £/a -2,7% 83,7 years -43,4 years

127


11.3.2

Annex to Site 2

Input Substrates: Scenario 2 Manure

Grass Maize Straw Vegetables Dilution Total

Type cattle (liquid manure) poultry manure '1' poultry manure '2' grass silage (general) maize silage straw stock feed potatoes dilution water

Fresh Matter 1.500 1.350 500 1.955 4.500 100 500 6.800 17.205

Density 1,00 t/m³ 0,45 t/m³ 0,45 t/m³ 0,64 t/m³ 0,72 t/m³ 0,15 t/m³ 0,75 t/m³ 1,00 t/m³ #BEZUG!

Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 %

Input FM 1.500 1.350 500 1.955 4.500 100 500 6.800 17.205

t/a t/a t/a t/a t/a t/a t/a t/a t/a

8% 55 % 55 % 34 % 31 % 86 % 20 % % 19,7 %

Input [DM] 120 t/a 743 t/a 275 t/a 665 t/a 1.395 t/a 86 t/a 100 t/a t/a 3.383 t/a

Gas Yield/ oDM 350 L/kg oDM 490 L/kg oDM 490 L/kg oDM 540 L/kg oDM 670 L/kg oDM 320 L/kg oDM 560 L/kg oDM

Gas Yield/ FM 22 m³/ t FM 202 m³/ t FM 202 m³/ t FM 162 m³/ t FM 195 m³/ t FM 253 m³/ t FM 101 m³/ t FM

Methane Content 59 % 62 % 62 % 54 % 52 % 51 % 52 % 54,7 %

Flow Biogas 92 m³/d 748 m³/d 277 m³/d 865 m³/d 2.407 m³/d 69 m³/d 138 m³/d 4596 m³/d 1.677.686 m³/a

Flow Methane 54 m³/d 464 m³/d 172 m³/d 467 m³/d 1.252 m³/d 35 m³/d 72 m³/d 2516 m³/d 918.206 m³/a

while stock inside 182,5 d/a 8,29 t/d 3,70 t/d 1,37 t/d 5,21 t/d 11,99 t/d 0,27 t/d 1,33 t/d 18,63 t/d 50,79 t/d 18,6 % 54,9 % 2522 m³/d 45.010 kg/d 8,41%

stock outside 182,5 d/a 0,00 t/d 3,70 t/d 1,37 t/d 5,50 t/d 12,66 t/d 0,27 t/d 1,41 t/d 18,63 t/d 43,54 t/d 20,9 % 54,6 % 2510 m³/d 37.760 kg/d 9,13%


DM [%FM]

oDM [%DM] Input [oDM] 80 % 263 kg/d 75 % 1.526 kg/d 75 % 565 kg/d 88 % 1.603 kg/d 94 % 3.593 kg/d 92 % 217 kg/d 90 % 247 kg/d % kg/d 86,4 % 8.012 kg/d

water [t/a] 1.380 608 225 1.290 3.105 14 400 6.800 13.822


Daily Gas Yield and Reduction of Biomass (annual mean): Manure

Grass Maize Straw Vegetables Total

cattle (liquid manure) poultry manure '1' poultry manure '2' grass silage (general) maize silage straw stock feed potatoes


Input [oDM] Percentage oDM [%] 263 kg oDM/d 3,28% 1.526 kg oDM/d 19,04% 565 kg oDM/d 7,05% 1.603 kg oDM/d 20,00% 3.593 kg oDM/d 44,84% 217 kg oDM/d 2,71% 247 kg oDM/d 3,08% 8.012 kg oDM/d 100,00% 19,66% 17,00% 86,44%

Variation throughout the year cattle (liquid manure) poultry manure '1' poultry manure '2' grass silage (general) maize silage straw stock feed potatoes dilution water Total DM-content input Flow Biogas equalised, Methane content: Flow Methane Daily amount digestate DM-content digestate

0,57 m³/kg oDM 54,73% 1,23 kg/m³ 0,028 kg/m³ 128,70 kg Condens./d 5653,6 kg/d 5782,3 kg/d 5653,6 kg/d 41.355 kg/d reduction: 12,27% mass 3.615 kg/d reduction: 60,99% DM 2358,7 kg/d reduction: 70,56% oDM 8,74% 5,70%


(dairy cows in neighbourhood kept free range)

note: values for solid/liquid separator (distribution DM, N, P, K between the phases) were taken from experimental results with digestate from AD plant run on poultry manure as main feedstock Solid/Liquid-Separator Solid Phase Liquid Phase DM-content 27,0 % DM 5,95 % DM DM distribution 41,0 % 59,0 % amount DM 1482,3 kg/d 2133,1 kg/d digestate 5490,2 kg/d 35864,6 kg/d

Nutrients from manure and other substrates: Manure

cattle (liquid manure) poultry manure '1' poultry manure '2' grass silage (general) maize silage straw stock feed potatoes

Grass Maize Straw Vegetables Total From manure From other substrates

Substrate [DM] 120 t/a 743 t/a 275 t/a 665 t/a 1395 t/a 86 t/a 100 t/a 3383 t/a

N 56,8 kg/ t DM 49,6 kg/ t DM 49,6 kg/ t DM 25,6 kg/ t DM 13,6 kg/ t DM 6,4 kg/ t DM 15,5 kg/ t DM 28,19 kg/ t DM

P2O5 18,4 kg/ t DM 44,2 kg/ t DM 44,2 kg/ t DM 8,7 kg/ t DM 5,5 kg/ t DM 3,5 kg/ t DM 6,2 kg/ t DM 18,2 kg/ t DM

K2 O 69,2 kg/ t DM 38,9 kg/ t DM 38,9 kg/ t DM 34,9 kg/ t DM 16,9 kg/ t DM 1,81 kg/ t DM 27,7 kg/ t DM 28,84 kg/ t DM

N

P2O5 6,82 t/a 36,83 t/a 13,64 t/a 17,02 t/a 18,97 t/a 0,55 t/a 1,55 t/a 95,37 t/a 57,28 t/a 38,09 t/a

2,21 t/a 32,82 t/a 12,16 t/a 5,78 t/a 7,67 t/a 0,3 t/a 0,62 t/a 61,56 t/a 47,18 t/a 14,38 t/a

Main Digester / Second Digester / Digestate Storage no after-digester Main Digester:

2 item

Diameter: Height/ Length: Freeboard Effective Digester volume: Organic loading rate input (annual mean): Theoretical retention time (annual mean): oDM of Input oDM of Outflow

After-Digester:


Diameter: Height: Freeboard Effective Digester volume: Organic loading rate input (annual mean): Theoretical retention time (annual mean):

8.012 kg oDM/d 2.359 kg oDM/d


item


47,1 m³/d 0,0 m³/d 47,1 m³/d 5,0 % 49,5 m³/d 39,4 m³/d

0,0 m 0,0 m 0,0 m m³ #DIV/0! days 2.359 kg oDM/d 2.359 kg oDM/d


39,4 m³/d

Surplus volume due to bubbles, foam etc. Theoretic. volume in digester Flow rate effluent digester

5,0 % 41,4 m³/d 39,4 m³/d


Organic loading while stock inside: Th. retention time while stock inside: Organic loading while stock outside: Th. retention time while stock outside:

K2O 8,3 t/a 28,88 t/a 10,7 t/a 23,2 t/a 23,58 t/a 0,16 t/a 2,77 t/a 97,58 t/a 47,88 t/a 49,7 t/a

2003,9 t/a amount oDM 967,1 kg/d oDM-content 17,6 % oDM N distribution 13,0 % amount N 12398,5 kg/a N content 6,19 kg/t effective 5,26 kg/t P distribution 37,0 % amount P2O5 22776,4 kg/a P2O5 content 11,37 kg/t K distribution 13,0 % amount K2O 12685,9 kg/a K2O content 6,33 kg/t

storage capacity mimimum for already available and usable Storage = Eco/Manure Bags:

13090,6 t/a 1391,6 kg/d 3,9 % oDM 87,0 % 82974,3 kg/a 6,34 kg/t 5,39 kg/t 63,0 % 38781,5 kg/a 2,96 kg/t 87,0 % 84898,0 kg/a 6,49 kg/t


Mass flow from digested substrate: 15094,47 t/a Mass flow of recyclate , t/a Total mass flow 15094,47 t/a Total flow rate of material for storage: 14375,7 m³/a minus Existing: Necessary storage capacity total 7801,7 m³ Necessary Surplus to after-digester 7801,7 m³ 7801,7 m³ 2 item No. of Eco/Manure Bags 39,0 m Lengh 40,0 m Width 2,5 m Height: 7.800 m³ Total storage volume 7.800 m³ Storage time (annual mean): 6,5 months Relevant digestate for storage (winter/summer feeding varies) Maximum digestate 182 days 7.802 m³ Minimum storage volume 7.802 m³ Digestate production: Mass flow digestate 15094,47 t/a Flow rate digestate 14375,7 m³/a


Balancing of CHP-Unit: CHP Type:


499 kW


WAHR lower than efficiency at full power, as engine is not run at full power 3.507.547 kWh/a 3.994.196 kWh/a


87,9 %

128


Balancing of process energy demand (electrical and thermal energy): Senario 2 Electrical energy demand for biogas process: Thermal energy demand for biogas process: Calculation of thermal energy demand for biogas process: Digester:

1

Month



outside


38 °C

7,7 %

270.081 kWh/a

21,7 %

867.047 kWh/a

∆T K 32 32 31 29 27 24 22 22 24 26 29 31

Heat Loss kWh/day 778,3 783,1 749,2 708,0 647,4 579,5 540,7 535,8 569,8 630,4 712,8 746,8



Process energy kWh/day 2836,8 2842,6 2736,2 2555,6 2286,0 2073,3 1895,5 1824,1 1996,0 2200,0 2561,4 2733,3 incl. 20% heat losses from CHP to digester 867.047

Total:

Heat utilisation: Heat produced by CHP: Process energy demand for biogas plant: Theoretically available surplus heat: Losses during transformation and transport: Real available surplus heat: Monthly distribution of available surplus heat:


actually available 6.971 kWh/d 6.966 kWh/d 7.058 kWh/d 7.213 kWh/d 7.445 kWh/d 7.628 kWh/d 7.781 kWh/d 7.842 kWh/d 7.694 kWh/d 7.519 kWh/d 7.208 kWh/d 7.060 kWh/d 2.689.349 kWh/a

need (customer) 422 kWh/d 425 kWh/d 366 kWh/d 321 kWh/d 276 kWh/d 271 kWh/d 259 kWh/d 250 kWh/d 254 kWh/d 321 kWh/d 367 kWh/d 420 kWh/d 120.000 kWh/a

3.994.196 kWh/a 867.047 kWh/a 3.127.149 kWh/a 437.801 kWh/a

14 %

2.689.349 kWh/a

67,33%




Calculation of available heat (kWh): produced Surplus heat Heat theoretical 339.233 251.293 306.404 226.812 339.233 254.410 328.290 251.624 339.233 268.368 328.290 266.092 339.233 280.473 339.233 282.687 328.290 268.409 339.233 271.033 328.290 251.449 339.233 254.500 3.994.196 3.127.149

real (after loss) 216.112 195.058 218.792 216.396 230.797 228.839 241.207 243.111 230.832 233.089 216.246 218.870 2.689.349

total (kWh/a)

Utilisation of electrical power: Electrical power produced by CHP: Electrical power demand by biogas plant: Demand for farm and/ or house: Transformation and feed-in losses: Available surplus electrical power:

3.507.547 kWh/a 270.081 kWh/a x 56.121 kWh/a

FALSCH electrical power bought from the grid

270.081 0x

electrical power bought from the gridWAHR

0

3.181.345 kWh/a

Investment costs: Scenario 2 Planning, Approval, Grid Connection Plant design, information, approval procedure, etc. (lump sum in % of invest for construct + technology + CHP) Grid Connection, incl cables and cable trenching 150 m to next transformer station Earth Works, Walk Way preparation

K,T,B

Unit

B B

lump total total

Amount


Costs [£]

865.382 £

Feeding technology Mixing pit 90 m³ with mixer Solid feeder 20,0 m³ incl. screw conveyor + additional screw Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.)

1/2 T, 1/2 B T T

total total


1/3 T, 2/3 B

total

B T T

25.961 22.725 64.800 113.486 21.537 48.874 17.271 87.682

Digester 2

147387,1 £

294.774

£/ m3 total total

7.800 m³ 2 2

15,2 £/m³ 5.500 3.200

118.560 11.000 6.400

K

total

499 kW

B

total

15.566 15.566

T T T T

total total total total

42.249 32.308 5.435 19.200 99.193

B

£/ m

B

lump £/ m3

294.774

Storage of digestate Eco/ Manure bags Mixing equipment Piping system digestate

135.960


213.008 213.008


Technology Plant Control cabinet, visualisation, electrical equipment Gas equipment (incl. desulphurication, gas quality analysis, condensate pit, gas pipes etc.) Heating equipment (heating circuits, heating pumps, valves, heat supply lines to tank) Solid/ Liquid Separator


200 m

96

19.200 19.200

5,0 % 6979 m³

865.382 49,0 £/m³

43.269 341.947 385.216

Other investment costs Unforeseen costs (lump sum in % of investment construct + technology + CHP) Substrate Storage for additional AD feedstock


1.364.085

Personal contribution:

0

Grant:

Total without VAT

0%

0

1.364.085

129



reference

Write-off:


836.236 £

20 years

41.812 £/a

Technology

314.841 £

12 years

26.237 £/a

Gas engine

213.008 £

7, years

30.430 £/a

682.042 £

7,0 %

47.743 £/a

Rate of interest: Insurance: Maintenance/ Repair


annual costs

1.364.085 £

1,5 %

20.461 £/a

836.236 £/a

2,0 %

16.725 £/a

314.841 £/a

3,0 %

9.445 £/a

3.507.547 kWh/a

0,96 p/kWhel.

33.672 £/a


Manure

cattle (liquid manure

1.500 t/a transport only

poultry manure '1'

1.350 t/a

poultry manure '2' Others

500 t/a transport only

2,14 £/t

3.216 £/a

0,0 £/t

£/a

2,63 £/t

1.316 £/a

grass silage (gener

1.955 t/a

22,5 £/t

43.988 £/a

maize silage

4.500 t/a

25,0 £/t

112.500 £/a

straw

100 t/a

50,0 £/t

5.000 £/a

stock feed potatoes

500 t/a

22,0 £/t

11.000 £/a

6.800 t/a

0,2 £/t

1.360 £/a

dilution water Total Costs Substrates

178.380 £/a

Transport costs digestate off-farm (e.g. material given back to neighbours after AD)

1.903 t/a

2,48 £/t

4.719 £/a

(before AD: poultry manure), difference:

25.618 £/a

1.996 h/a

15,0 £/h

29.940 £/a

1.151.077 £/a

1,0 %

11.511 £/a

Costs for land-spreading digestate on-farm (difference to situation without AD): Labour costs plant (without digestate spreading, basic substrate production): Other operating costs (lump sum of investment costs without CHP):


476.692 £/a

Benefits of biogas production: scenario 2 2009



5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh


3.181.345 kWh/a

0,145 £/kWh

461.295 £/a

120.000 kWh/a

0,047 £/kWh

5.616 £/a

Gate fees for waste

£/a


15 % Losses

48.691 kg N/a

0,12 €/kg N

4.674 £/a

15 % Losses

41.258 kg N/a

0,56 €/kg N

18.483 £/a

7.113 kg P2O5/a

0,55 €/kg P2O5

3.130 £/a




P (P from substrates without manure):

Digestate fertiliser value K (K from substrates without manure): 56.655 kg K2O/a 0,28 €/kg K2O 12.691 £/a (when calculating digestate fertiliser value, only nutrients remaining on own farm are considered, not digestate given back to neighbours) Total revenue:


505.889 £/a

29.198 £/a 9,1% 7,8 years 10,7 years

130


11.3.3

Annex to Site 3

Input Substrates: Scenario 3 Type Manure cattle slurry (half-stackable, lagoon) Grass grass silage (general) Straw straw Dilution dilution water Total incl. dilution water

Fresh Matter 563 3.600 100 2.400 6.663


Density 1,05 t/m³ 0,64 t/m³ 0,15 t/m³ 1,00 t/m³ #BEZUG!

Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 %

1,05 t/m³

Gas Yield/ oDM 310 L/kg oDM 540 L/kg oDM 320 L/kg oDM L/kg oDM

t/a t/a t/a t/a t/a

2.625 t/a 9.288 t/a

Input FM 563 3.600 100 2.400 6.663

t/a t/a t/a t/a t/a

DM [%FM] 16 % 34 % 86 % % 21,0 %

Input [DM] 90 t/a 1.224 t/a 86 t/a t/a 1.400 t/a

0,0 %

2.625 t/a 9.288 t/a

5,34 % 16,6 %

140 t/a 1.540 t/a

Gas Yield/ FM 39 m³/ t FM 162 m³/ t FM 253 m³/ t FM m³/ t FM

Methane Content 59 % 54 % 51 % % 54,1 %

Flow Biogas 60 m³/d 1.594 m³/d 69 m³/d m³/d 1723 m³/d 628.745 m³/a

Flow Methane 35 m³/d 861 m³/d 35 m³/d m³/d 931 m³/d 339.852 m³/a

cattle slurry (half-stackable, lagoon) grass silage (general) straw dilution water Recyclate Total incl recyclate DM content input incl. water and recyclate

while stock inside 151,0 d/a 3,73 t/d 9,36 t/d 0,26 t/d 6,58 t/d 5,55 t/d 25,47 t/d 16,9 %

stock outside 214,0 d/a 0,00 t/d 10,22 t/d 0,28 t/d 6,58 t/d 8,35 t/d 25,43 t/d 16,4 %


54,3 % 935 m³/d 17.758 kg/d 10,61%

53,9 % 928 m³/d 14.909 kg/d 10,73%

oDM [%DM] Input [oDM] 78 % 192 kg/d 88 % 2.951 kg/d 92 % 217 kg/d % kg/d 87,6 % 3.360 kg/d %

kg/d

water [t/a] 473 2.376 14 2.400 5.263

t/a t/a t/a t/a t/a

2.485 t/a 7.748 t/a

Daily Gas Yield and Reduction of Biomass (annual mean): Manure Grass Straw Dilution Total

cattle slurry (half-stackable grass silage (general) straw dilution water


Input [oDM] Percentage oDM [%] 192 kg oDM/d 5,73% 2.951 kg oDM/d 87,82% 217 kg oDM/d 6,45% kg oDM/d 0,00% 3.360 kg oDM/d 100,00% 21,01% 18,41% 87,60%

Variation throughout the year

0,51 m³/kg oDM 54,05% 1,23 kg/m³ 0,028 kg/m³ 2118,8 kg/d 2167,0 kg/d 2118,8 kg/d 16.088 kg/d 1.717 kg/d 1241,5 kg/d 10,67% 7,72%

48,23 kg Condens./d



dairy cows in the neighbourhood

Nutrients from manure and other substrates: Manure cattle slurry (half-stackable Grass grass silage (general) Straw straw Total From manure From other substrates

Substrate DM 90 1224 86 1400

t/a t/a t/a t/a

N 56,8 kg/ t DM 25,6 kg/ t DM 6,4 kg/ t DM 26,43 kg/ t DM

P 2 O5 18,4 kg/ t DM 8,7 kg/ t DM 3,5 kg/ t DM 9, kg/ t DM

K2O 69,2 kg/ t DM 34,9 kg/ t DM 1,81 kg/ t DM 35,07 kg/ t DM

N

P2O5 5,12 t/a 31,33 t/a 0,55 t/a 37, t/a 5,12 t/a 31,88 t/a

1,66 t/a 10,65 t/a 0,3 t/a 12,61 t/a 1,66 t/a 10,95 t/a


1 item


After-Digester (not heated):






18,3 m³/d 7,2 m³/d 25,4 m³/d 5,0 % 26,7 m³/d 23,2 m³/d

23,2 m³/d 7,2 m³/d

Surplus volume due to bubbles, foam etc. Theoretic. volume in digester Flow rate effluent digester incl. recyclate Flow rate effluent digester without recyclate Digester volume occupied by recyclate Effective reactor occupied by substrate Organic loading while stock inside: Th. retention time while stock inside: Organic loading while stock outside: Th. retention time while stock inside:

3,05 g/L

25,0 m 6,4 m 0,3 m 2.994 m³ 0,6 kg oDM/m³·d 123 days 1.771 kg oDM/d 1.241 kg oDM/d

Flow rate into digester: Of this: recyclate

1,9 kg oDM/m³·d 69 days 1,8 kg oDM/m³·d 69 days

1 item

5,0 % 24,4 m³/d 22,5 m³/d 15,3 m³/d 882,2 m³ 2.112,2 m³ 0,6 kg oDM/m³·d 123 days 0,6 kg oDM/m³·d 123 days

K2O 6,23 t/a 42,72 t/a 0,16 t/a 49,11 t/a 6,23 t/a 42,87 t/a

182 days storage capacity mimimum for already available and usable 0,0 m³ "Existing" Storage:= After-Fermenter + Eco/Manure Bags Of After-digester to be considered 2.112 m³ partial storage Mass flow from digested substrate: 5872,04 t/a Mass flow of recyclate 2624,68 t/a Total mass flow 8496,72 t/a Total flow rate of material for storage: 5592,4 m³/a minus Existing: Necessary storage capacity total 2994,0 m³ Necessary Surplus to after-digester 881,8 m³ 881,8 m³ No. of Eco/Manure Bags 1 item 19,0 m Lengh Width 20,0 m 2,5 m Height: 950 m³ Storage volume total: 3.062 m³ Storage time (annual mean): 6,6 months Relevant digestate for storage (amount varies while stock in/out) Maximum digestate 182 days 2.994 m³ Minimum storage volume 2.994 m³ Digestate production: 5872,04 t/a Mass flow digestate Flow rate digestate 5592,4 m³/a

Note: After-Digester is only partially considered as digestate storage capacity, as some of the volume is continuously occupied by recyclate.



190 kW




85,4 %

131



1

Month



outside

Heat transmission coefficient: Insulation: heat conductance λ thickness: Insulation index k-value: Surface of heated Digesters: Surface of storage tank (if heated only): Loss of heat total: Process temperature:

38 °C

8,6 %

111.648 kWh/a

24,5 %

368.588 kWh/a

∆T K 32 32 31 29 27 24 22 22 24 26 29 31

Heat Loss kWh/day 389,1 391,6 374,6 354,0 323,7 289,7 270,3 267,9 284,9 315,2 356,4 373,4



Process energy kWh/day 1.203,9 1.206,8 1.161,0 1.085,5 972,9 881,3 807,2 778,9 850,1 937,3 1.088,4 1.159,6 incl. 20% heat losses from CHP to digester 368.588 kWh/a

Total:

Heat utilisation: Heat produced by CHP: Process energy demand for biogas plant: Theoretically available surplus heat: Losses during transformation and transport:


17 %

Real available surplus heat:

940.851 kWh/a

62,63%

Monthly distribution of available surplus heat:


actually available 2.417 kWh/d 2.414 kWh/d 2.452 kWh/d 2.515 kWh/d 2.608 kWh/d 2.684 kWh/d 2.746 kWh/d 2.769 kWh/d 2.710 kWh/d 2.638 kWh/d 2.512 kWh/d 2.453 kWh/d 940.851 kWh/a

need (customer) 12.318 kWh/d 12.388 kWh/d 10.669 kWh/d 9.357 kWh/d 8.039 kWh/d 7.898 kWh/d 7.553 kWh/d 7.282 kWh/d 7.420 kWh/d 9.348 kWh/d 10.710 kWh/d 12.261 kWh/d 3.500.000 kWh/a

actually used 2.417 kWh/d 2.414 kWh/d 2.452 kWh/d 2.515 kWh/d 2.608 kWh/d 2.684 kWh/d 2.746 kWh/d 2.769 kWh/d 2.710 kWh/d 2.638 kWh/d 2.512 kWh/d 2.453 kWh/d 940.851 kWh/a




real (after loss) 74.915 67.598 76.018 75.447 80.859 80.530 85.121 85.850 81.308 81.775 75.375 76.055 940.851

total (kWh/a)

Utilisation of electrical power: Electrical power produced by CHP: Electrical power demand by biogas plant: Demand for farm and/ or house: Transformation and feed-in losses

Available surplus electrical power:

1.298.233 kWh/a 111.648 kWh/a x 20.772 kWh/a


111.648 0x

0

1.165.813 kWh/a

Investment costs: scenario 3 K,T,B

Unit

B B

lump total total

Mixing pit with mixer, pump, 90 m³ Solid feeder incl. screw conveyor, 20 m³ Substrate transport equipment (pumps,substrate lines between tanks, valves, etc.) incl. recyclate

1/2 T, 1/2 B T T

total total total

Vertical digester (complete with mixer, heating circuit, sensors, covering, gas storage) After-digester (not heated), covered, incl. gas storage, mixer = storage tank

1/3 T, 2/3 B 1/3 T, 2/3 B

total total

Planning, Approval, Grid Connection, Earth Works Plant design, information, approval procedure, etc. (lump sum in % of invest for construct + technology + CHP) Grid Connection incl. cables and cable trenching 100 m to next transformer station Earth works, walk way preparation

Amount


Costs [£]

686.627 £

Feeding technology

30.898 10.250 45.600 86.748 21.537 43.274 19.973 84.784

Digester 1.854 m³ 2.994 m³

147.387 126.946 274.333

Storage of digestate (After-digester can be partially considered as digestate storage capacity. Therefore only limited additional storage capacity is necessary) Eco/Manure bags Mixing equipment Piping system digestate

B T T

£/ m3 total total

950,0 m³ 1 1

24,7 £/m³ 5.500 3.200

K

total

B

total

15.464 15.464

T T T

total total total

40.811 30.763 4.941 76.516

B

£/ m

850

96

81.600 81.600

B

lump £/ m3

5,0 % 2.969 m³

686.627 49,0 £/m³

34.331 145.469 179.800

32.165


190 kW

121.765 121.765


Technology Plant Control cabinet, visualisation, Electrical equipment Gas equipment (incl. desulphurication, gas quality analysis, condensate pit, gas pipes etc.) Heating equipment (heating circuits, heating pumps, valves, heat supply lines to tank)


Other investment costs Unforeseen costs (lump sum in % of investment construct + technology + CHP) Substrate Storage for additional AD feedstock: Silage


953.176


Total without VAT

23.465 5.500 3.200

0 0%

0

953.176

132



reference

Write-off:


558.992 £

20 years

27.950 £/a

Technology

272.419 £

12 years

22.702 £/a

Gas engine

121.765 £

7, years

17.395 £/a

Rate of interest:

476.588 £

7,0 %

33.361 £/a

Insurance:

953.176 £

1,5 %

14.298 £/a

558.992 £/a

2,0 %

11.180 £/a

Maintenance/ Repair


annual costs

272.419 £/a

3,0 %

8.173 £/a

1.298.233 kWh/a

0,96 p/kWhel.

12.463 £/a


Manure

cattle slurry (half-sta

Others

grass silage (gener straw dilution water


563 t/a

0,0 £/t

£/a

3.600 t/a

22,5 £/t

81.000 £/a

100 t/a

50,0 £/t

5.000 £/a

2.400 t/a

0,2 £/t

480 £/a

86.480 £/a

Transport costs digestate off-farm (e.g. material given back to neighbours after AD) Costs for land-spreading digestate on-farm (difference to manure without AD): Labour costs plant (without digestate spreading, basic substrate production): Other operating costs (lump sum of investment costs without CHP):

0,0 £/t

£/a

5.309 t/a

t/a

km

2,8 £/t

14.865 £/a

950 h/a

15,0 £/h

14.250 £/a

831.410 £/a

1,0 %

8.314 £/a


271.430 £/a




5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh


1.165.813 kWh/a

0,145 £/kWh

169.043 £/a

940.851 kWh/a

0,047 £/kWh

44.032 £/a

15 % Losses

4.349 kg N/a

0,12 €/kg N

418 £/a

15 % Losses

27.102 kg N/a

0,56 €/kg N

12.142 £/a

10.950 kg P2O5/a

0,55 €/kg P2O5

4.818 £/a

42.873 kg K2O/a

0,28 €/kg K2O

9.604 £/a

Gate fees for waste

£/a

Revenue from selling/ using the heat Improved fertiliser value manure (N): Digestate fertiliser value




Digestate fertiliser value Total revenue:

240.056 £/a

Business Profit/ Losses:

-31.374 £/a

Return on investment:

3,7%

Reflux/ reflow of capital:

13,6 years

Payback period:

26,0 years

133


11.3.4

Annex to Site 4

Input Substrates: Scenario 4 Type cattle (liquid manure) solid cow manure grass silage (general) straw (in slurry/ manure) crop grain whole crop wheat silage sawdust (in slurry) dilution water

Manure Grass Straw Cereals Others Dilution Total

Fresh Matter 4.960 350 500 75 100 500 14 315 6.814




Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 %

1,05 t/m³

Gas Yield/ oDM 350 L/kg oDM 330 L/kg oDM 540 L/kg oDM 320 L/kg oDM 730 L/kg oDM 570 L/kg oDM 0. L/kg oDM

2.530 t/a 9.344 t/a

Input FM 4.960 350 500 75 100 500 14 315 6.814


DM [%FM] 8% 22 % 31 % 86 % 85 % 38 % 75 % % 14,4 %

Input [DM] 397 t/a 77 t/a 155 t/a 65 t/a 85 t/a 190 t/a 11 t/a t/a 979 t/a

0,0 %

2.530 t/a 9.344 t/a

4,01 % 11,6 %

102 t/a 1.080 t/a

Gas Yield/ FM 22 m³/ t FM 57 m³/ t FM 147 m³/ t FM 253 m³/ t FM 583 m³/ t FM 201 m³/ t FM 0. m³/ t FM

Methane Content 59 % 59 % 54 % 51 % 53 % 53 % % 55,1 %

Flow Biogas 304 m³/d 54 m³/d 202 m³/d 52 m³/d 160 m³/d 276 m³/d m³/d 1048 m³/d 382.615 m³/a

Flow Methane 180 m³/d 32 m³/d 109 m³/d 27 m³/d 85 m³/d 146 m³/d m³/d 578 m³/d 210.998 m³/a

while stock inside 135,0 d/a 28,93 t/d 0,96 t/d 0,66 t/d 0,45 t/d 0,00 t/d 0,66 t/d 0,07 t/d 0,00 t/d 0,00 t/d 31,74 t/d 10,8 % 56,9 % 596 m³/d 30.423 kg/d 7,03%

stock outside 230,0 d/a 4,53 t/d 0,96 t/d 1,79 t/d 0,06 t/d 0,44 t/d 1,79 t/d 0,02 t/d 1,37 t/d 11,00 t/d 21,95 t/d 12,2 % 54,1 % 567 m³/d 9.629 kg/d 9,89%

oDM [%DM] Input [oDM] 80 % 870 kg/d 78 % 165 kg/d 88 % 374 kg/d 92 % 163 kg/d 94 % 219 kg/d 93 % 484 kg/d 94 % 27 kg/d % kg/d 85,8 % 2.301 kg/d %

water [t/a] 4.563 273 345 11 15 310 4 315 5.835

kg/d


2.428 t/a 8.264 t/a

Daily Gas Yield and Reduction of Biomass (annual mean): Manure Grass Straw Cereals Others Total

cattle (liquid manure) 0 solid cow manure grass silage (general) straw (in slurry/ manure) crop grain whole crop wheat silage sawdust (in slurry)


Input [oDM] Percentage oDM [%] 870 kg oDM/d 37,80% 165 kg oDM/d 7,15% 374 kg oDM/d 16,24% 163 kg oDM/d 7,07% 219 kg oDM/d 9,52% 484 kg oDM/d 21,04% 27 kg oDM/d 1,18% 2.301 kg oDM/d 100,00% 14,36% 12,32% 85,79%

Variation throughout the year cattle (liquid manure) solid cow manure grass silage (general) straw (in slurry/ manure) crop grain whole crop wheat silage sawdust (in slurry) dilution water Recyclate Total incl. dilution and recyclate DM-content input incl. dilution and recyclate Flow Biogas equalised, Methane content: Flow Methane Daily amount digestate DM-content digestate


29,35 kg Condens./d


energy content 2.110, MWh/a

Nutrients from manure and other substrates: Manure Grass Straw Cereals

cattle (liquid manure) 0 solid cow manure grass silage (general) straw (in slurry/ manure) crop grain 0 whole crop wheat silage sawdust (in slurry)

Others Total From manure (including litter material) From other substrates

Substrate [DM] 397 t/a 77 t/a 155 t/a 65 t/a 85 t/a 190 t/a 11 t/a 979 t/a

N 56,8 kg/ t DM 22, kg/ t DM 25,6 kg/ t DM 6,4 kg/ t DM 24,4 kg/ t DM 14,2 kg/ t DM 6,4 kg/ t DM 34,18 kg/ t DM

P2O5 18,4 kg/ t DM 12,5 kg/ t DM 8,7 kg/ t DM 3,5 kg/ t DM 9,3 kg/ t DM 6,2 kg/ t DM 3,5 kg/ t DM 12,1 kg/ t DM

K 2O 69,2 kg/ t DM 29, kg/ t DM 34,9 kg/ t DM 1,81 kg/ t DM 7, kg/ t DM 10,8 kg/ t DM 1,81 kg/ t DM 38,7 kg/ t DM

N



Main Digester / Second Digester / Storage Main Digester:

1 item

Diameter: Height/ Length: Freeboard Digester volume: Organic loading rate input: Theoretical retention time: oDM of Input oDM of Outflow


Diameter: Height: Height of Gasholder: Volume: Organic loading rate input: Theoretical retention time:




After-Digester:


18,7 m³/d 6,9 m³/d 25,6 m³/d 5,0 % 26,9 m³/d 23,5 m³/d



23,5 m³/d


0,0 % 23,5 m³/d 16,5 m³/d




182 days storage capacity mimimum for already available and usable 2427,0 m³ "Existing" Storage: Eco/Manure Bags + Existent: Mass flow from digested substrate: Mass flow of recyclate Total mass flow Of this flow rate for storage: Necessary storage capacity total

6332,74 t/a 2529,91 t/a 8862,65 t/a 6031,2 m³/a minus Existing: 4342,5 m³ 4342,5 m³ 1915,5 m³ No. of Eco/Manure Bags 1 item Lengh 28,0 m Width 28,0 m Height: 2,5 m 1.960 m³ Storage volume (total): 4.387 m³ Storage time (annual mean): 8,7 months Relevant digestate for storage (amount varies while stock in/out) 4.343 m³ Maximum digestate 182 days Minimum storage volume 4.343 m³ Digestate production: 6332,74 t/a Mass flow digestate Flow rate digestate 6031,2 m³/a




104 kW


WAHR effective efficiency (lower than efficiency at full power, as engine is not run at full power) 803.902 kWh/a 930.501 kWh/a


96,6 %

134



1

Month



outside


38 °C

9,1 %

73.155 kWh/a

40,2 %

373.646 kWh/a

∆T K 32 32 31 29 27 24 22 22 24 26 29 31

Heat Loss kWh/day 389,1 391,6 374,6 354,0 323,7 289,7 270,3 267,9 284,9 315,2 356,4 373,4



Total:

Processenergy kWh/day 1.220,6 1.223,5 1.177,1 1.100,4 986,1 893,4 818,2 789,3 861,6 949,9 1.103,4 1.175,7 incl. 20% heat losses from CHP to digester 373.646



20 %


445.484 kWh/a

47,88%




need (customer) 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/a

actually used 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d 0 kWh/d kWh/a




real (after loss) 32.952 29.698 34.030 34.773 38.767 39.742 42.933 43.649 40.505 39.665 34.703 34.066 445.484 total (kWh/a)

Utilisation of electrical power: Electrical power produced by CHP: Electrical power demand by biogas plant: Demand for farm and/ or house: Transformation and feed-in losses:


803.902 kWh/a 73.155 kWh/a x 12.862 kWh/a


73.155 0x

0

717.885 kWh/a


Unit

B B

lump total total

Mixing pit with agitator, 90 m³ Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.) incl. recyclate

1/2 T, 1/2 B T

total total

21.537 19.974 41.511


1/3 T, 2/3 B

total

147.387

B T T

£/ m3 total total

1.960 m³ 1 1

K

total

104 kW

B

total

14.059 14.059

T T T

total total total

22.701 27.967 4.941 55.609

B T

lump £/ t total

Planning, Approval, Grid Connection, Earth Works Plant design, information, approval procedure, etc. (lump sum in % of invest for construct + technology + CHP) Grid Connection incl. cables and cable trenching 30 m to next transformer station Earth Works, Walk Way preparation

Amount


388.322 £

Feeding technology

Costs [£] 19.416 4.650 24.000 48.066

Digester 147.387


19,1 £/m³ 5.500 3.200

46.136


83.620 83.620



Other investment costs Unforeseen costs (lump sum in % of investment construct + technology + CHP) Storage crop grain Straw chopper (not included in modelling)

5,0 % 100 t

388.322 143 £/t


Total without VAT

19.416 14.250 0 33.666

470.054


37.436 5.500 3.200

0 0%

0

470.054

135



reference

Write-off:


229.309 £

20 years

11.465 £/a

Technology

157.125 £

12 years

13.094 £/a

Gas engine

83.620 £

7, years

11.946 £/a

Rate of interest:

235.027 £

7,0 %

16.452 £/a

Insurance:

470.054 £

1,5 %

7.051 £/a

229.309 £/a

2,0 %

4.586 £/a

157.125 £/a

3,0 %

4.714 £/a

803.902 kWh/a

0,96 p/kWhel.

7.717 £/a

Maintenance/ Repair


annual costs


Manure

Others

slurry main site

3.481 t/a

0,0 £/t

£/a

slurry site 2 + 3

1.479 t/a

max. 5,6 km

2,93 £/t

4.331 £/a

solid cow manure

350 t/a

5,6 km

2,93 £/t

1.025 £/a

grass silage (gener

500 t/a

22,5 £/t

11.250 £/a

crop grain

100 t/a

105,0 £/t

10.500 £/a

whole crop wheat s

500 t/a

32,0 £/t

16.000 £/a

sawdust (in slurry)

14 t/a

0,0 £/t

£/a

315 t/a

0,2 £/t

63 £/a

dilution water Total Costs Substrates

43.168 £/a

Transport costs digestate off-farm (e.g. material given back to neighbours after AD) Costs for land-spreading digestate on-farm (difference to slurry without AD): Labour costs plant (without digestate spreading, substrate transport): Other operating costs (lump sum of investment costs without CHP):

0,0 £/t

£/a

948 t/a

t/a

km

2,8 £/t

2.654 £/a

520 h/a

15,0 £/h

7.800 £/a

386.434 £/a

1,0 %

3.864 £/a


134.511 £/a




5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh


717.885 kWh/a

0,145 £/kWh

104.093 £/a

0 kWh/a

0,047 £/kWh

£/a

15 % Losses

21.005 kg N/a

0,12 €/kg N

2.017 £/a

15 % Losses

7.429 kg N/a

0,56 €/kg N

3.328 £/a

3.317 kg P2O5/a

0,55 €/kg P2O5

1.459 £/a

8.057 kg K2O/a

0,28 €/kg K2O

Gate fees for waste

£/a



P (P from substrates without manure): Digestate fertiliser value K (K from substrates without manure): Digestate fertiliser value

1.805 £/a

Total revenue:

112.702 £/a


-21.809 £/a


2,4%


15,1 years

Payback period:

32,0 years

136


11.3.5

Annex to Site 5

Input Substrates: Scenario 5 Manure Straw Vegetables Total

Type cattle (liquid manure) straw (in slurry) stock feed potatoes

Fresh Matter 16.000 1.170 500 17.670

Density 1,00 t/m³ 0,15 t/m³ 0,75 t/m³ #BEZUG!

Losses [%FM] 0,0 % 0,0 % 0,0 %

Input FM 16.000 1.170 500 17.670

t/a t/a t/a t/a

8% 86 % 20 % 13,5 %

Input [DM] 1.280 t/a 1.006 t/a 100 t/a 2.386 t/a

Gas Yield/ oDM 350 L/kg oDM 320 L/kg oDM 560 L/kg oDM

Gas Yield/ FM 22 m³/ t FM 253 m³/ t FM 101 m³/ t FM

Methane Content 59 % 51 % 52 % 55,1 %

Flow Biogas 982 m³/d 812 m³/d 138 m³/d 1932 m³/d 705.025 m³/a

Flow Methane 579 m³/d 414 m³/d 72 m³/d 1065 m³/d 388.739 m³/a

while stock inside 181,0 d/a 55,25 t/d 4,04 t/d 0,00 t/d 59,29 t/d

stock outside 184,0 d/a 32,61 t/d 2,38 t/d 2,72 t/d 37,71 t/d

2260 m³/d 55,4 % 1252 m³/d 56.445 kg/d 9,06%

1608 m³/d 54,8 % 881 m³/d 35.688 kg/d 9,04%

P2O5 23,55 t/a 3,52 t/a 0,62 t/a 27,69 t/a 27,07 t/a 0,62 t/a

K2O 88,58 t/a 1,82 t/a 2,77 t/a 93,17 t/a 90,4 t/a 2,77 t/a

t/a t/a t/a t/a

DM [%FM]

oDM [%DM] 80 % 92 % 90 % 85,5 %

Input [oDM] 2.805 kg/d 2.536 kg/d 247 kg/d 5.588 kg/d

water [t/a] 14.720 164 400 15.284

t/a t/a t/a t/a

Daily Gas Yield and Reduction of Biomass: Manure Straw Vegetables Total

cattle (liquid manure) straw (in slurry) stock feed potatoes


Input [oDM] Percentage oDM [%] 2.805 kg oDM/d 50,20% 2.536 kg oDM/d 45,38% 247 kg oDM/d 4,41% 5.588 kg oDM/d 100,00% 13,50% 11,54% 85,48%

Variation throughout the year cattle (liquid manure) straw (in slurry) stock feed potatoes Total incl recyclate



50% of dairy cows out

54,08 kg Condens./d


Flow Biogas Methane content Flow Methane Daily amount digestate DM-content digestate

Nutrients from manure and other substrates: Manure cattle (liquid manure) Straw straw (in slurry) Vegetables stock feed potatoes Total From manure (including straw in slurry) From other substrates

Substrate [DM] 1280 t/a 1006 t/a 100 t/a 2386 t/a

N 56,8 kg/ t DM 6,4 kg/ t DM 15,5 kg/ t DM 33,82 kg/ t DM

P2O5 18,4 kg/ t DM 3,5 kg/ t DM 6,2 kg/ t DM 11,61 kg/ t DM

K2O 69,2 kg/ t DM 1,81 kg/ t DM 27,7 kg/ t DM 39,04 kg/ t DM

N 72,7 t/a 6,44 t/a 1,55 t/a 80,69 t/a 79,14 t/a 1,55 t/a

Main Digester / After-Digester / Digestate Storage Main Digester:

1 item

Diameter: Height/ Length: Freeboard: Digester volume (effective): Organic loading rate input: Theoretical retention time: oDM of Input oDM of Outflow







0,0 m 0,0 m 0,0 m m³ days 3.212 kg oDM/d 3.212 kg oDM/d


43,8 m³/d


5,0 % 46,0 m³/d 43,8 m³/d



Mass flow from digested substrate: 16783,08 t/a Mass flow of recyclate , t/a Total mass flow 16783,08 t/a 15983,9 m³/a Total flow rate of material for storage: minus Existing: Necessary storage capacity total 9764,0 m³ Necessary Surplus to after-digester 9764,0 m³ 9764,0 m³ 2 item No. of Eco/Manure Bags Lengh 44,0 m 44,0 m Width Height: 2,5 m 9.680 m³ 9.680 m³ Storage volume total: Storage time (annual mean): 7,3 months Relevant digestate for storage (amount varies while stock in/out) Maximum digestate 182 days 9.764 m³ Minimum storage volume 9.764 m³ Digestate production: Mass flow digestate 16783,08 t/a Flow rate digestate 15983,9 m³/a

#DIV/0!


48,4 m³/d 0,0 m³/d 48,4 m³/d 5,0 % 50,8 m³/d 43,8 m³/d



After-Digester:


Note: The following table gives annual mean values, but more electricity and heat is produced during months when all stock is housed; also the electr. efficiency is higher duringthis time.

250 kW


WAHR

1.461.658 kWh/a 1.780.424 kWh/a

higher capacity necessary due to higher gas production during winter months lower than efficiency at full power, as engine is not run at full power while all stock in:

4.932 kWh/d 5.733 kWh/d 206 kW

while stock outside:


3.155 kWh/d 4.036 kWh/d 131 kW 73,1 %

137



1

Month



outside

Heat transmission coefficient: Insulation: heat conductance λ thickness: Insulation index k-value: Surface of Digesters: Surface of storage tank (if heated only): Loss of heat total:

38 °C

Process temperature:

8,7 %

127.164 kWh/a

44,2 %

787.503 kWh/a

∆T K 32 32 31 29 27 24 22 22 24 26 29 31

Heat Loss kWh/day 523,9 527,2 504,3 476,6 435,8 390,1 364,0 360,7 383,6 424,4 479,9 502,7



Processenergy kWh/day 2.583,0 2.586,9 2.492,1 2.324,0 2.072,9 1.883,2 1.717,1 1.645,8 1.808,0 1.991,8 2.327,9 2.490,1 incl. 20% heat losses from CHP to digester 787.503

Total:


1.780.424 kWh/a 787.503 kWh/a 992.921 kWh/a 168.797 kWh/a

17 %


824.125 kWh/a

46,29%








Note: The following assumes that all stock is housed from Nov to April. Calculation of available heat (kWh): produced Surplus heat Heat theoretical real (after loss) 177.735 97.664 81.061 160.535 88.103 73.125 177.735 100.481 83.399 172.002 102.282 84.894 125.125 60.867 50.519 121.089 64.592 53.611 125.125 71.894 59.672 125.125 74.105 61.507 121.089 66.848 55.484 125.125 63.381 52.606 172.002 102.165 84.797 177.735 100.542 83.450 1.780.424 992.922 824.125 total (kWh/a)



1.461.658 kWh/a 127.164 kWh/a x 23.387 kWh/a


127.164 0x


0

1.311.107 kWh/a


Unit

B B

lump total total

Mixing pit with agitator, 90 m³ Grinder pump Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.)

1/2 T, 1/2 B T T

total total total

21.537 8.400 15.018 44.955


1/3 T, 2/3B

total

201.799

B T T

£/ m3 total total

9.680 m³ 2 2

K

total

250 kW

B

total

14.150 14.150

T T T

total total total

38.408 28.094 4.941 71.444

B

£/ m

400

96

38.400 38.400

lump

5,0 %

670.617

33.531 33.531

Planning, Approval, Grid Connection, Earth Works Plant design, information, approval procedure, etc. (lump sum in % of invest for construct + technology + CHP) Grid Connection incl. cables and cable trenching 900 m to next transformer station Earth works, walk way preparation

Amount


Costs [£]

670.617 £

Feeding technology

26.825 40.750 50.400 117.975

Digester 201.799


14,6 £/m³ 5.500 3.200

158.728


141.140 141.140


Technology Plant Control cabinet, visualisation, electrical equipment Gas equipment (incl. desulphurication, gas quality analysis, condensate pit, gas pipes etc.) Heating equipment (heating circuits, heating pumps, valves, heat supply lines to tank)

Other technology Local heat distribution system to heat consumers

Other investment costs Unforeseen costs (lump sum in % of investment construct + technology + CHP)

Investment costs total: Personal contribution: Grant:

Total without VAT

141.328 11.000 6.400

822.122 0%

0 0

822.122

138


Capital Costs/ Maintenance/ Ongoing Costs: Scenario 5

reference

Write-off:


470.567 £

20 years

23.528 £/a

Technology

210.415 £

12 years

17.535 £/a

Gas engine

141.140 £

7, years

20.163 £/a

Rate of interest:

411.061 £

7,0 %

28.774 £/a

Insurance:

822.122 £

1,5 %

12.332 £/a


470.567 £/a

2,0 %

9.411 £/a

Technology

210.415 £/a

3,0 %

6.312 £/a

1.461.658 kWh/a

0,96 p/kWhel.

14.032 £/a

Maintenance/ Repair

CHP

annual costs


Manure

cattle (liquid manure)

16.000 t/a

0,0 £/t

straw (in slurry)

1.170 t/a

0,0 £/t

£/a

500 t/a

15,0 £/t

7.500 £/a

Others

stock feed potatoes


£/a

7.500 £/a


0,0 £/t

£/a

-387 t/a

t/a

km

2,8 £/t

-1.083 £/a

1.250 h/a

15,0 £/h

18.750 £/a

680.982 £/a

1,0 %

6.810 £/a


164.064 £/a




5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh


1.311.107 kWh/a

0,145 £/kWh

190.111 £/a

144.000 kWh/a

0,047 £/kWh

6.739 £/a

Gate fees for waste

£/a



15 % Losses

67.272 kg N/a

0,12 €/kg N

6.458 £/a

15 % Losses

1.318 kg N/a

0,56 €/kg N

590 £/a

620 kg P2O5/a

0,55 €/kg P2O5

273 £/a

2.770 kg K2O/a

0,28 €/kg K2O

620 £/a

P (P from substrates without manure): Digestate fertiliser value K (K from substrates without manure):


Total revenue:

204.791 £/a


40.727,3 £/a


12,0%


6,3 years

Payback period:

8,1 years

139

Economic Modelling of AD in Cornwall – Annex: Scenario 6 – Option 1

11.3.6

Annex to Site 6

Option 1: No extra energy crops Input Substrates: Scenario 6 Type beef cattle slurry (liquid) pig slurry grass silage (general) straw (in slurry) washing (pigs)

Manure Grass Straw (Water) Total

Fresh Matter 1.500 17.500 1.792 200 1.908 22.900

Density 1,03 t/m³ 1,00 t/m³ 0,64 t/m³ 0,15 t/m³ 1,00 t/m³ #BEZUG!

Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 % 0,0 %

Input FM 1.500 17.500 1.792 200 1.908 22.900

Gas Yield/ oDM 330 L/kg oDM 500 L/kg oDM 540 L/kg oDM 320 L/kg oDM L/kg oDM L/kg oDM

Gas Yield/ FM 33 m³/ t FM 25 m³/ t FM 119 m³/ t FM 253 m³/ t FM m³/ t FM #DIV/0!

Methane Content 59 % 60 % 54 % 51 % % % 57,6 %



DM [%FM] 12,5 % 6, % 25, % 86, % ,% 8,1 %

Input [DM] 188 t/a 1.050 t/a 448 t/a 172 t/a t/a 1.858 t/a

Flow Biogas 134 m³/d 1.179 m³/d 583 m³/d 139 m³/d m³/d m³/d 2035 m³/d 742.908 m³/a

Flow Methane 79 m³/d 708 m³/d 315 m³/d 71 m³/d m³/d m³/d 1172 m³/d 427.925 m³/a

while stock inside 181,0 d/a 8,29 t/d 47,95 t/d 3,17 t/d 0,00 t/d 0,83 t/d 5,23 t/d 65,46 t/d 8,3 %

stock outside 184,0 d/a 0,00 t/d 47,95 t/d 6,62 t/d 0,00 t/d 0,27 t/d 5,23 t/d 60,07 t/d 7,9 %

57,8 % 1177 m³/d 62.896 kg/d 4,63%

57,4 % 1168 m³/d 57.507 kg/d 3,94%

oDM [%DM] 79 % 82 % 88 % 92 % % 84,1 %

Input [oDM] 406 kg/d 2.359 kg/d 1.080 kg/d 434 kg/d kg/d 4.278 kg/d

water [t/a] 1.313 16.450 1.344 28 1.908 21.043



beef cattle slurry (liquid) pig slurry grass silage (general) straw (in slurry) washing (pigs) dilution water

Grass Straw Dilution Total


Input [oDM] Percentage oDM [%] 406 kg oDM/d 9,49% 2.359 kg oDM/d 55,14% 1.080 kg oDM/d 25,25% 434 kg oDM/d 10,13% kg oDM/d 0,00% kg oDM/d 0,00% 4.278 kg oDM/d 100,00% 8,11% 6,82% 84,07%

Variation throughout the year beef cattle slurry (liquid) pig slurry grass silage (general) maize silage straw (in slurry) washing (pigs) Total DM-content input


56,99 kg Condens./d




beef catlle only


beef cattle slurry (liquid) 0 pig slurry grass silage (general) straw (in slurry)

Grass Straw Total From manure (including litter) From other substrates

Substrate [DM] 188 t/a 1050 t/a 448 t/a 172 t/a 1858 t/a

N 56,8 kg/ t DM 89,7 kg/ t DM 25,6 kg/ t DM 6,4 kg/ t DM 63,21 kg/ t DM

P2O5 18,4 kg/ t DM 42,1 kg/ t DM 8,7 kg/ t DM 3,5 kg/ t DM 28,08 kg/ t DM

K2 O 69,2 kg/ t DM 39,9 kg/ t DM 34,9 kg/ t DM 1,81 kg/ t DM 38,12 kg/ t DM

N

P2O5

10,65 t/a 94,19 t/a 11,47 t/a 1,1 t/a 117,4 t/a 105,94 t/a 11,47 t/a

3,45 t/a 44,21 t/a 3,9 t/a 0,6 t/a 52,15 t/a 48,26 t/a 3,9 t/a

Main Digester / Second Digester / Digestate Storage no after-digester Main Digester:

1 item

Diameter: Height/ Length: Height of Gasholder: Digester volume: Organic loading rate input: Theoretical retention time: oDM of Input oDM of Outflow

After-Digester:




Flow rate substrate into digester: Flow rate recyclate Total flow rate into digester Surplus volume due to bubbles, foam etc Theoretic. volume in digester Flow rate effluent digester NH4-N Organic loading while stock inside: Th. retention time while stock inside: Organic loading while stock outside: Th. retention time while stock outside:

item


62,7 m³/d 0,0 m³/d 62,7 m³/d 5,0 % 65,9 m³/d 57,3 m³/d



57,3 m³/d


5,0 % 60,2 m³/d 57,3 m³/d


K2 O 12,98 t/a 41,9 t/a 15,64 t/a 0,31 t/a 70,82 t/a 55,18 t/a 15,64 t/a

182 days storage capacity mimimum for already available and usable 855,0 m³ "Existing" Storage = Eco/Manure Bags + Existent: Mass flow from digested substrate: 21965,42 t/a Mass flow of recyclate , t/a Total mass flow 21965,42 t/a Total flow rate of material for storage: 20919,4 m³/a minus Existing: Necessary storage capacity total 10896,8 m³ Necessary Surplus to after-digester 10896,8 m³ 10041,8 m³ No. of Eco/Manure Bags 2 item Lengh 44,0 m Width 44,0 m Height: 2,6 m 10.067 m³ 10.922 m³ Total storage volume Storage time (annual mean): 6,3 months Relevant digestate for storage (amount varies while stock in/out) Maximum digestate 182 days 10.897 m³ Minimum storage volume 10.897 m³ Digestate production: Mass flow digestate 21965,42 t/a Flow rate digestate 20919,4 m³/a




250 kW




80,9 %

140



1

Month



outside


38 °C

8,3 %

134.257 kWh/a

49,3 %

962.606 kWh/a

∆T K 32 32 31 29 27 24 22 22 24 26 29 31

Heat Loss kWh/day 523,9 527,2 504,3 476,6 435,8 390,1 364,0 360,7 383,6 424,4 479,9 502,7



Process energy kWh/day 3.161,4 3.165,3 3.050,5 2.842,6 2.531,6 2.302,1 2.096,1 2.004,9 2.206,9 2.430,6 2.846,5 3.048,6 incl. 20% heat losses from CHP to digester 962.606

Total:


1.951.338 kWh/a 962.606 kWh/a 988.733 kWh/a 168.085 kWh/a

17 %


820.648 kWh/a

42,06%




need (customer) 2.323 kWh/d 2.336 kWh/d 2.012 kWh/d 1.764 kWh/d 1.516 kWh/d 1.489 kWh/d 1.424 kWh/d 1.373 kWh/d 1.399 kWh/d 1.763 kWh/d 2.020 kWh/d 2.312 kWh/d 660.000 kWh/a




Calculation of actually available heat (kWh): produced Surplus heat Heat theoretical real (after loss) 165.730 67.727 56.214 149.692 61.063 50.683 165.730 71.163 59.065 160.384 75.107 62.338 165.730 87.250 72.418 160.384 91.321 75.796 165.730 100.751 83.623 165.730 103.580 85.971 160.384 94.176 78.166 165.730 90.382 75.017 160.384 74.989 62.241 165.730 71.224 59.116 1.951.338 988.733 820.648 total (kWh/a)



1.617.557 kWh/a 134.257 kWh/a x 25.881 kWh/a


134.257 0x


0

1.457.419 kWh/a

Investment costs K,T,B

Unit

B B

lump total total

Mixing pit with agitator, 90 m³ Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.)

1/2 T, 1/2 B T

total total

21.537 15.018


1/3 T, 2/3B

total

201.799

B T T

£/ m3 total total

K

total

B

total

14.150 14.150

T T T

total total total

38.408 28.094 4.941 71.444

B

£/ m

1.200 m

96

115.200 115.200

lump

5,0 %

744.670

37.233 37.233

Planning, Approval, Grid Connection Plant design, information, approval procedure, etc. (lump sum in % of invest for construct + technology + CHP) Grid Connection incl. cables and cable trenching 150 m to next transformer station Earth works, walk way preparation

Amount


Costs [£]

744.670 £

Feeding technology

29.787 14.500 50.400 94.687

36.555

Digester 201.799

After-Digester/ Storage of digestate Eco/ Manure bags Mixing equipment Piping system digestate

10.067 m³ 2 2

14,6 £/m³ 5.500 3.200

164.381


250 kW

141.140 141.140






876.590


Total without VAT

146.981 11.000 6.400

0 0%

0

876.590

141



reference

Write-off:


531.213 £

20 years

26.561 £/a

Technology

204.237 £

12 years

17.020 £/a

Gas engine

141.140 £

7, years

20.163 £/a

Rate of interest:

438.295 £

7,0 %

30.681 £/a

Insurance:

876.590 £

1,5 %

13.149 £/a

531.213 £/a

2,0 %

10.624 £/a

Maintenance/ Repair


annual costs

204.237 £/a

3,0 %

6.127 £/a

1.617.557 kWh/a

0,96 p/kWhel.

15.529 £/a


Manure

beef cattle slurry (liq pig slurry grass silage (gener

Others

straw (in slurry) washing (pigs) dilution water Total Costs Substrates

1.500 t/a

0,0 £/t

17.500 t/a

0,0 £/t

£/a £/a

1.792 t/a

22,5 £/t

40.320 £/a

200 t/a

0,0 £/t

£/a

1.908 t/a

0,0 £/t

£/a

t/a

0,0 £/t

£/a

40.320 £/a


0,0 £/t

£/a

857 t/a

t/a

km

2,8 £/t

2.401 £/a

1.250 h/a

15,0 £/h

18.750 £/a

735.450 £/a

1,0 %

7.355 £/a


208.678 £/a




5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh


1.457.419 kWh/a

0,145 £/kWh

211.326 £/a

613.620 kWh/a

0,047 £/kWh

28.717 £/a

15 % Losses

90.045 kg N/a

0,12 €/kg N

8.644 £/a

15 % Losses

9.748 kg N/a

0,56 €/kg N

4.367 £/a

3.898 kg P2O5/a

0,55 €/kg P2O5

1.715 £/a

15.635 kg K2O/a

0,28 €/kg K2O

Gate fees for waste

£/a




Total revenue:

Business Profit/ Losses: Return on investment:

3.502 £/a 258.272 £/a

49.594 £/a 12,7%


6,1 years

Payback period:

7,7 years

142

Economic Modelling of AD in Cornwall – Annex: Scenario 6 – Option 2: with 7,135 t/a extra energy crops

Scenario 6 – Option 2: with 7,135 t/a extra Energy Crops Input Substrates: Scenario 6 - Option 2: with 7.135 t/a additional energy crops Manure Manure Grass Maize Straw (Water) Total

Type beef cattle slurry (liquid) pig slurry grass silage (general) maize silage straw (in slurry) washing (pigs)

Fresh Matter 17.500 7.168 1.759 100 1.908 28.435

t/a t/a t/a t/a t/a t/a t/a

Density 1,03 t/m³ 1,00 t/m³ 0,64 t/m³ 0,72 t/m³ 0,15 t/m³ 1,00 t/m³ #BEZUG!

Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 %

Gas Yield/ oDM 330 L/kg oDM 500 L/kg oDM 540 L/kg oDM 670 L/kg oDM 320 L/kg oDM L/kg oDM

Gas Yield/ FM #DIV/0! 25 m³/ t FM 119 m³/ t FM 189 m³/ t FM 253 m³/ t FM m³/ t FM

Input FM 17.500 7.168 1.759 100 1.908 28.435


DM [%FM] 12,5 % 6, % 25, % 30, % 86, % ,% 12,2 %

Input [DM] t/a 1.050 t/a 1.792 t/a 528 t/a 86 t/a t/a 3.456 t/a

oDM [%DM] 79 % 82 % 88 % 94 % 92 % % 87,2 %

Input [oDM] kg/d 2.359 kg/d 4.320 kg/d 1.359 kg/d 217 kg/d kg/d 8.255 kg/d

water [t/a] 16.450 5.376 1.231 14 1.908 24.979


Daily Gas Yield and Reduction of Biomass: Manure Grass Maize Straw

beef cattle slurry (liquid) pig slurry grass silage (general) maize silage straw (in slurry) washing (pigs)

Total DM content of input mixture: oDM content of input mixture: Proportion of digestable dry substance: Assumed gas yield from input: Assumed methande content: Density of Biogas Loss of Water (evaporation) Mass of produced Biogas Total reduction/ loss (water+biogas) Reduction of oDM Daily amount of digestate: DM in digestate: oDM in digestate: DM-content digestate: oDM-content digestate

Input [oDM] Percentage oDM [%] kg oDM/d 0,00% 2.359 kg oDM/d 28,58% 4.320 kg oDM/d 52,34% 1.359 kg oDM/d 16,46% 217 kg oDM/d 2,63% kg oDM/d 0,00% 8.255 kg oDM/d 100,00% 12,15% 10,60% 87,19% 0,54 m³/kg oDM 55,12% 1,23 kg/m³ 0,028 kg/m³ 125,79 kg Condens./d 5525,6 kg/d 5651,4 kg/d 5525,6 kg/d 72.253 kg/d reduction: 7,25% 3.942 kg/d reduction: 58,36% 2729,5 kg/d reduction: 66,94% 5,46% 3,78%

Methane Content 59 % 60 % 54 % 52 % 51 % % 55,1 %

Flow Biogas m³/d 1.179 m³/d 2.333 m³/d 911 m³/d 69 m³/d m³/d 4492 m³/d 1.639.722 m³/a

Flow Methane m³/d 708 m³/d 1.260 m³/d 473 m³/d 35 m³/d m³/d 2476 m³/d 903.874 m³/a


5525,6 kg/d 5.526 kg/d

Nutrients from manure and other substrates: Substrate [DM] Manure beef cattle slurry (liquid) Manure pig slurry Grass grass silage (general) Maize maize silage Straw straw (in slurry) Total From manure (including litter) From other substrates

1050 1792 528 86 3456


N 56,8 kg/ t DM 89,7 kg/ t DM 25,6 kg/ t DM 13,6 kg/ t DM 6,4 kg/ t DM 42,77 kg/ t DM

P2O5 18,4 kg/ t DM 42,1 kg/ t DM 8,7 kg/ t DM 5,5 kg/ t DM 3,5 kg/ t DM 18,23 kg/ t DM

K2O 69,2 kg/ t DM 39,9 kg/ t DM 34,9 kg/ t DM 16,9 kg/ t DM 1,81 kg/ t DM 32,85 kg/ t DM

N

P2O5

0, t/a 94,19 t/a 45,88 t/a 7,18 t/a 0,55 t/a 147,79 t/a 94,74 t/a 53,05 t/a

0, t/a 44,21 t/a 15,59 t/a 2,9 t/a 0,3 t/a 63, t/a 44,51 t/a 18,49 t/a

Main Digester / Second Digester / Storage Tank Main Digester:

2 item

Diameter: Height/ Length: Freeboard Effective digester volume: Organic loading rate input: Theoretical retention time: oDM of Input oDM of Outflow

After-Digester (not heated):


Diameter: Height: Freeboard Effective digester volume: Organic loading rate input: Theoretical retention time:


Flow rate substrate into digester: Flow rate recyclate Total flow rate into digester Surplus volume due to bubbles, foam etc Theoretic. volume in digester Flow rate effluent digester NH4-N


77,9 m³/d 0,0 m³/d 77,9 m³/d 5,0 % 81,8 m³/d 70,6 m³/d

1 item 24,0 m 6,4 m 0,3 m 2.760 m³ 1,4 kg oDM/m³·d 37 days 3.835 kg oDM/d 2.729 kg oDM/d


70,6 m³/d


5,0 % 74,2 m³/d 68,8 m³/d

2,86 g/L

K2O 0, t/a 41,9 t/a 62,54 t/a 8,92 t/a 0,16 t/a 113,51 t/a 42,05 t/a 71,46 t/a

182 days storage capacity mimimum for already available and usable 855,0 m³ "Existing" Storage = After digester + Eco/Manure Bags + Existent: Mass flow from digested substrate: 26372,23 t/a Mass flow of recyclate , t/a Total mass flow 26372,23 t/a Total flow rate of material for storage: 25116,4 m³/a minus Existing: Necessary storage capacity total 12523,8 m³ Necessary Surplus to after-digester 9764,2 m³ 8909,2 m³ 2 item No. of Eco/Manure Bags Lengh 42,0 m Width 42,2 m 2,5 m Height: 8.862 m³ 12.477 m³ Total storage volume Storage time (annual mean): 6,0 months Relevant digestate for storage (winter/summer feeding does not vary) 12.524 m³ Maximum digestate 182 days Minimum storage volume 12.524 m³ Digestate production: 26372,23 t/a Mass flow digestate Flow rate digestate 25116,4 m³/a



499 kW




86,3 %

143


Balancing of process energy demand (electrical and thermal energy): Scenario 6 - Option 2: with 7.135 t/a additional energy crops Electrical energy demand for biogas process:

8,1 %

278.944 kWh/a

Thermal energy demand for biogas process: Calculation of thermal energy demand for biogas process:

32 %

1.243.032 kWh/a

Digester:

1

Month



outside

Heat transmission coefficient: Insulation: heat conductance λ thickness: Insulation index k-value: Surface of heated Digesters: Surface of storage tank (if heated only): Loss of heat total:

38 °C


∆T K 32 32 31 29 27 24 22 22 24 26 29 31

Heat Loss kWh/day 778,3 783,1 749,2 708,0 647,4 579,5 540,7 535,8 569,8 630,4 712,8 746,8



Process energy kWh/day 4.078,8 4.084,6 3.935,4 3.669,1 3.271,0 2.972,7 2.709,2 2.595,0 2.852,6 3.142,2 3.674,9 3.932,5 incl. 20% heat losses from CHP to digester 1.243.032

Total:


3.940.889 kWh/a 1.243.032 kWh/a 2.697.856 kWh/a 512.593 kWh/a

19 %


2.185.264 kWh/a

55,45%




need (customer) 2.323 kWh/d 2.336 kWh/d 2.012 kWh/d 1.764 kWh/d 1.516 kWh/d 1.489 kWh/d 1.424 kWh/d 1.373 kWh/d 1.399 kWh/d 1.763 kWh/d 2.020 kWh/d 2.312 kWh/d 660.000 kWh/a




Calculation of actually available heat (kWh): produced Surplus heat Heat theoretical real (after loss) 334.706 208.264 168.693 302.315 187.946 152.236 334.706 212.708 172.293 323.909 213.836 173.207 334.706 233.304 188.976 323.909 234.729 190.130 334.706 250.720 203.083 334.706 254.262 205.952 323.909 238.331 193.048 334.706 237.297 192.211 323.909 213.662 173.066 334.706 212.798 172.366 3.940.889 2.697.856 2.185.264

total (kWh/a)



3.443.758 kWh/a 278.944 kWh/a x 55.100 kWh/a


278.944 0x


0

3.109.714 kWh/a

Investment costs: Scenario 6 - Option 2: with 7.135 t/a additional energy crops K,T,B

Unit

B B

lump total total

Mixing pit with agitator, 90 m³ Solid feeder 10 m³, incl. screw conveyor Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.)

1/2 T, 1/2 B T T

total total total


1/3 T, 2/3 B

total

1/3 T, 2/3 B B T T

total £/ m3 total total

2.760 m³ 8.862 m³ 2 2

K

total

499 kW

B

total

16.273 16.273

T T T

total total total

44.170 32.870 5.682 82.722

B

£/ m

1.200 m

96

115.200 115.200

B

lump £/ m3

5,0 % 6901 m³

1.061.141 49,0 £/m³

53.057 338.163 391.220

Planning, Approval, Grid Connection Plant design, information, approval procedure, etc. (lump sum in % of invest for construct + technology + CHP) Grid Connection incl. cables and cable trenching 150 m to next transformer station Earth works, walk way preparation

Amount


Costs [£]

1.061.141 £

Feeding technology

31.834 22.725 64.800 119.359 21.537 34.861 18.022 74.420

Digester 2

147387,1 £/unit

294.774

15,0 £/m³ 5.500 3.200

114.414 132.930 11.000 6.400

294.774

After-Digester/ Storage of digestate After-digester (not heated), covered, incl. gas storage, mixer = storage tank Eco/ Manure bags (Flexistore) Mixing equipment Piping system digestate

264.744


213.008 213.008




Other investment costs Unforeseen costs (lump sum in % of investment construct + technology + CHP) Substrate Storage for additional AD feedstock


1.571.720


Total without VAT

0 0%

0

1.571.720

144


Cost of Capital/ Ongoing Costs: Scenario 6 - Option 2 with 7.135 t/a additional energy crops Write-off:


annual costs 20 years

51.512 £/a

Technology

328.467 £

12 years

27.372 £/a

Gas engine

213.008 £

7, years

30.430 £/a

785.860 £

7,0 %

55.010 £/a

1.571.720 £

1,5 %

23.576 £/a

1.030.246 £/a

2,0 %

20.605 £/a

328.467 £/a

3,0 %

9.854 £/a

3.443.758 kWh/a

0,96 p/kWhel.

33.060 £/a


reference 1.030.246 £



Manure

beef cattle slurry (liq pig slurry

Others

t/a

0,0 £/t

£/a

17.500 t/a

0,0 £/t

£/a

grass silage (gener

7.168 t/a

22,5 £/t

161.280 £/a

maize silage

1.759 t/a

25,0 £/t

43.975 £/a

100 t/a

0,0 £/t

£/a

1.908 t/a

0,0 £/t

£/a

straw (in slurry) washing (pigs) Total Costs Substrates

205.255 £/a


0,0 £/t

£/a

5.364 t/a

t/a

km

2,8 £/t

15.020 £/a

1.996 h/a

15,0 £/h

29.940 £/a

1.358.712 £/a

1,0 %

13.587 £/a


515.221 £/a

Benefits of biogas production: Scenario 6 - Option 2: with 7.135 t/a additional energy crops 2009



5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh


3.109.714 kWh/a

0,145 £/kWh

450.908 £/a

660.000 kWh/a

0,047 £/kWh

30.888 £/a

Gate fees for waste

£/a


15 % Losses

80.525 kg N/a

0,12 €/kg N

7.730 £/a

15 % Losses

45.094 kg N/a

0,56 €/kg N

20.202 £/a

18.493 kg P2O5/a

0,55 €/kg P2O5

8.137 £/a

71.459 kg K2O/a

0,28 €/kg K2O

16.007 £/a





Digestate fertiliser value Total revenue:


533.873 £/a

18.651 £/a 8,2% 8,6 years 12,3 years

145


11.3.7

Annex to Site 7

Option 1: without food waste Input Substrates: Scenario 7 Type cattle (liquid manure) horse manure Grass grass silage (general) Maize maize silage Straw straw (in slurry) Cereals whole crop cereal silage Dilution dilution water Total incl. dilution water

Fresh Matter 4.066 360 300 200 30 100 314 5.370

Manure


t/a t/a t/a t/a t/a t/a t/a t/a

Density 1,00 t/m³ 0,17 t/m³ 0,64 t/m³ 0,72 t/m³ 0,15 t/m³ 0,59 t/m³ 1,00 t/m³ #BEZUG!

Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 %

1,05 t/m³

Gas Yield/ oDM 350 L/kg oDM 350 L/kg oDM 540 L/kg oDM 670 L/kg oDM 320 L/kg oDM 570 L/kg oDM L/kg oDM

1.043 t/a 6.414 t/a

Input FM 4.066 360 300 200 30 100 314 5.370


DM [%FM] 8% 28 % 30 % 33 % 86 % 38 % % 12,0 %

Input [DM] 325 t/a 101 t/a 90 t/a 66 t/a 26 t/a 38 t/a t/a 646 t/a

0,0 %

1.043 t/a 6.414 t/a

3,58 % 10,7 %

37 t/a 683 t/a

Gas Yield/ FM 22 m³/ t FM 74 m³/ t FM 143 m³/ t FM 208 m³/ t FM 253 m³/ t FM 201 m³/ t FM m³/ t FM

Methane Content 59 % 55 % 54 % 52 % 51 % 53 % % 55,5 %

Flow Biogas 250 m³/d 72 m³/d 117 m³/d 114 m³/d 21 m³/d 55 m³/d m³/d 629 m³/d 229.613 m³/a

Flow Methane 147 m³/d 40 m³/d 63 m³/d 59 m³/d 11 m³/d 29 m³/d m³/d 349 m³/d 127.549 m³/a

while stock inside 135,5 d/a 22,38 t/d 0,99 t/d 0,04 t/d 0,03 t/d 0,17 t/d 0,01 t/d 0,00 t/d 0,00 t/d 23,61 t/d 9,5 % 57,9 % 364 m³/d 22.821 kg/d 6,40%

stock outside 229,5 d/a 4,50 t/d 0,99 t/d 1,28 t/d 0,86 t/d 0,03 t/d 0,43 t/d 1,37 t/d 4,55 t/d 14,01 t/d 12,0 % 54,2 % 341 m³/d 8.668 kg/d 8,33%

oDM [%DM] Input [oDM] 80 % 713 kg/d 75 % 207 kg/d 88 % 217 kg/d 94 % 170 kg/d 92 % 65 kg/d 93 % 97 kg/d % kg/d 83,0 % 1.469 kg/d %

water [t/a] 3.741 259 210 134 4 62 314 4.725

kg/d


1.006 t/a 5.730 t/a


cattle (liquid manure) horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage dilution water

Grass Maize Straw Cereals Dilution Total


Input [oDM] Percentage oDM [%] 713 kg oDM/d 48,54% 207 kg oDM/d 14,10% 217 kg oDM/d 14,77% 170 kg oDM/d 11,57% 65 kg oDM/d 4,43% 97 kg oDM/d 6,59% kg oDM/d 0,00% 1.469 kg oDM/d 100,00% 12,03% 9,98% 83,01%

Variation throughout the year cattle (liquid manure) horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage dilution water Recyclate Total incl recyclate DM-content input incl. dilution and recyclate Flow Biogas equalised, Methane content: Flow Methane Daily amount digestate DM-content digestate

0,43 m³/kg oDM 55,55% 1,23 kg/m³ 0,028 kg/m³ 773,8 kg/d 791,4 kg/d 773,8 kg/d 13.922 kg/d 996 kg/d 695,1 kg/d 7,15% 4,99%

17,61 kg Condens./d




cattle (liquid manure) 0 horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage

Grass Maize Straw Cereals Total From manure From other substrates

Substrate DM 325 101 90 66 26 38 646


N 56,8 kg/ t DM 18,7 kg/ t DM 25,6 kg/ t DM 13,6 kg/ t DM 6,4 kg/ t DM 14,2 kg/ t DM 37,57 kg/ t DM

P2O5 18,4 kg/ t DM 10,7 kg/ t DM 8,7 kg/ t DM 5,5 kg/ t DM 3,5 kg/ t DM 6,2 kg/ t DM 13,22 kg/ t DM

K 2O 69,2 kg/ t DM 21,4 kg/ t DM 34,9 kg/ t DM 16,9 kg/ t DM 1,81 kg/ t DM 10,8 kg/ t DM 45,49 kg/ t DM

N

P2O5 18,48 t/a 1,88 t/a 2,3 t/a 0,9 t/a 0,17 t/a 0,54 t/a 24,27 t/a 20,53 t/a 3,74 t/a

5,99 t/a 1,08 t/a 0,78 t/a 0,36 t/a 0,09 t/a 0,24 t/a 8,54 t/a 7,15 t/a 1,38 t/a


1 item







After-Digester:


14,7 m³/d 2,9 m³/d 17,6 m³/d 5,0 % 18,5 m³/d 16,1 m³/d



16,1 m³/d


5,0 % 16,9 m³/d 13,3 m³/d



K2O 22,51 t/a 2,16 t/a 3,14 t/a 1,12 t/a 0,05 t/a 0,41 t/a 29,38 t/a 24,71 t/a 4,67 t/a



Mass flow from digested substrate: 5081,53 t/a Mass flow of recyclate 1043,22 t/a Total mass flow 6124,75 t/a Total flow rate of material for storage: 4839,6 m³/a minus Existing: Necessary storage capacity total 3328,8 m³ Necessary Surplus to after-digester 3328,8 m³ 3328,8 m³ No. of Eco/Manure Bags 1 item Lengh 37,0 m 37,0 m Width 2,5 m Height: 3.423 m³ Storage volume total: 3.423 m³ Storage time (annual mean): 8,5 months Relevant digestate for storage (amount varies while stock in/out) Maximum digestate 182 days 3.329 m³ Minimum storage volume 3.329 m³ Digestate production: Mass flow digestate 5081,53 t/a Flow rate digestate 4839,6 m³/a




75 kW




69,3 %

146



1

Month



outside


38 °C

8,6 %

35.760 kWh/a

45,6 %

282.013 kWh/a

∆T K 32 32 31 29 27 24 22 22 24 26 29 31

Heat Loss kWh/day 273,3 275,1 263,1 248,7 227,4 203,5 189,9 188,2 200,1 221,4 250,4 262,3



Process energy kWh/day 922,0 924,0 889,2 830,9 743,9 674,3 617,0 594,5 649,8 716,3 832,9 888,2 incl. 20% heat losses from CHP to digester 282.013

Total:



15 %


286.108 kWh/a

46,25%



actually available 657 kWh/d 655 kWh/d 685 kWh/d 734 kWh/d 808 kWh/d 867 kWh/d 916 kWh/d 935 kWh/d 888 kWh/d 832 kWh/d 733 kWh/d 686 kWh/d 286.108 kWh/a






real (after loss) 20.365 18.345 21.228 22.030 25.057 26.023 28.400 28.994 26.649 25.785 21.978 21.254 286.108

total (kWh/a)



415.809 kWh/a 35.760 kWh/a x 6.653 kWh/a


35.760 0x

0

373.396 kWh/a


Unit

B B

lump total total

Mixing pit with mixer, 90 m³ Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.) incl. recyclate

1/2 T, 1/2 B T

total total

21.537 19.974


1/3 T, 2/3 B

total

130.661

B T T

£/ m3 total total

K

total

B

total

14.059 14.059

T T T

total total total

22.701 27.967 4.941 55.609

B

£/ m

30

96

2.880 2.880

B

lump £/ m3

5,0 % m³

388.285 49,0 £/m³

19.414 0 19.414


Amount

Costs per Unit

5,0 %

Costs [£]

388.285 £

Feeding technology

19.414 13.375 24.000 56.789

41.511

Digester 130.661


3.423 m³ 1 1

16,5 £/m³ 5.500 3.200

65.171


75 kW

78.394 78.394




Other investment costs Unforeseen costs (lump sum in % of investment construct + technology + CHP) Substrate Storage for additional AD feedstock: Silage; assumption: already available


464.489


Total without VAT

56.471 5.500 3.200

0 0%

0

464.489

147



reference

Write-off:


234.546 £

20 years

Technology

151.548 £

12 years

12.629 £/a

78.394 £

7, years

11.199 £/a

Rate of interest:

232.244 £

7,0 %

16.257 £/a

Insurance:

464.489 £

1,5 %

6.967 £/a

234.546 £/a

2,0 %

4.691 £/a

151.548 £/a

3,0 %

4.546 £/a

415.809 kWh/a

0,96 p/kWhel.

3.992 £/a


Maintenance/ Repair


annual costs 11.727 £/a


Manure

cattle (liquid manure horse manure

Others

4.066 t/a

0,0 £/t

£/a

360 t/a

2,14 £/t

772 £/a

grass silage (gener

300 t/a

22,5 £/t

6.750 £/a

maize silage

200 t/a

25,0 £/t

5.000 £/a

straw (in slurry)

30 t/a

0,0 £/t

£/a

whole crop cereal s

100 t/a

105,0 £/t

10.500 £/a

dilution water

314 t/a

0,2 £/t

63 £/a


23.085 £/a


0,0 £/t

£/a

626 t/a

t/a

km

2,8 £/t

1.751 £/a

375 h/a

15,0 £/h

5.625 £/a

386.094 £/a

1,0 %

3.861 £/a


106.331 £/a




5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh


373.396 kWh/a

0,145 £/kWh

54.142 £/a

5.000 kWh/a

0,047 £/kWh

234 £/a

Gate fees for waste

£/a



15 % Losses

17.447 kg N/a

0,12 €/kg N

1.675 £/a

15 % Losses

3.180 kg N/a

0,56 €/kg N

1.425 £/a

1.382 kg P2O5/a

0,55 €/kg P2O5

608 £/a

4.667 kg K2O/a

0,28 €/kg K2O

1.045 £/a

P (P from substrates without manure): Digestate fertiliser value K (K from substrates without manure):


Total revenues:

Business Profit/ Losses: Return on investment:

59.129 £/a

-47.202 £/a -3,2%


100,7 years

Payback period:

-39,9 years

148

Economic Modelling of AD in Cornwall – Annex: Scenario 7 – Option 2: with 1000 t/a food waste

Scenario 7 – Option 2: With 1000 t/a food waste. Input Substrates: Scenario 7 + 1000 t/a food waste Type cattle (liquid manure) horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage food waste Dilution dilution water Total incl. dilution water

Fresh Matter 4.066 360 300 200 30 100 1.000 314 6.370


Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 %

1,05 t/m³

Input [oDM] Percentage oDM [%] Gas Yield/ oDM 713 kg oDM/d 33,61% 350 L/kg oDM 207 kg oDM/d 9,77% 350 L/kg oDM 217 kg oDM/d 10,23% 540 L/kg oDM 170 kg oDM/d 8,01% 670 L/kg oDM 65 kg oDM/d 3,07% 320 L/kg oDM 97 kg oDM/d 4,57% 570 L/kg oDM 652 kg oDM/d 30,74% 460 L/kg oDM kg oDM/d 0,00% L/kg oDM 2.121 kg oDM/d 100,00%

Manure

Grass Maize Straw Cereals



987 t/a 7.358 t/a

Input FM 4.066 360 300 200 30 100 1.000 314 6.370


DM [%FM] 8% 28 % 30 % 33 % 86 % 38 % 28 % % 14,5 %

Input [DM] 325 t/a 101 t/a 90 t/a 66 t/a 26 t/a 38 t/a 280 t/a t/a 926 t/a

0,0 %

987 t/a 7.358 t/a

4,28 % 13,2 %

42 t/a 968 t/a

Gas Yield/ FM 22 m³/ t FM 74 m³/ t FM 143 m³/ t FM 208 m³/ t FM 253 m³/ t FM 201 m³/ t FM 109 m³/ t FM m³/ t FM

Methane Content 59 % 55 % 54 % 52 % 51 % 53 % 60 % % 57,0 %

Flow Biogas 250 m³/d 72 m³/d 117 m³/d 114 m³/d 21 m³/d 55 m³/d 300 m³/d m³/d 929 m³/d 339.093 m³/a

Flow Methane 147 m³/d 40 m³/d 63 m³/d 59 m³/d 11 m³/d 29 m³/d 180 m³/d m³/d 529 m³/d 193.237 m³/a



oDM [%DM] Input [oDM] 80 % 713 kg/d 75 % 207 kg/d 88 % 217 kg/d 94 % 170 kg/d 92 % 65 kg/d 93 % 97 kg/d 85 % 652 kg/d % kg/d 83,6 % 2.121 kg/d %

water [t/a] 3.741 259 210 134 4 62 720 314 5.445

kg/d


945 t/a 6.390 t/a

Daily Gas Yield and Reduction of Biomass (annual mean): Manure Grass Maize Straw Cereals Dilution Total

cattle (liquid manure) horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage 0 food waste dilution water


14,53% 12,15% 83,61%

Variation throughout the year cattle (liquid manure) horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage food waste dilution water Recyclate Total incl recyclate DM-content input incl. dilution and recyclate Flow Biogas equalised, Methane content: Flow Methane Daily amount digestate DM-content digestate


26,01 kg Condens./d



Nutrients from manure and other substrates: Manure Grass Maize Straw Cereals

cattle (liquid manure) 0 horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage 0 food waste

Total From manure From other substrates

Substrate DM 325 101 90 66 26 38 280 926


N 56,8 kg/ t DM 18,7 kg/ t DM 25,6 kg/ t DM 13,6 kg/ t DM 6,4 kg/ t DM 14,2 kg/ t DM 28, kg/ t DM 34,68 kg/ t DM

P2O5 18,4 kg/ t DM 10,7 kg/ t DM 8,7 kg/ t DM 5,5 kg/ t DM 3,5 kg/ t DM 6,2 kg/ t DM 9, kg/ t DM 11,94 kg/ t DM

K 2O 69,2 kg/ t DM 21,4 kg/ t DM 34,9 kg/ t DM 16,9 kg/ t DM 1,81 kg/ t DM 10,8 kg/ t DM 9,5 kg/ t DM 34,6 kg/ t DM

N




1 item







After-Digester:


17,5 m³/d 2,7 m³/d 20,2 m³/d 5,0 % 21,2 m³/d 18,2 m³/d



18,2 m³/d

Surplus volume due to bubbles, foam etc. Theoretic. volume in digester Flow rate effluent digester incl. recyclate

5,0 % 19,1 m³/d 18,2 m³/d

2,77 g/L Organic loading while stock inside: Th. retention time while stock inside: Organic loading while stock outside: Th. retention time while stock inside:





Mass flow from digested substrate: 5943,81 t/a Mass flow of recyclate 987,29 t/a Total mass flow 6931,1 t/a Total flow rate of material for storage: 5660,8 m³/a minus Existing: Necessary storage capacity total 3738,3 m³ Necessary Surplus to after-digester 3738,3 m³ 3738,3 m³ No. of Eco/Manure Bags 1 item Length 39,0 m 39,0 m Width 2,5 m Height: 3.803 m³ 3.803 m³ Storage volume total: Storage time (annual mean): 8,1 months Relevant digestate for storage (amount varies while stock in/out) Maximum digestate 182 days 3.738 m³ Minimum storage volume 3.738 m³ Digestate production: 5943,81 t/a Mass flow digestate Flow rate digestate 5660,8 m³/a




104 kW




88,0 %

149


Balancing of process energy demand (electrical and thermal energy): Scenario 7 with 1000 t/a food waste Electrical energy demand for biogas process: Thermal energy demand for biogas process: Calculation of thermal energy demand for biogas process: Digester:

1

Month



outside


38 °C

8,6 %

62.984 kWh/a

40,3 %

358.791 kWh/a

Heat Loss kWh/day 389,1 391,6 374,6 354,0 323,7 289,7 270,3 267,9 284,9 315,2 356,4 373,4

∆T K 32 32 31 29 27 24 22 22 24 26 29 31

56.052 kWh/a

Thermal energy demand hygenisation



Process energy Hygenisation kWh/day kWh/d 1.172 167,1 1.174 167,1 1.130 164,4 1.056 158,9 947 150,7 858 145,2 786 139,7 759 137,0 828 142,5 913 147,9 1.059 158,9 1.128 164,4 incl. 20% heat losses from CHP to digester 358.791 56.052 kWh/a

Total:

Heat utilisation: Scenario 7 + 1000 t/a food waste Heat produced by CHP: Process energy demand for biogas plant and hygienisation: Theoretically available surplus heat: Losses during transformation and transport:


18 %


390.302 kWh/a

43,81%



actually available 904 kWh/d 901 kWh/d 940 kWh/d 1.005 kWh/d 1.101 kWh/d 1.179 kWh/d 1.242 kWh/d 1.267 kWh/d 1.206 kWh/d 1.132 kWh/d 1.002 kWh/d 941 kWh/d 390.302 kWh/a

need (customer) actually used % distribution need 2.182 kWh/d 10,91 904 kWh/d 2.194 kWh/d 9,91 901 kWh/d 1.890 kWh/d 9,45 940 kWh/d 1.657 kWh/d 8,02 1.005 kWh/d 1.424 kWh/d 7,12 1.101 kWh/d 1.399 kWh/d 6,77 1.179 kWh/d 1.338 kWh/d 6,69 1.242 kWh/d 1.290 kWh/d 6,45 1.267 kWh/d 1.314 kWh/d 6,36 1.206 kWh/d 1.656 kWh/d 8,28 1.132 kWh/d 1.897 kWh/d 9,18 1.002 kWh/d 2.172 kWh/d 10,86 941 kWh/d 620.000 kWh/a 390.302 kWh/a assumption: all heat is supplied to a consumer at a distance of 1000 m



real (after loss) 28.012 25.234 29.143 30.141 34.132 35.363 38.508 39.269 36.171 35.078 30.070 29.180 390.302

total (kWh/a)



732.367 kWh/a 62.984 kWh/a x 11.718 kWh/a


62.984 0x

0

657.665 kWh/a

Investment costs: Scenario 7 + 1000 t/a food waste K,T,B

Unit

B B

lump total total

Mixing pit with mixer, 90 m³ Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.) incl. recyclate Solid feeder 10.5 m³

1/2 T, 1/2 B T T

total total total

21.537 19.974 34.861 76.372


1/3 T, 2/3 B

total

147.387

B T T

£/ m3 total total

3.803 m³ 1 1

K

total

104 kW

T B

total total

349.841 250.160 600.001

B

total

14.059 14.059

T T T

total total total

37.101 27.967 4.941 70.009

B

£/ m

1000

96

96.000 96.000

B

lump £/ m3

5,0 % m³

1.153.946 49,0 £/m³

57.697 0 57.697


Amount

Costs per Unit

5,0 %

Costs [£]

1.153.946 £

Feeding technology

57.697 15.100 24.000 96.797

Digester 147.387


15,2 £/m³ 5.500 3.200

66.498


83.620 83.620

Hygenisation Hygenisation tank with heating, recooling, screw pump, grinder Hall with equippment


Technology Plant Control, visualisation, electrical equipment Gas equipment (incl. desulphurication, gas quality analysis, condensate pit, gas pipes etc.) Heating equipment (heating circuits, heating pumps, valves, heat supply lines to tank)




1.308.441


Total without VAT

57.798 5.500 3.200

0 0%

0

1.308.441

150


Cost of Capital/ Ongoing Costs: Scenario 7 + 1000 t/a food waste

reference

Write-off:


643.073 £

20 years

Technology

581.747 £

12 years

48.479 £/a

83.620 £

7, years

11.946 £/a

CHP unit: Gas engine Rate of interest:

32.154 £/a

654.220 £

7,0 %

45.795 £/a

1.308.441 £

1,5 %

19.627 £/a


643.073 £/a

2,0 %

12.861 £/a

Technology

581.747 £/a

3,0 %

17.452 £/a

732.367 kWh/a

0,96 p/kWhel.

7.031 £/a

Insurance: Maintenance/ Repair

annual costs

CHP


Manure


Others

4.066 t/a

0,0 £/t

£/a

360 t/a

2,14 £/t

772 £/a

grass silage (gener

300 t/a

22,5 £/t

6.750 £/a

maize silage

200 t/a

25,0 £/t

5.000 £/a

straw (in slurry)

30 t/a

0,0 £/t

£/a

whole crop cereal s

100 t/a

105,0 £/t

10.500 £/a

dilution water

314 t/a

0,2 £/t

63 £/a


23.085 £/a


0,0 £/t

£/a

1.205 t/a

t/a

km

2,8 £/t

3.373 £/a

520 h/a

15,0 £/h

7.800 £/a

1.224.820 £/a

1,5 %

18.372 £/a


247.975 £/a

Benefits of biogas production: Scenario 7 + 1000 t/a food waste 2009



5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh


657.665 kWh/a

0,145 £/kWh

1.000 t/a

45,0 £/t

45.000 £/a

390.302 kWh/a

0,047 £/kWh

18.266 £/a

15 % Losses

17.447 kg N/a

0,12 €/kg N

1.675 £/a

15 % Losses

9.844 kg N/a

0,56 €/kg N

4.410 £/a

3.902 kg P2O5/a

0,55 €/kg P2O5

1.717 £/a

7.327 kg K2O/a

0,28 €/kg K2O

Gate fees for waste Revenue from selling/ using the heat Improved fertiliser value manure (N): Digestate fertiliser value



95.361 £/a

1.641 £/a

Total revenues:

168.071 £/a

Business profit/ losses:

-79.905 £/a

Return on investment: Reflux/ reflow of capital: Payback period:

0,9% 22,4 years 103,2 years

151


Scenario 7 – Option 3: With 4000 t/a food waste. Input Substrates: Scenario 7 + 4000 t/a food waste Type cattle (liquid manure) horse manure Grass grass silage (general) Maize maize silage Straw straw (in slurry) Cereals whole crop cereal silage food waste Dilution dilution water Total incl. dilution water

Fresh Matter 4.066 360 300 200 30 100 4.000 1.129 10.185

Manure



Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 %

1,05 t/m³

Gas Yield/ oDM 350 L/kg oDM 350 L/kg oDM 540 L/kg oDM 670 L/kg oDM 320 L/kg oDM 570 L/kg oDM 460 L/kg oDM L/kg oDM


826 t/a 11.010 t/a

Input FM 4.066 360 300 200 30 100 4.000 1.129 10.185


DM [%FM] 8% 28 % 30 % 33 % 86 % 38 % 28 % % 17,3 %

Input [DM] 325 t/a 101 t/a 90 t/a 66 t/a 26 t/a 38 t/a 1.120 t/a t/a 1.766 t/a

0,0 %

826 t/a 11.010 t/a

5,06 % 16,4 %

42 t/a 1.808 t/a

Gas Yield/ FM 22 m³/ t FM 74 m³/ t FM 143 m³/ t FM 208 m³/ t FM 253 m³/ t FM 201 m³/ t FM 109 m³/ t FM m³/ t FM

Methane Content 59 % 55 % 54 % 52 % 51 % 53 % 60 % % 58,5 %

Flow Biogas 250 m³/d 72 m³/d 117 m³/d 114 m³/d 21 m³/d 55 m³/d 1.200 m³/d m³/d 1829 m³/d 667.533 m³/a

Flow Methane 147 m³/d 40 m³/d 63 m³/d 59 m³/d 11 m³/d 29 m³/d 720 m³/d m³/d 1069 m³/d 390.301 m³/a



oDM [%DM] Input [oDM] 80 % 713 kg/d 75 % 207 kg/d 88 % 217 kg/d 94 % 170 kg/d 92 % 65 kg/d 93 % 97 kg/d 85 % 2.608 kg/d % kg/d 84,3 % 4.077 kg/d %

water [t/a] 3.741 259 210 134 4 62 2.880 1.129 8.419

kg/d


784 t/a 9.203 t/a

Daily Gas Yield and Reduction of Biomass (annual mean): Manure Grass Maize Straw Cereals Dilution Total

cattle (liquid manure) horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage 0 food waste dilution water


Input [oDM] Percentage oDM [%] 713 kg oDM/d 17,49% 207 kg oDM/d 5,08% 217 kg oDM/d 5,32% 170 kg oDM/d 4,17% 65 kg oDM/d 1,60% 97 kg oDM/d 2,37% 2.608 kg oDM/d 63,97% kg oDM/d 0,00% 4.077 kg oDM/d 100,00% 17,34% 14,61% 84,27%

Variation throughout the year cattle (liquid manure) horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage food waste dilution water Recyclate Total incl recyclate DM-content input incl. dilution and recyclate Flow Biogas equalised, Methane content: Flow Methane Daily amount digestate DM-content digestate


51,21 kg Condens./d


energy content 3.903, MWh/a

Nutrients from manure and other substrates: Manure Grass Maize Straw Cereals

cattle (liquid manure) 0 horse manure grass silage (general) maize silage straw (in slurry) whole crop cereal silage 0 food waste

Total From manure From other substrates

Substrate DM 325 101 90 66 26 38 1120 1766

N 56,8 kg/ t DM 18,7 kg/ t DM 25,6 kg/ t DM 13,6 kg/ t DM 6,4 kg/ t DM 14,2 kg/ t DM 28, kg/ t DM 31,5 kg/ t DM


P2O5 18,4 kg/ t DM 10,7 kg/ t DM 8,7 kg/ t DM 5,5 kg/ t DM 3,5 kg/ t DM 6,2 kg/ t DM 9, kg/ t DM 10,54 kg/ t DM

K2O 69,2 kg/ t DM 21,4 kg/ t DM 34,9 kg/ t DM 16,9 kg/ t DM 1,81 kg/ t DM 10,8 kg/ t DM 9,5 kg/ t DM 22,66 kg/ t DM

N




1 item







After-Digester:


27,9 m³/d 2,3 m³/d 30,2 m³/d 5,0 % 31,7 m³/d 26,6 m³/d



26,6 m³/d

Surplus volume due to bubbles, foam etc. Theoretic. volume in digester Flow rate effluent digester incl. recyclate

5,0 % 28,0 m³/d 26,6 m³/d

3, g/L Organic loading while stock inside: Th. retention time while stock inside: Organic loading while stock outside: Th. retention time while stock inside:





Mass flow from digested substrate: 9345,01 t/a Mass flow of recyclate 825,72 t/a Total mass flow 10170,73 t/a Total flow rate of material for storage: 8900,0 m³/a Necessary storage capacity total 5264,8 m³ minus Existing: Necessary Surplus to after-digester 5264,8 m³ 5264,8 m³ No. of Eco/Manure Bags 1 item Length 45,0 m 45,0 m Width Height: 2,5 m 5.063 m³ 5.063 m³ Storage volume total: Storage time (annual mean): 6,8 months Relevant digestate for storage (amount varies while stock in/out) Maximum digestate 182 days 5.265 m³ Minimum storage volume 5.265 m³ Digestate production: 9345,01 t/a Mass flow digestate Flow rate digestate 8900,0 m³/a




250 kW




73,8 %

152


Balancing of process energy demand (electrical and thermal energy): Scenario 7 with 4000 t/a food waste Electrical energy demand for biogas process: Thermal energy demand for biogas process: Calculation of thermal energy demand for biogas process: Digester:

1

Month



outside


38 °C

8,6 %

126.879 kWh/a

29,8 %

536.894 kWh/a

∆T K 32 32 31 29 27 24 22 22 24 26 29 31

Heat Loss kWh/day 523,9 527,2 504,3 476,6 435,8 390,1 364,0 360,7 383,6 424,4 479,9 502,7

224.208 kWh/a

Thermal energy demand hygenisation



Process energy Hygenisation kWh/day kWh/d 1.755 668,5 1.759 668,5 1.693 657,5 1.582 635,6 1.416 602,7 1.284 580,8 1.175 558,9 1.132 547,9 1.237 569,9 1.364 591,8 1.586 635,6 1.691 657,5 incl. 20% heat losses from CHP to digester 536.894 224.208 kWh/a

Total:

Heat utilisation Heat produced by CHP: Process energy demand for biogas plant and hygienisation: Theoretically available surplus heat: Losses during transformation and transport:


18 %


851.311 kWh/a

47,31%




need (customer) actually used % distribution need 2.182 kWh/d 10,91 2.055 kWh/d 2.194 kWh/d 9,91 2.052 kWh/d 1.890 kWh/d 9,45 1.890 kWh/d 1.657 kWh/d 8,02 1.657 kWh/d 1.424 kWh/d 7,12 1.424 kWh/d 1.399 kWh/d 6,77 1.399 kWh/d 1.338 kWh/d 6,69 1.338 kWh/d 1.290 kWh/d 6,45 1.290 kWh/d 1.314 kWh/d 6,36 1.314 kWh/d 1.656 kWh/d 8,28 1.656 kWh/d 1.897 kWh/d 9,18 1.897 kWh/d 2.172 kWh/d 10,86 2.117 kWh/d 620.000 kWh/a 610.346 kWh/a assumption: all heat is supplied to a consumer at a distance of 1000 m



real (after loss) 63.701 57.447 65.565 66.719 73.985 75.398 81.240 82.605 76.816 75.600 66.622 65.614 851.311

total (kWh/a)



1.475.336 kWh/a 126.879 kWh/a x 23.605 kWh/a


126.879 0x

0

1.324.852 kWh/a

Investment costs: Scenario 7 + 4000 t/a food waste K,T,B

Unit

B B

lump total total

Mixing pit with mixer, 90 m³ Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.) incl. recyclate Solid feeder 10.5 m³

1/2 T, 1/2 B T T

total total total

21.537 19.974 34.861 76.372


1/3 T, 2/3 B

total

201.799

B T T

£/ m3 total total

5.063 m³ 1 1

K

total

250 kW

T B

total total

349.841 410.160 760.001

B

total

14.150 14.150

T T T

total total total

38.408 28.094 4.941 71.444

B

£/ m

1000

96

96.000 96.000

B

lump £/ m3

5,0 % m³

1.443.519 49,0 £/m³

72.176 0 72.176


Amount


Costs [£]

1.443.519 £

Feeding technology

72.176 19.750 24.000 115.926

Digester 201.799


14,6 £/m³ 5.500 3.200

82.613


141.140 141.140

Hygenisation Hygenisation tank with heating, recooling, screw pump, grinder Hall with equippment


Technology Plant Control, visualisation, electrical equipment Gas equipment (incl. desulphurication, gas quality analysis, condensate pit, gas pipes etc.) Heating equipment (heating circuits, heating pumps, valves, heat supply lines to tank)




1.631.621


Total without VAT

73.913 5.500 3.200

0 0%

0

1.631.621

153


Cost of Capital/ Ongoing Costs: Scenario 7 + 4000 t/a food waste

reference

Write-off:


879.509 £

20 years

Technology

610.972 £

12 years

50.914 £/a


141.140 £

7, years

20.163 £/a

Rate of interest:

43.975 £/a

815.811 £

7,0 %

57.107 £/a

1.631.621 £

1,5 %

24.474 £/a


879.509 £/a

2,0 %

17.590 £/a

Technology

610.972 £/a

3,0 %

18.329 £/a

1.475.336 kWh/a

0,96 p/kWhel.

14.163 £/a

Insurance: Maintenance/ Repair

annual costs

CHP


Manure


Others

4.066 t/a

0,0 £/t

£/a

360 t/a

2,14 £/t

772 £/a

grass silage (gener

300 t/a

22,5 £/t

6.750 £/a

maize silage

200 t/a

25,0 £/t

5.000 £/a

straw (in slurry) whole crop cereal s dilution water Total Costs Substrates

30 t/a

0,0 £/t

£/a

100 t/a

105,0 £/t

10.500 £/a

1.129 t/a

0,2 £/t

226 £/a

23.248 £/a


0,0 £/t

£/a

4.444 t/a

t/a

km

2,8 £/t

12.443 £/a

1.250 h/a

15,0 £/h

18.750 £/a

1.490.481 £/a

1,5 %

22.357 £/a


323.514 £/a

Benefits of biogas production: Scenario 7 + 4000 t/a food waste 2009



5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh


1.324.852 kWh/a

0,145 £/kWh

192.104 £/a

4.000 t/a

45,0 £/t

180.000 £/a

610.346 kWh/a

0,047 £/kWh

28.564 £/a

15 % Losses

17.447 kg N/a

0,12 €/kg N

1.675 £/a

15 % Losses

29.836 kg N/a

0,56 €/kg N

13.367 £/a

11.462 kg P2O5/a

0,55 €/kg P2O5

5.043 £/a

15.307 kg K2O/a

0,28 €/kg K2O

Gate fees for waste Revenue from selling/ using the heat Improved fertiliser value manure (N): Digestate fertiliser value





3.429 £/a

Total revenues:

424.181 £/a

Business profit/ losses:

100.667 £/a

Return on investment: Reflux/ reflow of capital: Payback period:

13,2% 6, years 7,6 years

154


11.3.8

Annex to Site 8

Input Substrates: Scenario 8 Type cow slurry (liquid) maize silage meat waste fish waste food waste depackaged food waste

Manure Maize Wastes

Fresh Matter 31.200 7.300 2.080 150 300 1.500 42.530

Total


Density 1,00 t/m³ 0,72 t/m³ 1,00 t/m³ 1,00 t/m³ 1,00 t/m³ 1,00 t/m³ #BEZUG!

Losses [%FM] 0,0 % 0,0 % 0,0 % 0,0 % 0,0 % 0,0 %

Input FM 31.200 7.300 2.080 150 300 1.500 42.530

Gas Yield/ oDM 350 L/kg oDM 670 L/kg oDM 450 L/kg oDM 450 L/kg oDM 460 L/kg oDM 650 L/kg oDM

Gas Yield/ FM 28 m³/ t FM 183 m³/ t FM 90 m³/ t FM 108 m³/ t FM 92 m³/ t FM 130 m³/ t FM

Methane Content 59 % 52 % 60 % 60 % 60 % 65 % 56,0 %

Flow Biogas 2.393 m³/d 3.653 m³/d 513 m³/d 44 m³/d 76 m³/d 534 m³/d 7213 m³/d 2.632.887 m³/a

Flow Methane 1.412 m³/d 1.899 m³/d 308 m³/d 27 m³/d 45 m³/d 347 m³/d 4039 m³/d 1.474.083 m³/a

N 177,22 t/a 28,79 t/a 14,56 t/a 1,26 t/a 2,1 t/a 10,5 t/a 234,43 t/a

P2O5 57,41 t/a 11,64 t/a 4,68 t/a 0,41 t/a 0,68 t/a 3,38 t/a 78,19 t/a

K2O 215,9 t/a 35,78 t/a 4,94 t/a 0,43 t/a 0,71 t/a 3,56 t/a 261,32 t/a


DM [%FM] Input [DM] oDM [%DM] Input [oDM] 10, % 3.120 t/a 80 % 6.838 kg/d 29, % 2.117 t/a 94 % 5.452 kg/d 25, % 520 t/a 80 % 1.140 kg/d 30, % 45 t/a 80 % 99 kg/d 25, % 75 t/a 80 % 164 kg/d 25, % 375 t/a 80 % 822 kg/d 14,7 % 6.252 t/a 78,4 % 13.430 kg/d note: DM, oDM-contents of wastes taken as indicated by the Site 8

water [t/a] 28.080 5.183 1.560 105 225 1.125 36.278


Daily Gas Yield and Reduction of Biomass: Manure Maize Wastes


Total DM content of input mixture: oDM content of input mixture: Proportion of digestable dry substance: Assumed gas yield from input: Assumed methande content: Density of Biogas Loss of Water (evaporation) Mass of produced Biogas Total reduction/ loss (water+biogas) Reduction of oDM Daily amount of digestate: DM in digestate: oDM in digestate: DM-content digestate: oDM-content digestate

Input [oDM] Percentage oDM [%] 6.838 kg oDM/d 47,11% 5.452 kg oDM/d 37,56% 1.140 kg oDM/d 7,85% 99 kg oDM/d 0,68% 164 kg oDM/d 1,13% 822 kg oDM/d 5,66% 14.515 kg oDM/d 100,00% 14,70% 11,53% 78,41% 0,50 m³/kg oDM 55,99% 1,23 kg/m³ 0,028 kg/m³ 201,97 kg Condens./d 8872,5 kg/d 9074,4 kg/d 8872,5 kg/d 107.446 kg/d reduction: 7,79% 8.256 kg/d reduction: 51,80% 4557,6 kg/d reduction: 66,06% 7,68% 4,24%

note: wastes would need analyses for gas yields gas yields (wastes) take as indicated by the site


8872,5 kg/d 8.872 kg/d

Nutrients Manure Maize Wastes


Total

Substrate [DM] 3120 t/a 2117 t/a 520 t/a 45 t/a 75 t/a 375 t/a 6252 t/a

N 56,8 kg/ t DM 13,6 kg/ t DM 28, kg/ t DM 28, kg/ t DM 28, kg/ t DM 28, kg/ t DM 37,5 kg/ t DM

P2O5 18,4 kg/ t DM 5,5 kg/ t DM 9, kg/ t DM 9, kg/ t DM 9, kg/ t DM 9, kg/ t DM 12,51 kg/ t DM

K2O 69,2 kg/ t DM 16,9 kg/ t DM 9,5 kg/ t DM 9,5 kg/ t DM 9,5 kg/ t DM 9,5 kg/ t DM 41,8 kg/ t DM

Main Digester / Second Digester / Storage Tank Main Digester:

2 item

After-Digester (heated):

Diameter: Height/ Length: Freeboard Effective digester volume: Organic loading rate input: Theoretical retention time:


Diameter: Height: Freeboard Effective digester volume: Organic loading rate input: Theoretical retention time:

oDM of Input oDM of Outflow



Flow rate substrate into digester: Flow rate recyclate Total flow rate into digester Surplus volume due to bubbles, foam etc Theoretic. volume in digester Flow rate effluent digester NH4-N

116,5 m³/d 0,0 m³/d 116,5 m³/d 5,0 % 122,3 m³/d 104,5 m³/d

1 item 24,0 m 6,4 m 0,3 m 2.760 m³ 2,1 kg oDM/m³·d 25 days 5.888 kg oDM/d 4.558 kg oDM/d


104,5 m³/d


5,0 % 109,7 m³/d 102,3 m³/d

3,03 g/L

note: wastes would need analyses for nutrients

storage capacity mimimum for 182 days already available and usable 0,0 m³ "Existing" Storage = Eco/Manure Bags (Flexistore) (After-Digester not considered as storage capacity in this scenario!) Mass flow from digested substrate: 39217,83 t/a Mass flow of recyclate , t/a Total mass flow 39217,83 t/a Total flow rate of material for storage: 37350,3 m³/a minus Existing: Necessary storage capacity total 18624,0 m³ (After-Digester is not considered) 18624,0 m³ 18624,0 m³ No. of Eco/Manure Bags 4 item Lengh 42,0 m 42,0 m Width Height: 2,5 m 17.640 m³ Total storage volume 17.640 m³ Storage time (annual mean): 5,7 months Relevant digestate for storage (winter/summer feeding does not vary) Maximum digestate 182 days 18.624 m³ Minimum storage volume 18.624 m³ Digestate production: 39217,83 t/a Mass flow digestate Flow rate digestate 37350,3 m³/a



861 kW




82,6 %

155



1

Month



outside

Heat transmission coefficient: Insulation: heat conductance λ thickness: Insulation index k-value: Surface of Digesters: Surface of storage tank (if heated only): Loss of heat total:

46 °C


8,9 %

506.406 kWh/a

38,3 %

2.656.819 kWh/a

∆T K 40 40 39 37 35 32 30 30 32 34 37 39

Heat Loss kWh/day 1963,5 1973,3 1904,7 1821,5 1699,1 1562,0 1483,6 1473,8 1542,4 1664,8 1831,3 1899,8

225.890 kWh/a

Thermal energy demand hygenisation Feed temperature °C 9 9 10 12 15 17 19 20 18 16 12 10

Heating energy kWh/day

3,3 %

Process energy Hygenisation kWh/day kWh/d 8.357 673,5 8.369 673,5 8.125 662,5 7.700 640,4 7.067 607,3 6.578 585,2 6.160 563,1 5.986 552,1 6.392 574,1 6.864 596,2 7.712 640,4 8.119 662,5 incl. 20% heat losses from CHP to digester 2.656.819 225.890 kWh/a

5001,1 5001,1 4865,9 4595,6 4190,1 3919,8 3649,4 3514,3 3784,6 4054,9 4595,6 4865,9

Total:

Heat utilisation: Heat produced by CHP: Process energy demand for biogas plant and hygienisation: Theoretically available surplus heat: Losses during transformation and transport to consumer:

6.942.931 kWh/a 2.882.708 kWh/a 4.060.223 kWh/a 771.442 kWh/a

19 %


3.288.780 kWh/a

47,37%




need (customer) 10.558 kWh/d 10.618 kWh/d 9.145 kWh/d 8.020 kWh/d 6.890 kWh/d 6.770 kWh/d 6.474 kWh/d 6.242 kWh/d 6.360 kWh/d 8.013 kWh/d 9.180 kWh/d 10.510 kWh/d 3.000.000 kWh/a

actually used 8.093 kWh/d 8.083 kWh/d 8.290 kWh/d 8.020 kWh/d 6.890 kWh/d 6.770 kWh/d 6.474 kWh/d 6.242 kWh/d 6.360 kWh/d 8.013 kWh/d 8.642 kWh/d 8.295 kWh/d 2.741.278 kWh/a



Calculation of actually available heat (kWh): produced Surplus heat Heat theoretical real (after loss) 589.674 309.714 250.868 532.608 279.413 226.324 589.674 317.270 256.989 570.652 320.427 259.546 589.674 351.772 284.936 570.652 355.755 288.161 589.674 381.268 308.827 589.674 387.003 313.472 570.652 361.657 292.942 589.674 358.418 290.318 570.652 320.074 259.260 589.674 317.452 257.136 6.942.931 4.060.223 3.288.780

total (kWh/a)



5.689.961 kWh/a 506.406 kWh/a x 91.039 kWh/a


506.406 0x


0

5.092.515 kWh/a

Investment costs: Scenario 8 Planning, Approval, Grid Connection Plant design, information, approval procedure, etc. (lump sum in % of invest for construct + technology + CHP) Grid Connection incl. cables and cable trenching 700 m to next transformer station Earth works, walk way preparation, access road preparation

K,T,B

Unit

B B

lump total total

1/2 T, 1/2 B T T

total total total

1/3 T, 2/3 B 1/3 T, 2/3 B

total total

B T T

£/ m3 total total

K

total

Amount


Costs [£]

2.692.010 £

Feeding technology Mixing pit with agitator, 190 m³, with submersible pump Solid feeder 40 m³, incl. extra screw conveyor and extra screws Substrate transport equipment (pumps, substrate lines between tanks, valves, etc.)

134.601 51.025 144.800 330.426 34.054 99.219 18.031 151.304

Digester and After-Digester Vertical digester (complete with mixer, heating circuit, sensors, covering, gas storage) After-fermenter (complete with mixer, heating circuit, sensors, covering, gas storage)

2 1

506.632 235.691 742.323

Storage of digestate Eco/ Manure bags (Flexistore) Mixing equipment Piping system digestate

17.640 m³ 4 4

15,0 £/m³ 5.500 3.200

299.400


861 kW

439.421 439.421

Hygienisation/ Wastes Hygenisation tank with heating, recooling, screw pump, grinder Hall with equippment

T B

349.841 410.160 760.001

Separate Buildings Working platform, container module, housing pumps and equipment, for all 3 digesters

B

total

46.362 46.362

T T T

total total total

69.837 51.970 16.191 137.998

B

£/ m

1.200 m

96

115.200 115.200

lump

5,0 %

2.692.010

134.601 134.601

Technology AD Plant Control cabinet, visualisation, electrical equipment Gas equipment (incl. desulphurication, gas quality analysis, condensate pit, gas pipes etc.) Heating equipment (heating circuits, heating pumps, valves, heat supply lines to tank)




3.157.036


Total without VAT

264.600 22.000 12.800

0 0%

0

3.157.036

156


Cost of Capital/ Ongoing Costs: Scenario 8 Write-off:

reference


20 years

86.176 £/a

Technology

994.091 £

12 years

82.841 £/a

Gas engine

439.421 £

7, years

62.774 £/a

1.578.518 £

7,0 %

110.496 £/a


annual costs

1.723.524 £

3.157.036 £

1,5 %

47.356 £/a

1.723.524 £/a

2,0 %

34.470 £/a

994.091 £/a

3,0 %

29.823 £/a

5.689.961 kWh/a

0,96 p/kWhel.

54.624 £/a


Costs for Substrates All costs for substrates are taken into account as they were indicated by the site. Any gate fees are not listed here Substrate Costs

Manure collection

cow slurry (liquid)

Silage

maize silage


31.200 t/a

as indicated by the site:

7.300 t/a

31.200 £/a

35,0 £/t (as indicated by the site)

255.500 £/a

286.700 £/a

Transport costs digestate: delivery to farms

t/a

Labour costs plant: Other operating costs (lump sum of investment costs without CHP):

as indicated by the site:

46.530 £/a

3.444 h/a

15,0 £/h

51.660 £/a

2.717.615 £/a

1,5 %

40.764 £/a


934.214 £/a




5,5 p/kWh

ROC

4,5 p/kWh

Second ROC

4,5 p/kWh

WAHR

Others

0,0 p/kWh

FALSCH



14,5 p/kWh

Revenue from electricity Gate fees for waste (as indicated by the site)

5.092.515 kWh/a

0,145 £/kWh

738.415 £/a

2.080 t/a

40,0 £/t

83.200 £/a

fish waste

150 t/a

40,0 £/t

6.000 £/a

food waste

300 t/a

30,0 £/t

9.000 £/a

1.500 t/a

30,0 £/t

45.000 £/a

2.741.278 kWh/a

0,047 £/kWh

meat waste

depackaged food waste Revenue from selling/ using the heat

Total revenue:

Business profit/ losses: Return on investment: Reflux/ reflow of capital: Payback period:

128.292 £/a

1.009.906 £/a

75.692 £/a 9,4% 7,6 years 10,3 years

157

Economic Modelling of AD in Cornwall – Annexes: AD companies

11.4 AD Companies 11.4.1

Biogas plant equipment suppliers in the UK market

Greenfinch Ltd. www.greenfinch.co.uk Michael Chesshire Greenfinch Ltd. The Business Park Coder Road Ludlow Shropshire SY8 1XE England tel.: +44 (0)1584 877687 fax: +44 (0) 1584 878131 e-mail: [email protected] Founded in 1993, the company specialises in biological and engineering aspects of anaerobic digestion. Key competences include treatment of sewage sludge, food waste, and grass or other energy crops.

Biogen (UK) Ltd. www.biogen.co.uk Milton Parc, Milton Ernest, Bedfordshire, MK44 1YU tel: ++44 (0)1234 827 249 e-mail: [email protected] Specialist in food waste digestion. BIOGEN is part of the eco-technology sector of the Bedfordia Group of companies.

Methanogen (UK) Ltd. http://www.methanogen.co.uk/ James Murcott Methanogen (UK) Ltd. The Nurton Linley Shropshire SY9 5HW tel: +44 (0)7980 541 520 e-mail: [email protected] 30 years of AD experience. Company supplies key components including gas holders, heat exchangers, mixing systems, pasteurizers, digester vessels. Has completed largest number of non-sewage works digesters in the UK and Ireland, including many on-farm digesters, treating manures, food waste and green waste.

Biogas Nord UK Ltd. www.biogas-nord.com Owen Yeatman Biogas Nord UK Ltd.

158


Henstridge Trading Estate Templecombe BA8 0TN Somerset UK tel: +44 (0)1963 365 252 fax: +44 (0)1963 364 792 e-mail: [email protected] UK subsidiary of German company Biogas Nord AG, founded in 1995, which has experience with digestion of waste waters, agricultural waste, and co-fermentation of municipal or industrial wastes. Very small-scale plants up to large-scale facilities have been completed. All necessary AD equipment is supplied, including CHP unit.

EnviTec Biogas UK Ltd. http://www.envitec-biogas.com John Day Colton Road Rugeley Staffordshire, WS15 3HF tel.: +44 (0)1889 584459 fax.: +44 (0)1889 578088 e-mail: [email protected] or [email protected] EnviTec Biogas UK is the UK subsidiary of German company EnviTec Biogas AG. EnviTec Biogas AG covers the entire value chain for the production of biogas. In Cornwall, in 2008 the company will build an 844 kW plant at Penare Farm, Higher Fraddon, near Truro, where there is a 600-sow farrow-to-finish unit.

BEKON Energy Technologies GmbH & Co. KG www.bekon-energy.de Feringastraße 9 85774 Unterföhring Germany tel: +49 (0)89 9077 9590 fax: +49 (0)89 9077 95929 e-mail: [email protected] UK partner: James Lloyd (CEO), HotRot Composting Systems Ltd, Milbank, Mundford Road, Weeting, Norfolk IP27 0PL, tel: +44 (0)1842 816909, fax: +44 (0)8707 053055, e-mail: [email protected] The BEKON group companies cover various fields of environmental engineering. BEKON Energy Technologies GmbH & Co. KG is the expert company in dry digestion, which offers complete planning and construction of the biogas plant.

WELtec BioPower GmbH www.weltec-biopower.de WELtec BioPower GmbH Zum Langenberg 2 49377 Vechta Germany tel: +49 (0)4441 999780 fax : +49 (0)4441 999788 e-mail: [email protected] WELtec, set up 2001 by German agricultural systems manufacturer WEDA and Stalkamp, provide complete AD systems using stainless steel vessels, including equipment for solid substrate handling, pasteurisation, CHP units. Most projects are in Germany, but the first units in the United States, in Japan, Sweden, in The Netherlands and in the United Kingdom have already been put into effect. An agent for UK is available.

159


FARMATIC Anlagenbau GmbH www.farmatic.com Kolberger Straße 13 24589 Nortorf Germany tel.: +49 (0)4392 91770 fax: +49 (0)4392 5864 e-mail: [email protected] Farmatic has constructed many large-scale biogas plants since around 15 years (throughputs typically 35,000 to 140,000 t/a). The centralised digestion plant at Holsworthy, Devon, UK, digests cattle, pig, and poultry manure, and food wastes.

Hese Biogas GmbH www.hese-biogas.de Magdeburger Straße 16b 45881 Gelsenkirchen Germany tel.: +49 (0)209 98099 900 fax: +49 (0)209 98099 901 e-mail: [email protected] Previously part of Hese Umwelt GmbH, Gelsenkirchen, Germany, a company specialised in waste management and waste treatment (in Britain: e.g. mechanical & biological waste treatment plant for the City of Leicester and Biffa Waste Services), Hese Biogas GmbH presently belongs to Schmack Biogas AG, Germany, and is specialised in AD plants for treatment of residual bio waste, food waste and agricultural substrates.

Schmack Biogas AG www.schmack-biogas.com Bayernwerk 8 92421 Schwandorf Germany tel.: +49 (0)94 31 751 0 fax: +49 (0)94 31 751 204 e-mail: [email protected] Active since 1995 in the biogas sector, the company provides support during the planning phase and builds complete biogas systems.

Organic Power Ltd. www.organic-power.co.uk Organic Power Ltd. Gould’s House Horsington Somerset BA8 0EW England tel: +44 (0) 1963 371 100 fax: +44 (0) 1963 371 300 e-mail: [email protected] Organic Power has been active in the field of anaerobic digestion for many years, mainly with consultancy work for government departments and private clients. Commercial demo plant is at company headquarters in Somerset. Bubbling

160


biogas from central cusp of low energy tank shape creates opposing circulation patterns within tank. Adding liquid material at centre of circulation pattern and removing it from opposite end gives a continuous plug flow.

Bioplex Technologies Ltd www.bioplex.co.uk Bioplex Technologies Ltd Unit 5, The Cobden Centre Folly Brook Road Emerald Park Emersons Green Bristol BS16 7FQ United Kingdom tel.: +44 (0)117 301 4409 fax: +44 (0)845 602 0066 e-mail: [email protected] The Portagester® is a mobile and modular anaerobic fermenter, which can hygienically treat waste material in less than four days. It operates as leachate bed reactor with pasteurisation and hydrolysis and was developed by Bioplex Technologies Ltd as part of a process which digests solid waste materials. The liquefied organic material is then digested in a second reactor.

Monsal Ltd. www.monsal.co.uk Oak House Ransom Wood Park Southwell Road West Mansfield NG21 0HJ United Kingdom tel: +44 (0)1623 429500 fax: +44 (0)1623 429505 e-mail: [email protected] Monsal is a specialist environmental technology company providing engineered solutions for the water and waste sectors. Many Monsal components are operating in the UK, incorporating thermal pasteurization and biological hydrolysis pretreatment. Components and complete digestion systems are available.

Enpure Ltd. www.enpure.co.uk Enpure House Woodgate Business Park Kettleswood Drive Birmingham B32 3DB tel.: +44 (0)121 251 9000 fax: +44 (0)121 251 9111 e-mail: [email protected] Enpure Ltd., formerly Purac Ltd., provides solutions for the water and waste sectors and supplied some of the major ADbased sludge treatment systems in the UK. Licensee in UK for BTA Process, plants process green waste, manure, sewage sludge and MSW.

Biogas Hochreiter GmbH www.biogas-hochreiter.de

161


Johann Hochreiter GmbH Hermann in der Steinau 1 83530 Schnaitsee Germany tel: +49 (0)8622 98730 00 fax: +49 (0)8622 98730 99 e-mail: [email protected] UK Partner: SRG Energy Parks (UK) Ltd, Stable End, Hawthorn, Seaham, Co Durham, SR7 8SG, tel.: +44 (0)1642 355 383, fax: +44 (0)1642 550 400, e-mail: [email protected] Biogas Hochreiter GmbH is a pioneer company in the German agricultural biogas sector. Johann Hochreiter is involved in AD since 1985. The company provides complete biogas plants or single components including CHP units.

162


11.4.2

Profiles of Companies which Contributed to this Study’s Results by giving UK market prices

Support from companies and their willingness to cooperate within this project are gratefully acknowledged. In the following, this report includes profiles from the following companies:

Greenfinch

Fre-Energy (Methanogen)

Bioplex

Biogas Nord

EnviTec

Hochreiter

Bekon

Fitec

Companies with contributions to this study, but of which no profile is attached:

Novatech

Organic Power

Hans Huber AG

163


IBBK Am Feuersee 6 74592 Kirchberg/ Weckelweiler Germany www.biogas-zentrum.de [email protected]

164