Publications
230 results found
Santarelli M, Gandiglio M, Acri M, et al., 2019, Results from industrial size biogas-fed SOFC plant (DeMosofC project), Pages: 107-116, ISSN: 1938-6737
The EU-funded DEMOSOFC project demonstrates the technical and economic feasibility of operating a 174 kWe (+ 100 kWth) SOFC system in a wastewater treatment plant, fed by biogas. The integrated biogas-SOFC plant includes three main units: 1) the biogas clean-up and compression section; 2) the SOFC power modules, and 3) the heat recovery loop. The present work is related to the results of the operation of the SOFC system. More than 7000 hours of operation have been reached onsite. Biogas raw composition is daily measured: starting form values of around 50 ppm (Sulphur equivalent) and 1.0-1.5 ppm (siloxanes equivalent) downstream the results show zero H2S and zero siloxanes. Measured SOFC efficiency from biogas to AC power has always been higher than 52-53%, with peaks of 56%. A dedicated emissions measurements campaign shows NOx < 20 mg/m3, SO2 < 8 mg/m3 and particulate lower than ambient air values (0.01 mg/m3).
Oluleye G, Wigh D, Shah N, et al., 2019, A framework for biogas exploitation in Italian waste water treatment plants, Chemical Engineering Transactions, Vol: 76, Pages: 991-996
Copyright © 2019, AIDIC Servizi S.r.l. Effective utilisation of biogas is an important step in increasing usage of renewable energy, due to the great flexibility that solar and wind power in particular lacks. Biogas generated through anaerobic digestion (AD) of sewage sludge addresses environmental concerns together with creating electricity generation potential. There is currently no optimisation-based decision-support framework to determine the best use of biogas from a Waste Water Treatment Plant (WWTP), and provide a market outlook for each of the options. This work proposes a novel multi-period Mixed Integer Linear Program (MILP) model for dispatch and selection of technologies capable of exploiting biogas produced from sludge. The novelty is also highlighted by extrapolating the optimised results to a broader analysis of 855 Italian WWTPs with Population Equivalent (P.E.) > 20,000. The use of real input data provides a unique added value to the work. The modelling framework is applied to several case studies. Results show that 7–23 % savings in operating costs are possible from integrating three systems to exploit biogas, and the trade-offs between capital and operating costs affect the optimal system choice. Furthermore, market driven scenarios are used to analyse how to improve the economic performance.
Bosch J, Staffell I, Hawkes A, 2018, Temporally explicit and spatially resolved global offshore wind energy potentials, Energy, Vol: 163, Pages: 766-781, ISSN: 0360-5442
Several influential energy systems models (ESMs) indicate that renewable energy must supply a large share of the world's electricity to limit global temperature increases to 1.5 °C. To better represent the costs and other implications of such a transition, it is important that ESMs can realistically characterise the technical and economic potential of renewable energy resources. This paper presents a Geospatial Information System methodology for estimating the global offshore wind energy potential, i.e. the terawatt hour per year (TWh/yr) production potential of wind farms, assuming capacity could be built across the viable offshore area of each country. A bottom-up approach characterises the capacity factors of offshore wind farms by estimating the available wind power from high resolution global wind speed data sets. Temporal phenomena are retained by binning hourly wind speeds into 32 time slices per year considering the wind resource across several decades. For 157 countries with a viable offshore wind potential, electricity generation potential is produced in tranches according to the distance to grid connection, water depth and average annual capacity factor. These data can be used as inputs to ESMs and to assess the economically viable offshore wind energy potential, on a global or per-country basis.
Budinis S, Krevor S, Mac Dowell N, et al., 2018, An assessment of CCS costs, barriers and potential, Energy Strategy Reviews, Vol: 22, Pages: 61-81, ISSN: 2211-467X
© 2018 Elsevier Ltd Global decarbonisation scenarios include Carbon Capture and Storage (CCS) as a key technology to reduce carbon dioxide (CO2) emissions from the power and industrial sectors. However, few large scale CCS plants are operating worldwide. This mismatch between expectations and reality is caused by a series of barriers which are preventing this technology from being adopted more widely. The goal of this paper is to identify and review the barriers to CCS development, with a focus on recent cost estimates, and to assess the potential of CCS to enable access to fossil fuels without causing dangerous levels of climate change. The result of the review shows that no CCS barriers are exclusively technical, with CCS cost being the most significant hurdle in the short to medium term. In the long term, CCS is found to be very cost effective when compared with other mitigation options. Cost estimates exhibit a high range, which depends on process type, separation technology, CO2transport technique and storage site. CCS potential has been quantified by comparing the amount of fossil fuels that could be used globally with and without CCS. In modelled energy system transition pathways that limit global warming to less than 2 °C, scenarios without CCS result in 26% of fossil fuel reserves being consumed by 2050, against 37% being consumed when CCS is available. However, by 2100, the scenarios without CCS have only consumed slightly more fossil fuel reserves (33%), whereas scenarios with CCS available end up consuming 65% of reserves. It was also shown that the residual emissions from CCS facilities is the key factor limiting long term uptake, rather than cost. Overall, the results show that worldwide CCS adoption will be critical if fossil fuel reserves are to continue to be substantively accessed whilst still meeting climate targets.
Oluleye OO, Allison J, Hawker G, et al., 2018, A two-step optimization model for quantifying the flexibility potential of power-to-heat systems in dwellings, Applied Energy, Vol: 228, Pages: 215-228, ISSN: 0306-2619
Coupling the electricity and heat sectors is receiving interest as a potential source of flexibility to help absorb surplus renewable electricity. The flexibility afforded by power-to-heat systems in dwellings has yet to be quantified in terms of time, energy and costs, and especially in cases where homeowners are heterogeneous prosumers. Flexibility quantification whilst accounting for prosumer heterogeneity is non-trivial. Therefore in this work a novel two-step optimization framework is proposed to quantify the potential of prosumers to absorb surplus renewable electricity through the integration of air source heat pumps and thermal energy storage. The first step is formulated as a multi-period mixed integer linear programming problem to determine the optimal energy system, and the quantity of surplus electricity absorbed. The second step is formulated as a linear programming problem to determine the price a prosumer will accept for absorbing surplus electricity, and thus the number of active prosumers in the market.A case study of 445 prosumers is presented to illustrate the approach. Results show that the number of active prosumers is affected by the quantity of absorbed electricity, frequency of requests, the price offered by aggregators and how prosumers determine the acceptable value of flexibility provided. This study is a step towards reducing the need for renewable curtailment and increasing pricing transparency in relation to demand-side response.
Balcombe P, Speirs JF, Brandon NP, et al., 2018, Methane emissions: choosing the right climate metric and time horizon, Environmental Science: Processes and Impacts, Vol: 20, Pages: 1323-1339, ISSN: 2050-7895
Methane is a more potent greenhouse gas (GHG) than CO2, but it has a shorter atmospheric lifespan, thus its relative climate impact reduces significantly over time. Different GHGs are often conflated into a single metric to compare technologies and supply chains, such as the global warming potential (GWP). However, the use of GWP is criticised, regarding: (1) the need to select a timeframe; (2) its physical basis on radiative forcing; and (3) the fact that it measures the average forcing of a pulse over time rather than a sustained emission at a specific end-point in time. Many alternative metrics have been proposed which tackle different aspects of these limitations and this paper assesses them by their key attributes and limitations, with respect to methane emissions. A case study application of various metrics is produced and recommendations are made for the use of climate metrics for different categories of applications. Across metrics, CO2 equivalences for methane range from 4–199 gCO2eq./gCH4, although most estimates fall between 20 and 80 gCO2eq./gCH4. Therefore the selection of metric and time horizon for technology evaluations is likely to change the rank order of preference, as demonstrated herein with the use of natural gas as a shipping fuel versus alternatives. It is not advisable or conservative to use only a short time horizon, e.g. 20 years, which disregards the long-term impacts of CO2 emissions and is thus detrimental to achieving eventual climate stabilisation. Recommendations are made for the use of metrics in 3 categories of applications. Short-term emissions estimates of facilities or regions should be transparent and use a single metric and include the separated contribution from each GHG. Multi-year technology assessments should use both short and long term static metrics (e.g. GWP) to test robustness of results. Longer term energy assessments or decarbonisation pathways must use both short and long-term metrics and where this has a lar
Guo Y, Hawkes A, 2018, Simulating the game-theoretic market equilibrium and contract-driven investment in global gas trade using an agent-based method, Energy, Vol: 160, Pages: 820-834, ISSN: 0360-5442
To understand how the alternative US liquefied natural gas exportation strategies may affect future global gas market dynamics, a global-scale model Gas-GAME is developed using an agent-based framework. This is the first model having explicit contract-driven capacity expansion process, allowing investors to hold imperfect foresights, and simulating market power in global gas trade. With these features, Gas-GAME can analyse market development subject to the incentives and perspectives of each market player. The model simulates short-term game-theoretical market equilibrium with Mixed Complementarity Problem approach. For long-term investment decisions, bilateral contracting processes considering both import requests and export profitability are modelled. A base case is presented and validated, followed by a case study considering US export strategy. When the US stays conservative in export expansion, gas supply tightness occurs, leading to continuing European dependence on Russian gas, and a shift to pipeline-based import in the Chinese market. Conversely, when the US invests aggressively, Middle East and Australia both see significant revenue losses, and Western Europe constructs more regasification plants to provide alternatives to Russian supply. Gas-GAME captures the essential dynamics between market power, short-term prices and long-term contracts to provide a more nuanced view of global gas market.
Crow DJG, Anderson K, Hawkes AD, et al., 2018, Impact of drilling costs on the US gas industry: prospects for automation, Energies, Vol: 11, ISSN: 1996-1073
Recent low gas prices have greatly increased pressure on drilling companies to reduce costs and increase efficiency. Field trials have shown that implementing automation can dramatically reduce drilling costs by reducing the time required to drill wells. This study uses the DYNamic upstreAm gAs MOdel (DYNAAMO), a new techno-economic, bottom-up model of natural gas supply, to quantitatively assess the economic impact of lower drilling costs on the US upstream gas industry. A sensitivity analysis of three key economic indicators is presented, with results quoted for the most common field types currently producing, including unconventional and offshore gas. While all operating environments show increased profitability from drilling automation, it is found that conventional onshore reserves can benefit to the greatest extent. For large gas fields, a 50% reduction in drilling costs is found to reduce initial project breakevens by up to 17 million USD per billion cubic metres (MUSD/BCM) and mid-plateau breakevens by up to 8 MUSD/BCM. In this same scenario, additional volumes of around 160 BCM of unconventional gas are shown to become commercial due to both the lower costs of additional production wells in mature fields and the viability of developing new resources held in smaller fields. The capital efficiency of onshore projects increases by 50%-100%, with initial project net present value (NPV) gains of up to 32%.
Miu LM, Wisniewska N, Mazur C, et al., 2018, A simple assessment of housing retrofit policies for the UK: what should succeed the energy company obligation?, Energies, Vol: 11, ISSN: 1996-1073
Despite the need for large-scale retrofit of UK housing to meet emissions reduction targets, progress to date has been slow and domestic energy efficiency policies have struggled to accelerate housing retrofit processes. There is a need for housing retrofit policies that overcome key barriers within the retrofit sector while maintaining economic viability for customers, funding organizations, and effectively addressing UK emission reductions and fuel poverty targets. In this study, we use a simple assessment framework to assess three policies (the Variable Council Tax, the Variable Stamp Duty Land Tax, and Green Mortgage) proposed to replace the UK’s current major domestic retrofit programme known as the Energy Company Obligation (ECO). We show that the Variable Council Tax and Green Mortgage proposals have the greatest potential for overcoming the main barriers to retrofit policies while maintaining economic viability and contributing to high-level UK targets. We also show that, while none of the assessed schemes are capable of overcoming all retrofit barriers on their own, a mix of all three policies could address most barriers and provide key benefits such as wide coverage of property markets, operation on existing financial infrastructures, and application of a “carrot-and-stick” approach to incentivize retrofit. Lastly, we indicate that the specific support and protection of fuel-poor households cannot be achieved by a mix of these policies and a complementary scheme focused on fuel-poor households is required.
Balcombe P, Speirs J, Johnson E, et al., 2018, The carbon credentials of hydrogen gas networks and supply chains, Renewable and Sustainable Energy Reviews, Vol: 91, Pages: 1077-1088, ISSN: 1364-0321
Projections of decarbonisation pathways have typically involved reducing dependence on natural gas grids via greater electrification of heat using heat pumps or even electric heaters. However, many technical, economic and consumer barriers to electrification of heat persist. The gas network holds value in relation to flexibility of operation, requiring simpler control and enabling less expensive storage. There may be value in retaining and repurposing gas infrastructure where there are feasible routes to decarbonisation. This study quantifies and analyses the decarbonisation potential associated with the conversion of gas grids to deliver hydrogen, focusing on supply chains. Routes to produce hydrogen for gas grids are categorised as: reforming natural gas with (or without) carbon capture and storage (CCS); gasification of coal with (or without) CCS; gasification of biomass with (or without) CCS; electrolysis using low carbon electricity. The overall range of greenhouse gas emissions across routes is extremely large, from − 371 to 642 gCO 2 eq/kW h H2 . Therefore, when including supply chain emissions, hydrogen can have a range of carbon intensities and cannot be assumed to be low carbon. Emissions estimates for natural gas reforming with CCS lie in the range of 23–150 g/kW h H2 , with CCS typically reducing CO 2 emissions by 75%. Hydrogen from electrolysis ranges from 24 to 178 gCO 2 eq/kW h H2 for renewable electricity sources, where wind electricity results in the lowest CO 2 emissions. Solar PV electricity typically exhibits higher emissions and varies significantly by geographical region. The emissions from upstream supply chains is a major contributor to total emissions and varies considerably across different routes to hydrogen. Biomass gasification is characterised by very large negative emissions in the supply chain and very large positive emissions in the gasification process. Therefore, improvements in total emissions are large if even small i
Vijay A, Hawkes A, 2018, Impact of dynamic aspects on economics of fuel cell based micro co-generation in low carbon futures, Energy, Vol: 155, Pages: 874-886, ISSN: 0360-5442
This article evaluates the impact of a range of dynamic performance parameters on the techno-economics of fuel cell based micro co-generation. The main novelties in methodology are: (1) Analysis in the context of future power system decarbonisation, (2) Use of the Long Run Marginal Cost of electricity, (3) Combination of the above with dynamic aspects such as start-up cost, ramping limit, turn down ratio, minimum up time and minimum down time and (4) Identification of sensitive parameters for future research. To this end it combines a national level energy systems model with an individual heating system model. A case study of the United Kingdom is considered for the year 2035. Economic viability of fuel cell based micro co-generation hinges upon the use of an optimized control strategy. With such a control strategy, a hot start-up approach offers much greater economic potential than a cold start-up approach. The best case ratio of maximum allowable hot standby power to the nominal value is 4.2 while the ratio for cold start is only 1.1. Combinations involving low ramping limits less than 70 W/min and limited turn down ratios above 35% need to be avoided as they seriously hinder economic performance.
Jalil Vega FA, Hawkes A, 2018, The effect of spatial resolution on outcomes from energy systems modelling of heat decarbonisation, Energy, Vol: 155, Pages: 339-350, ISSN: 0360-5442
Spatial resolution is often cited as a crucial determinant of results from energy systems models. However, there is no study that comprehensively analyses the effect of spatial resolution. This paper addresses this gap by applying the Heat Infrastructure and Technology heat decarbonisation optimisation model in six UK Local Authorities representing a range of rural/urban areas, at three levels of spatial resolution, in order to systematically compare results. Results show the importance of spatial resolution for optimal allocation of heat supply technologies and infrastructure across different urban/rural areas. Firstly, for the studied cases, differences of up to 30% in heat network uptake were observed when comparing results between different resolutions for a given area. Secondly, for areas that generally exhibit the high and low extremes of linear heat density, results are less dependent on spatial resolution. Also, spatial resolution effects are more significant when there is higher variability of linear heat density throughout zones. Finally, results show that it is important to use finer resolutions when using optimisation models to inform detailed network planning and expansion. Higher spatial resolutions provide more detailed information on zones that act as anchors that can seed network growth and on location of network supply technologies.
Allison J, Bell K, Clarke J, et al., 2018, Assessing domestic heat storage requirements for energy flexibility over varying timescales, Applied Thermal Engineering, Vol: 136, Pages: 602-616, ISSN: 1359-4311
© 2018 The Authors This paper explores the feasibility of storing heat in an encapsulated store to support thermal load shifting over three timescales: diurnal, weekly and seasonal. A building simulation tool was used to calculate the space heating and hot water demands for four common UK housing types and a range of operating conditions. A custom sizing methodology calculated the capacities of storage required to fully meet the heat demands over the three timescales. Corresponding storage volumes were calculated for a range of heat storage materials deemed suitable for storing heat within a dwelling, either in a tank or as an integral part of the building fabric: hot water, concrete, high-temperature magnetite blocks, and a phase change material. The results indicate that with low temperature heat storage, domestic load shifting is feasible over a few days. Beyond this timescale, the very large storage volumes required make integration in dwellings problematic. Supporting load shifting over 1–2 weeks is feasible with high temperature storage. Retention of heat over periods longer than this is challenging, even with significant levels of insulation. Seasonal storage of heat in an encapsulated store appeared impractical in all cases modelled due to the volume of material required.
Jalil Vega FA, Hawkes A, 2018, Spatially resolved optimization for studying the role of hydrogen for heat decarbonization pathways, ACS Sustainable Chemistry and Engineering, Vol: 6, Pages: 5835-5842, ISSN: 2168-0485
This paper studies the economic feasibility of installing hydrogen networks for decarbonising heat in urban areas. The study uses the Heat Infrastructure and Technology (HIT) spatially-resolved optimisation model to trade-off energy supply, infrastructure and end-use technology costs for the most important heat-related energy vectors; gas, heat, electricity, and hydrogen. Two model formulations are applied to UK urban area: one with an independent hydrogen network, and one that allows for retrofitting the gas network into hydrogen. Results show that for average hydrogen price projections, cost-effective pathways for heat decarbonisation towards 2050 comprise including heat networks supplied by a combination of district level heat pumps and gas boilers in the domestic and commercial sectors, and hydrogen boilers in the domestic sector. For a low hydrogen price scenario, when retrofitting the gas network into hydrogen, a cost-effective pathway is replacing gas by hydrogen boilers in the commercial sector, and a mixture of hydrogen boilers and heat networks supplied by district level heat pumps, gas, and hydrogen boilers for the domestic sector. Compared to the first modelled year, CO2 emissions reductions of 88% are achieved by 2050. These results build on previous research on the role of hydrogen in cost-effective heat decarbonisation pathways.
Oluleye G, Hawkes AD, Allison J, et al., 2018, An optimisation study on integrating and incentivising Thermal Energy Storage (TES) in a dwelling energy system, Energies, Vol: 11, ISSN: 1996-1073
In spite of the benefits from thermal energy storage (TES) integration in dwellings, the penetration rate in Europe is 5%. Effective fiscal policies are necessary to accelerate deployment. However, there is currently no direct support for TES in buildings compared to support for electricity storage. This could be due to lack of evidence to support incentivisation. In this study, a novel systematic framework is developed to provide a case in support of TES incentivisation. The model determines the costs, CO2 emissions, dispatch strategy and sizes of technologies, and TES for a domestic user under policy neutral and policy intensive scenarios. The model is applied to different building types in the UK. The model is applied to a case study for a detached dwelling in the UK (floor area of 122 m2), where heat demand is satisfied by a boiler and electricity imported from the grid. Results show that under a policy neutral scenario, integrating a micro-Combined Heat and Power (CHP) reduces the primary energy demand by 11%, CO2 emissions by 21%, but with a 16 year payback. Additional benefits from TES integration can pay for the investment within the first 9 years, reducing to 3.5–6 years when the CO2 levy is accounted for. Under a policy intensive scenario (for example considering the Feed in Tariff (FIT)), primary energy demand and CO2 emissions reduce by 17 and 33% respectively with a 5 year payback. In this case, the additional benefits for TES integration can pay for the investment in TES within the first 2 years. The framework developed is a useful tool is determining the role TES in decarbonising domestic energy systems.
Speirs JF, balcombe P, johnson E, et al., 2018, A Greener Gas Grid: What Are the Options?, Energy Policy, Vol: 118, Pages: 291-297, ISSN: 0301-4215
There is an ongoing debate over future decarbonisation of gas networks using biomethane, and increasingly hydrogen, in gas network infrastructure. Some emerging research presents gas network decarbonisation options as a tractable alternative to ‘all-electric’ scenarios that use electric appliances to deliver the traditional gas services such as heating and cooking. However, there is some uncertainty as to the technical feasibility, cost and carbon emissions of gas network decarbonisation options. In response to this debate the Sustainable Gas Institute at Imperial College London has conducted a rigorous systematic review of the evidence surrounding gas network decarbonisation options. The study focuses on the technologies used to generate biomethane and hydrogen, and examines the technical potentials, economic costs and emissions associated with the full supply chains involved. The following summarises the main findings of this research. The report concludes that there are a number of options that could significantly decarbonise the gas network, and doing so would provide energy system flexibility utilising existing assets. However, these options will be more expensive than the existing gas system, and the GHG intensity of these options may vary significantly. In addition, more research is required, particularly in relation to the capabilities of existing pipework to transport hydrogen safely.
Crow DJG, Giarola S, Hawkes AD, 2018, A dynamic model of global natural gas supply, Applied Energy, Vol: 218, Pages: 452-469, ISSN: 0306-2619
This paper presents the Dynamic Upstream Gas Model (DYNAAMO); a new, global, bottom-up model of natural gas supply. In contrast to most “static” supply-side models, which bracket resources by average cost, DYNAAMO creates a range of dynamic outputs by simulating investment and operating decisions in the upstream gas industry triggered in response to investors’ expectations of future gas prices. Industrial data from thousands of gas fields is analysed and used to build production and expenditure profiles which drive the economics of supply at field level. Using these profiles, a novel methodology for estimating supply curves is developed which incorporates the size, age and operating environment of gas fields, and treats explicitly the fiscal, abandonment, exploration and emissions costs of production. The model is validated using the US shale gas boom in the 2000s as a historic case study. It is found that the modelled market share of supply by field environment replicates the observed trend during the period 2000–2010, and that the model price response during the same period – due to lower capacity margins and the financing of new projects – is consistent with market behaviour.
Giarola S, Forte O, Lanzini A, et al., 2018, Techno-economic assessment of biogas-fed solid oxide fuel cell combined heat and power system at industrial scale, Applied Energy, Vol: 211, Pages: 689-704, ISSN: 0306-2619
Wastewater treatment plants (WWTP) are currently very energy and greenhouse gas intensive processes. An important opportunity to reduce both of these quantities is via the use of biogas produced within the treatment process to generate energy. This paper studies the optimal energy and economic performance of a wastewater treatment facility fitted with a solid oxide fuel cell (SOFC) based combined heat and power (CHP) plant. An optimisation framework is formulated and then applied to determine cost, energy and emissions performance of the retrofitted system when compared with conventional alternatives.Results show that present-day capital costs of SOFC technology mean that it does not quite compete with the conventional alternatives. But, it could become interesting if implemented in thermally-optimised WWTP systems. This would increase the SOFC manufacturing volumes and drive a reduction of capital and fixed operating costs.
de Castro REN, Alves RMB, Hawkes A, et al., 2018, Open Sugarcane Process Simulation Platform, Computer Aided Chemical Engineering, Pages: 1819-1824
Software tools for process simulation and optimization have increasingly been used in industry to design and operate complex, highly interconnected plants. This allows the design of industrial plants to be profitable and to meet quality, safety, environmental and other standards. The aim of this work is to create a platform to simulate industrial sugarcane first generation process. Brazilian sugarcane industry is a well known process with many parameters available from industrial and literature data. The current first generation process seems to have reached the state of art and not great improvements seams to emerge nowadays. However engineering research has dedicated great efforts recently to improve efficiency through the use of industrial and agricultural residues. Most of these studies are related to the use of lignocellulosic material and vinasse. In this context an easy and simple platform has been developed to provide reliable outputs that could provide data for the studies of viability, social and environmental impacts when an additional process are interconnected to the first generation plant. The model has been validated using industrial data in order to attain the most realistic outputs.
Garcia Kerdan I, Hawkes AD, Giarola S, 2018, Implications of Future Natural Gas Infrastructure on Bioenergy Production, Land Use Change and Related Emissions: A Brazil Case Study, 1st SDEWES Latin America
Due to its low global share of direct energy consumption (3-5%) and greenhouse gas emissions (1-2%), energy systems models (ESM) have unfairly overlooked the implications of technological transitions in the agricultural sector. In fact, if the demand of agrochemicals and land use changes (LUC) due to expansion of bioenergy crops and increasing food demand are considered, the sector is indirectly responsible for up to 30% of global emissions. This paper introduces the Agriculture and Land Use Sector Simulation Module (Ag&LU-SM) which is integrated in a novel ESM, called MUSE, the ModUlar energy systems Simulation Environment. The Ag&LU-SM simulates the investments in agricultural energy technologies through the concept of mechanisation diffusion to meet the demand of sector’s commodities, such as crops, animal and forestry products, as well as the implications due to LUC when arable or forest land is allocated to bioenergy crops. The aim is to study the sector’s dynamics and resource competition between bioenergy and natural gas at a country level. Brazil, one of the major bioenergy producers and with large amounts of oil and natural gas reserves, is used as a case study to study the implications in terms of land use change in two different scenarios. One scenario explores a ten-fold expansion of bioenergy production by 2050, which means a 6% annual growth rate. The second scenario explores the expansion of natural gas production while halving bioenergy production (3% annual growth rate). Results show that, in order to meet the future food and bioenergy demand, the agricultural sector should move from transitional to modern agricultural practices, improve the productivity at the expense of higher energy consumption, invest in efficient agricultural practices to reduce land-related emissions and have the opportunity to liberate crop and pasture land that could be used for dedicated energy crops. Finally, the development of a gas infrastructure coul
Sechi S, Giarola S, Lanzini A, et al., 2018, An optimization method to estimate the SOFC market in waste water treatment, Editors: Friedl, Klemes, Radl, Varbanov, Wallek, Publisher: ELSEVIER SCIENCE BV, Pages: 415-420
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Sachs J, Hidayat S, Giarola S, et al., 2018, The role of CCS and biomass-based processes in the refinery sector for different carbon scenarios, Editors: Friedl, Klemes, Radl, Varbanov, Wallek, Publisher: ELSEVIER SCIENCE BV, Pages: 1365-1370
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Luh S, Budinis S, Schmidt TJ, et al., 2018, Decarbonisation of the Industrial Sector by means of Fuel Switching, Electrification and CCS, Editors: Friedl, Klemes, Radl, Varbanov, Wallek, Publisher: ELSEVIER SCIENCE BV, Pages: 1311-1316
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Sachs J, Massari C, Hawkes A, et al., 2018, Distributed Optimization for a Cost Efficient Operation of a Network of Island Energy Systems, 2nd IEEE Conference on Control Technology and Applications (CCTA), Publisher: IEEE, Pages: 46-53
Oluleye G, Allison J, Kelly N, et al., 2018, A Multi-period Mixed Integer Linear Program for Assessing the Benefits of Power to Heat Storage in a Dwelling Energy System, Editors: Friedl, Klemes, Radl, Varbanov, Wallek, Publisher: ELSEVIER SCIENCE BV, Pages: 1451-1456
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Budinis S, Giarola S, Sachs J, et al., 2017, Modelling the impacts of investors' decision making on decarbonisation pathways in industry, 10th Annual Meeting of the IAMC, Publisher: IAMC
The Paris Climate agreement calls for dramatic changes in the energy system. This will be challenging for demand sectors like industry, which is notoriously energy intensive. Although increased efficiency has proven to be suitable options to reduce energy and environmental impacts, stringent regulations on carbon will require this sector to undergo an unprecedented innovation effort, which will go well beyond cost efficiency measures to include the deployment of novel technologies and, most likely, of carbon capture and storage (CCS).This manuscript focuses on the uptake of novel technologies in the industrial sector and the barriers which might prevent or slow down the pace of innovation. Some of these barriers are technological as they depend on the availability and the technology readiness level of a specific technology. Others are instead related to the attitude that investors show towards innovative and the inherent level of risk. Among the many innovation options in the industrial sector, the focus here is on the uptake of the carbon capture and storage technologies.The industrial sector is modelled including the top-energy intensive industries, such as those manufacturing pulp and paper, iron and steel, chemicals and petrochemicals, the non-ferrous metals as well as non-metallic minerals. The simulations are carried out using a novel energy systems model, MUSE, the Modular energy systems Simulation Environment.
Balcombe P, Brandon NP, Hawkes AD, 2017, Characterising the distribution of methane and carbon dioxide emissions from the natural gas supply chain, Journal of Cleaner Production, Vol: 172, Pages: 2019-2032, ISSN: 0959-6526
Methane and CO2 emissions from the natural gas supply chain have been shown to vary widely butthere is little understanding about the distribution of emissions across supply chain routes,processes, regions and operational practises. This study defines the distribution of total methaneand CO2 emissions from the natural gas supply chain, identifying the contribution from each stageand quantifying the effect of key parameters on emissions. The study uses recent high-resolutionemissions measurements with estimates of parameter distributions to build a probabilistic emissionsmodel for a variety of technological supply chain scenarios. The distribution of emissions resemblesa log-log-logistic distribution for most supply chain scenarios, indicating an extremely heavy tailedskew: median estimates which represent typical facilities are modest at 18 – 24 g CO2 eq./ MJ HHV,but mean estimates which account for the heavy tail are 22 – 107 g CO2 eq./ MJ HHV. To place thesevalues into context, emissions associated with natural gas combustion (e.g. for heat) areapproximately 55 g CO2/ MJ HHV. Thus, some supply chain scenarios are major contributors to totalgreenhouse gas emissions from natural gas. For methane-only emissions, median estimates are 0.8 –2.2% of total methane production, with mean emissions of 1.6 - 5.5%. The heavy tail distribution isthe signature of the disproportionately large emitting equipment known as super-emitters, whichappear at all stages of the supply chain. The study analyses the impact of different technologicaloptions and identifies a set of best technological option (BTO) scenarios. This suggests thatemissions-minimising technology can reduce supply chain emissions significantly, with this studyestimating median emissions of 0.9% of production. However, even with the emissions-minimisingtechnologies, evidence suggests that the influence of the super-emitters remains. Therefore,emissions-minimising technology is only part of the soluti
Schmidt O, Gambhir A, Staffell IL, et al., 2017, Future cost and performance of water electrolysis: An expert elicitation study, International Journal of Hydrogen Energy, Vol: 42, Pages: 30470-30492, ISSN: 0360-3199
The need for energy storage to balance intermittent and inflexible electricity supply with demand is driving interest in conversion of renewable electricity via electrolysis into a storable gas. But, high capital cost and uncertainty regarding future cost and performance improvements are barriers to investment in water electrolysis. Expert elicitations can support decision-making when data are sparse and their future development uncertain. Therefore, this study presents expert views on future capital cost, lifetime and efficiency for three electrolysis technologies: alkaline (AEC), proton exchange membrane (PEMEC) and solid oxide electrolysis cell (SOEC). Experts estimate that increased R&D funding can reduce capital costs by 0–24%, while production scale-up alone has an impact of 17–30%. System lifetimes may converge at around 60,000–90,000 h and efficiency improvements will be negligible. In addition to innovations on the cell-level, experts highlight improved production methods to automate manufacturing and produce higher quality components. Research into SOECs with lower electrode polarisation resistance or zero-gap AECs could undermine the projected dominance of PEMEC systems. This study thereby reduces barriers to investment in water electrolysis and shows how expert elicitations can help guide near-term investment, policy and research efforts to support the development of electrolysis for low-carbon energy systems.
Vijay A, Hawkes A, 2017, The techno-economics of small-scale residential heating in low carbon futures, Energies, Vol: 10, ISSN: 1996-1073
Existing studies that consider the techno-economics of residential heating systems typically focus on their performance within present-day energy systems. However, the energy system within which these technologies operate will need to change radically if climate change mitigation is to be achieved. This article addresses this problem by modelling small-scale heating techno-economics in the context of significant electricity system decarbonisation. The current electricity market price regime based on short run marginal costs is seen to provide a very weak investment signal for electricity system investors, so an electricity price regime based on long run marginal energy costs is also considered, using a case study of the UK in 2035. The economic case for conventional boilers remains stronger in most dwelling types. The exception to this is for dwellings with high annual heat demand. Sensitivity studies demonstrate the impact of factors such as price of natural gas, carbon intensity of the central grid and thermodynamic performance. Fuel cell micro combined heat and power shows most potential under the long run electricity price regime, and heat pumps under the short run electricity price regime. This difference highlights the importance of future electricity market structure on consumer choice of heating systems in the future.
Clark R, Budinis S, Hawkes A, et al., 2017, Analysis of power production and emission reduction through the use of biogas and carbon capture and storage, Computer Aided Chemical Engineering
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