The negative consequences of rising global energy use have led governments and businesses to pursue methods of reducing reliance on fossil fuels. Plug-In Hybrid Electric Vehicles (PHEVs) and wind power represent two practical methods for mitigating some of these negative consequences. PHEVs use large onboard batteries to displace gasoline with electricity obtained from the grid, while wind power generates clean, renewable power that has the potential to displace fossil-fuel power generation. The emissions reductions realized by these technologies will be highly dependent on the energy system into which they are integrated, and also how they are integrated. This research aims to assess to cost of reducing emissions through the integration of PHEVs and wind power in three Canadian jurisdictions, namely British Columbia, Ontario and Alberta. An Optimal Power Flow (OPF) model is used to assess the changes in generation dispatch resulting from the integration of wind power and PHEVs into the local electricity network. This network model captures the geographic distribution of load and generation in each jurisdiction, while simulating local transmission constraints. A linear optimization model is developed in the MATLAB environment and is solved using the ILOG CPLEX Optimization package. The model solves a 168-hour generation scheduling period for both summer and winter conditions. Simulation results provide the costs and emissions from power generation when various levels of PHEVs and/or wind power are added to the electricity system. The costs and emissions from PHEV purchase and gasoline displacement are then added to the OPF results and an overall GHG reduction cost is calculated. Results indicate that wind power is an expensive method of GHG abatement in British Columbia and Ontario. This is due to the limited environmental benefit of wind over the nuclear and hydro baseload mixtures. The large premium paid for displacing hydro or nuclear power with wind power does little to reduce emissions, and thus CO2e costs are high. PHEVs are a cheaper method of GHG abatement in British Columbia and Ontario, since the GHG reductions resulting from the substitution of gasoline for hydro or nuclear power are significant. In Alberta, wind power is the cheaper method of GHG abatement because wind power is closer in price to the coal and natural gas dominated Alberta mixture, while offering significant environmental benefits. PHEVs represent a more expensive method of GHG abatement in Alberta, since substituting gasoline for expensive, GHG-intense electricity in a vehicle does less to reduce overall emissions. Results also indicate that PHEV charging should take place during off-peak hours, to take advantage of surplus baseload generation. PHEV adoption helps wind power in Ontario and British Columbia, as overnight charging reduces the amount of cheap, clean baseload power displaced by wind during these hours. In Alberta, wind power helps PHEVs by cleaning up the generation mixture and providing more environmental benefit from the substitution of gasoline with electricity.

Cuba has vast natural resources for domestic renewable energy generation, but their energy mix is heavily dominated by fossil fuels. This contributes to a high dependence on expensive oil imports and has led to significant generation shortfalls, which in turn has resulted in extensive power outages and serious fuel crises. Additionally, large amounts of CO2 emissions are generated from power generation based on oil or gas. George Washington is a small industrial town in the Villa Clara province in Cuba that frequently experiences these problems. It holds a rum factory, a sugar mill, and a small residential area containing 710 households. The implementation of a microgrid utilizing the available solar, wind, and biomass potential could work to simultaneously reduce the town's dependence on energy imports, increase the renewable electricity share, and increase self-sufficiency of the electricity demand, enabling the industries and residential area to access energy services even when the national grid is not delivering power. By examining different potential microgrid configurations in HOMER Pro, an optimal system was decided based on cost parameters such as CAPEX and NPV, the self-sufficiency share of the electricity consumed, and the available potential to utilize domestic natural resources as well as the available workforce able to operate such a system. Because of Cuba's difficulties in accessing investment capital, a low CAPEX, high self-sufficiency index, and a high NPV was considered the best possible system. The scenario that best correlated with this outcome was the Middle Road scenario. By considering the area limiations of George Washington, one model run of the Middle Road scenario produced a system with additional solar PV (2.9 MW) and wind capacity (9.2 MW) paired with the already existing 6 MW of bagasse-fired CHP capacity in the sugar mill and 688 kW of solar PV capacity. It had a low investment cost of $34 million USD, a high NPV at $112 million USD, and a self-sufficiency index at 91.33%. Another model run of the Middle Road scenario that didn't take avaliable area into consideration produced a microgrid with an additional 43.1 MW of wind capacity. This model run had an NPV of $292 million USD, an investment cost of $79 million USD, and a self-sufficiency index of 94%. By implementing more capacity than this in the 100% Self-sufficient scenario, the self-sufficiency index reached a maximum of 100%, but had a lower NPV at $282 million USD, and a much higher investment cost of $1.324 billion USD. These scenarios only used biomass, solar, or wind energy for microgrid electricity generation, and therefore only consumed fossil fuels when importing electricity from the grid. / Kuba har en stor mängd naturliga resurser för att generera förnybar energi, men deras energimix idag domineras av fossilt bränsle. Landet är beroende av att importera dyr olja, vilket bidrar till en otillräcklig inhemsk energiproduktion samt många timmars strömavbrott och svåra bränslebrister. Stora mängder CO2-utsläpp genereras även när olja eller gas används för kraftproduktion. George Washington är en liten industriell by som ligger i provinsen Villa Clara, i Kuba, och som ofta får erfara dessa problem. I byn finns det en romfabrik, en sockerkvarn och ett litet bostadsområde som består av 710 hem. Installationen av ett microgrid som utnyttjar lokal solenergi, vindenergi samt biomassa kan minska byns beroende av importerad energi, öka andelen förnybar energi samt öka självförsörjningen av elbehovet. Ett sådant microgrid skulle möjliggöra byns tillgång till viktiga energitjänster även när det nationella nätverket inte har möjlighet att leverera elektricitet. Genom att undersöka flera olika microgridkonfigurationer i mjukvaruverktyget HOMER Pro valdes ett optimalt system baserat på parametrarna CAPEX, NPV, självförsörjningsgraden av den konsumerade elektriciteten, potentialen att använda sig av de lokala naturresurserna samt tillgängligheten av arbetskraft för att kunna driva ett sådant nätverkssystem. På grund av de begränsade tillgångarna till investeringskapital i Kuba så blev ett lågt CAPEX, hög självförsörjning samt ett högt NPV viktiga parametrar för att utse det bästa möjliga systemet. Det scenario som genererade system som bäst stämde överens med dessa egenskaper är Middle Road-scenariot. För att undersöka potentialen hos systemet och samtidigt ta hänsyn till den begränsade landtillgången i George Washingtons närområde så kördes en av systemsimuleringarna av Middle Road-scenariot med en areabegränsning i HOMER Pro. Detta resulterade i ett system med ytterligare 2.9 MW kapacitet från solpaneler, 9.2 MW vindkraft tillsammans med de redan existerande 6 MW av bagasse-drivna turbiner i sockerkvarnen samt de 688 kW av solpaneler som är installerade på romfabrikens tak. Systemet har en investeringskostnad (CAPEX) på $34 miljoner USD, ett högt NPV på $112 miljoner USD och ett självförsörjningsindex på 91.33%. När systemsimuleringen av Middle Road inte tog hänsyn till tillgänglig landyta så blev resultatet att det bästa systemet hade ytterligare 43.1 MW av vindkraft. Detta system har ett NPV på $292 miljoner USD, en investeringskostnad på $79 miljoner USD och ett självförsörjningsindex på 94%. Genom att implementera en högre kapacitet i 100% Self-sufficient-scenariot så blev resultatet ett självförsörjandeindex på 100%, men samtidigt ett lägre NPV på $282 miljoner USD och en mycket högre investeringskostnad på $1.324 miljarder USD. I dessa scenarion så används biomassa, solenergi samt vindenergi för generering av elektricitet i microgridet och konsumtion av fossilt bränsle sker endast när elektricitet importeras från det nationella elnätverket.

In response to growing concerns regarding global warming and climate change, reduction of CO2 emissions becomes a priority for many countries, especially the developed ones such as the UK. Residential applications are considered among the most important areas for substantial reduction of CO2 emissions because they represent a major part of the total consumed energy in those countries. For instance, in the UK, residential applications are currently accountable for about 150 Mt CO2 emissions, which represents approximately 25% of the whole CO2 emissions [1-2]. In order to achieve a significant CO2 reduction, many strategies must be adopted in the policy of these countries. One of these strategies is to introduce micro combined heat and power (μCHP) systems into residential energy systems, since they offer several advantages over traditional systems. A significant amount of research has been carried out in this field; however, in terms of integrating such systems into residential energy systems, significant work is yet to be conducted. This is because of the complexity of these systems and their interdependency on many uncertain variables, energy demand of a house is a case in point. In order to achieve such integration, this research focuses on the optimisation and operation of μCHP systems in residential energy systems as essential steps towards integration of these systems, so it deals with the optimisation and operation of a μCHP system within a building taking into account that the system is grid-connected in order to export or import electricity in certain cases. A comprehensive review that summarises key points that outline the trend of previous research in this field has been carried out. The reviewed areas include: technologies used as residential μCHP units, modelling of the μCHP systems, sizing of μCHP systems and operation strategies used for such systems. To further this, a generic model for sizing of μCHP system’s components to meet different residential application has been developed by the author. Two different online operation strategies of residential μCHP systems, namely: an online linear programming optimiser (LPO) and a real time fuzzy logic operation strategy (FLOS) have been developed. The performance of the novel online operation strategies, in terms of their ability to reduce operation costs, has been evaluated. Both the LPO and the FLOS were found to have their advantages when compared with the traditional operation strategies of μCHP systems in terms of operation costs and CO2 emissions. This research should therefore be useful in informing design and operation decisions during developing and implementing μCHP technologies in residential applications, especially single dwellings.

As part of the transition towards a fully sustainable energy system, green hydrogen shows great potential to decarbonise several hard-to-abate sectors. To provide the fossil-free electricity required for electrolysis, offshore wind power has emerged as a suggested option. In this report, four scenarios using different electrolyser placements and technologies are compared and applied in a 30-year case study considering a 1 GW offshore wind farm in the Baltic Sea. The scenarios are evaluated through the optimisation of electrolyser capacities, full system modelling and simulation, a techno-economic assessment, as well as a literature review of technological readiness, safety aspects and operational considerations. It is shown that a range of installed capacities offers only slight differences in levelised costs and that the optimal sizes to a large part depend on future electrolyser cost developments. A 1:1 sizing ratio between electrolyser capacity and maximum available power is not suggested for any of the studied configurations. Further, the simulations indicate that electrolyser inefficiencies constitute 63.2–68.5% of the total energy losses. Power transmission losses are relatively small due to the short transmission distance, while the power demands of several subsystems are nearly insignificant. Onshore H2 production using an alkaline electrolyser system is highlighted, offering the highest system efficiency and largest hydrogen production, at 55.93% and 2.23 Mton, respectively. This setup is further shown to be the most cost-efficient, offering a levelised cost of hydrogen at 3.15 €/kgH2. However, obstacles in the form of social and environmental concerns and regulations are seemingly larger compared to the scenarios using offshore electrolysis. Further, rapid future cost developments for electrolysers are likely to strengthen the case for offshore and PEM electrolyser configurations. A range of research opportunities are highlighted to fill the identified knowledge gaps and enable further insights. / Como parte de la transicion hacia un sistema energético totalmente sostenible, el hidrógeno verde muestra un gran potencial para descarbonizar varios sectores en los que es difíciles de conseguir. La energía eólica marina ha surgido como una opción para suministrar la electricidad libre de fósiles necesaria para la electrólisis. En este informe se comparan y aplican cuatro escenarios que utilizan diferentes ubicaciones y tecnologías de electrolizadores en un estudio de caso a 30 aoñs que considera un parque eólico marino de 1 GW en el Mar Báltico. Los escenarios se evalúan mediante una optimización de la capacidad de los electrolizadores, la modelización y simulación de todo el sistema, una revisión bibliográfica de la disponibilidad tecnológica, teniendo en cuenta los aspectos de seguridad y las consideraciones operativas. Se demuestra que una gama de capacidades instaladas ofrece sólo ligeras diferencias en los costes nivelados y que los tamaños óptimos dependen en gran medida de la evolución futura de los costes de los electrolizadores. No se recomienda una relación de tamaño de 1:1 entre entre la capacidad del electrolizador y la potencia máxima disponible. Además, las simulaciones indican que las ineficiencias del electrolizador constituyen entre el 63,2% y el 68,5% de las pérdidas totales de energía. Las pérdidas de transmisión de energía son relativamente pequeñas debido a la corta distancia de transmisión, mientras que las demandas de energía de varios subsistemas son casi insignificantes. Destaca la producción de H2 en tierra utilizando un sistema de electrolizador alcalino, que ofrece la mayor eficiencia del sistema y la mayor producción de hidrógeno, con un 55,93% y 2,23 Mton respectivamente. Además, este sistema es el más rentable, con un coste nivelado del hidrógeno de 3,15 €/kgH2. Sin embargo, los obstáculos sociales, medioambientales y normativos parecen ser mayores que en el caso de la electrólisis en alta mar. Además, es probable que la rápida evolución de los costes de los electrolizadores refuerce las configuraciones de electrolizadores marinos y PEM. Se destacan en el documento una serie de oportunidades de investigación con el fin de completar el estado del arte identificado.

As part of the transition towards a fully sustainable energy system, green hydrogen shows great potential to decarbonise several hard-to-abate sectors. To provide the fossil-free electricity required for electrolysis, offshore wind power has emerged as a suggested option. In this report, four scenarios using different electrolyser placements and technologies are compared and applied in a 30-year case study considering a 1 GW offshore wind farm in the Baltic Sea. The scenarios are evaluated through the optimisation of electrolyser capacities, full system modelling and simulation, a techno-economic assessment, as well as a literature review of technological readiness, safety aspects and operational considerations. It is shown that a range of installed capacities offers only slight differences in levelised costs and that the optimal sizes to a large part depend on future electrolyser cost developments. A 1:1 sizing ratio between electrolyser capacity and maximum available power is not suggested for any of the studied configurations. Further, the simulations indicate that electrolyser inefficiencies constitute 63.2–68.5% of the total energylosses. Power transmission losses are relatively small due to the short transmission distance, while the power demands of several subsystems are nearly insignificant. Onshore H2 production using an alkaline electrolyser system is highlighted, offering the highest system efficiency and largest hydrogen production, at 55.93% and 2.23 Mton, respectively. This setup is further shown to be the most cost-efficient, offering a levelised cost of hydrogen at 3.15 €/kgH2. However, obstacles in the form of social and environmental concerns and regulations are seemingly larger compared to the scenarios using offshore electrolysis. Further, rapid future cost developments for electrolysers are likely to strengthen the case for offshore and PEM electrolyser configurations. A range of research opportunities are highlighted to fill the identified knowledge gaps and enable further insights. / Como parte de la transición hacia un sistema energético totalmente sostenible, el hidrógeno verde muestra un gran potencial para descarbonizar varios sectores en los que es difíciles de conseguir. La energía eólica marina ha surgido como una opción para suministrar la electricidad libre de fósiles necesaria para la electrólisis. En este informe se comparan y aplican cuatro escenarios que utilizan diferentes ubicaciones y tecnologías de electrolizadores en un estudio de caso a 30 años que considera un parque eólico marino de 1 GW en el Mar Báltico. Los escenarios se evalúan mediante una optimización de la capacidad de los electrolizadores, la modelización y simulación de todo el sistema, una revisión bibliográfica de la disponibilidad tecnológica, teniendo en cuenta los aspectos de seguridad y las consideraciones operativas. Se demuestra que una gama de capacidades instaladas ofrece sólo ligeras diferencias en los costes nivelados y que los tamaños óptimos dependen en gran medida de la evolución futura de los costes de los electrolizadores. No se recomienda una relación de tamaño de 1:1 entre entre la capacidad del electrolizador y la potencia máxima disponible. Además, las simulaciones indican que las ineficiencias del electrolizador constituyen entre el 63,2% y el 68,5% de las pérdidas totales de energía. Las pérdidas de transmisión de energía son relativamente pequeñas debido a la corta distancia de transmisión, mientras que las demandas de energía de varios subsistemas son casi insignificantes. Destaca la producción de H2 en tierra utilizando un sistema de electrolizador alcalino, que ofrece la mayor eficiencia del sistema y la mayor producción de hidrógeno, con un 55,93% y 2,23 Mton respectivamente. Además, este sistema es el más rentable, con un coste nivelado del hidrógeno de 3,15 €/kgH2. Sin embargo, los obstáculos sociales, medioambientales y normativos parecen ser mayores que en el caso de la electrólisis en alta mar. Además, es probable que la rápida evolución de los costes de los electrolizadores refuerce las configuraciones de electrolizadores marinos y PEM. Se destacan en el documento una serie de oportunidades de investigacin ócon el fin de completar el estado del arte identificado.