Concerns over both environmental issues and about the depletion of fossil fuels have acted as twin driving forces to the development of renewable energy and its integration into existing electricity grids. The variable nature of RE generators assessment affects the ability to balance supply and demand across electricity networks; however, the use of energy storage and demand-side response techniques is expected to help relieve this situation. One possibility in this regard might be the use of water electrolysis to produce hydrogen while producing industrial-scale DSR services. This would be facilitated by the use of tariff structures that incentive the operation of electrolysers as dispatchable loads. This research has been carried out to answer the following question: What is the feasibility of using electrolysers to provide industrial-scale of Demand-side Response for grid balancing while producing hydrogen at a competitive price? The hydrogen thus produced can then be used, and indeed sold, as a clean automotive fuel. To these ends, two common types of electrolyser, alkaline and PEM, are examined in considerable detail. In particular, two cost scenarios for system components are considered, namely those for 2015 and 2030. The coastal city of Darnah in Libya was chosen as the basis for this case study, where renewable energy can be produced via wind turbines and photovoltaics (PVs), and where there are currently six petrol stations serving the city that can be converted to hydrogen refuelling stations (HRSs). In 2015 all scenarios for both PEM and alkaline electrolysers were considered and were found to be able to partly meet the project aims but with high cost of hydrogen due to the high cost of system capital costs, low price of social carbon cost and less government support. However, by 2030 the price of hydrogen price will make it a good option as energy storage and clean fuel for many reasons such as the expected drop in capital cost, improvement in the efficiency of the equipment, and the expectation of high price of social carbon cost. Penetration of hydrogen into the energy sector requires strong governmental support by either establishing or modifying policies and energy laws to increasingly support renewable energy usage. Government support could effectively bring forward the date at which hydrogen becomes techno-economically viable (i.e. sooner than 2030).

In this study a roof-top PVT/absorption chiller system is modeled for a hotel building in Antalya, Turkey to cover the cooling demand of the hotel, to produce electricity and domestic hot water. PVT modules, an absorption chiller, a hot storage tank and a natural gas fired auxiliary heater are the main components of the system. Elecetrical power produced by the system is 94.2 MWh, the cooling power is 185.5 MWh and the amount of domestic hot water produced in the system is 65135 m3 at 45 0C annually.  Even though the systems is capable of meeting the demands of the hotel building, because of the high investment costs of PVT modules and high interest rates in Turkey, it is not economically favorable. Using cheaper solar collectors, integrating a cold storage unit in the system or having an improved conrol strategy are the options to increase the system efficiency and to make the system economically competitive.

To decrease global warming, bioenergy with carbon capture and storage (Bio-CCS) has been proposed as an effective and necessary tool. Combusting biomass and capturing carbon dioxide (CO2) from the same process results in net negative emissions, hence, reducing the concentration of CO2 in the atmosphere. The infrastructure around heat and power generation in Sweden has transformed to make use of biomass and waste. Bio-CCS has the potential to be a key factor in making the heat sector carbon negative and the Swedish energy system more sustainable. This study has assessed how Bio-CCS can practically be implemented in the Uppsala heat and power plant. In the assessment, three chemical absorption post-combustion carbon capture (CC) technologies were evaluated based on energy requirement, potential to reduce emissions and economics. They are the amine process, the chilled ammonia process (CAP) and the hot potassium carbonate process (HPC). The process of each technology was modelled by performing mass and energy balance calculations when implementing CC on the flue gas streams of the production units using biomass-based fuel at the plant. The modelling enabled finding specific heating, cooling and electricity requirements of the technologies. With this data it was possible to assess the potential emission reduction and CC cost for the different configurations assessed. A solution was proposed in how a CC technology can be integrated into the system of the Uppsala plant regarding land footprint, available heat supply to the process and possibilities for waste heat recovery. If heat recovery is not utilized the results show that the amine process is the most cost-effective technology when implemented on the flue gas stream of the waste blocks. When utilizing heat recovery to use waste heat to heat the district heating water, CAP becomes more cost-effective than the amine process. Further improvements can be achieved by combining flue gas streams of the waste blocks to increase the number of hours per year CC can be performed. The plant in Uppsala can then capture 200 000 tonne CO2 annually. The total cost of Bio-CCS will be approximately 900 SEK per tonne CO2 captured. / För att minska den globala uppvärmningen har infångning och lagring av koldioxid från förbränning av biomassa (Bio-CCS) föreslagits som ett effektivt och nödvändigt verktyg. Förbränning av biomassa och infångande av koldioxid från samma process leder till negativa nettoutsläpp, vilket minskar koncentrationen av koldioxid (CO2) i atmosfären. Infrastrukturen kring värme- och kraftproduktion i Sverige har omvandlats till att använda biomassa och avfall. Bio-CCS har potential att vara en nyckelfaktor för att göra värmesektorn koldioxidnegativ och det svenska energisystemet mer hållbart. Denna studie har analyserat hur Bio-CCS praktiskt kan implementeras i Uppsalas kraftvärmeverk. I analysen utvärderades tre infångningstekniker av typen kemisk absorption baserat på energibehov, potential att minska utsläpp och ekonomi. Teknikerna är aminprocessen, chilled ammonia process (CAP) och hot potassium carbonate process (HPC). Processen för varje teknik modellerades genom att utföra mass- och energibalansberäkningar vid infångning av CO2 från rökgasströmmarna producerade av produktionsenheterna som förbränner biomassa. Modelleringen gjorde det möjligt att hitta specifika värme-, kyl- och elbehov för teknikerna. Med dessa data var det möjligt att bedöma den potentiella utsläppsminskningen och kostnaden för infångning för de olika konfigurationer som har analyserats. En lösning föreslogs i hur en infångningsanläggning kan integreras i kraftvärmeverkets system när det gäller markanvändning, tillgänglig värmeförsörjning till processen och möjligheter till återvinning av spillvärme. Om värmeåtervinning inte utnyttjas visar resultaten att aminprocessen är den mest kostnadseffektiva tekniken när den implementeras på rökgasströmmen från avfallsblocken. När man använder värmeåtervinning för att använda spillvärme för att värma fjärrvärmevattnet blir CAP mer kostnadseffektivt än aminprocessen. Ytterligare förbättringar kan uppnås genom att kombinera rökgasströmmar från avfallsblocken för att öka antalet timmar per år infångning kan utföras. Anläggningen i Uppsala kan då årligen fånga 200 000 ton CO2. Den totala kostnaden för Bio-CCS kommer att vara cirka 900 SEK per ton infångad CO2.

Several CO2 transcritical booster systems in supermarkets use the potential of integrating geothermal storage, enabling subcooling during warm climate conditions as well as being a heat source during cold climate conditions. First of all, field measurements of one of these systems located in Sweden were analysed with particular focus on the heat-recovery performance. The best theoretical operational strategy was compared to the one really implemented and the differences in the annual energy usage were assessed through modelling. The results show that an alternative to the best theoretical operational strategy exists; heat can be extracted from the ground while low-temperature heat is rejected by the gas cooler. Such an alternative strategy has important technical advantages with a negligible increment of the energy usage. In the second part of this work, the benefits of geothermal subcooling were evaluated. Applying the BIN hours method, it was demonstrated that this system is expected to save on average roughly 5% of the total power consumption, in Stockholm’s climate. The models utilized for the winter and summer season were combined to find the relationship between geothermal storage size and annual energy savings. In this way, it was possible to calculate the present value of the operational savings for the study case. Furthermore, a general methodology for assessing the economic feasibility of this system solution is presented. Finally, several scenarios were investigated to produce parametric curves and to perform a sensitivity analysis. Comparing the results with the typical Swedish prices for boreholes, the cases where this system solution is economically justified were identified. These are supermarkets with a Heat Recovery Ratio (HRR) higher than the average. For examples, supermarkets supplying heat to the neighbouring buildings (considering the Stockholm’s climate, systems with an annual average HRR of at least 70%). Relying only on savings from subcooling was found to be not enough to justify a geothermal storage, a not-negligible amount of heat must be extracted in winter. Finally, some interesting concepts and alternatives to a geothermal integration are presented to point out relevant future work.

Many countries strengthen their commitments to reduce greenhouse gas emissions to limit climate change and meet the Paris Agreement (Masson-Delmotte et al., 2019). Commitments include achieving net-zero emissions or in some cases even negative emissions (Government offices of Sweden, 2020a; United Nations, 2021a). To achieve these goals, carbon dioxide capture, utilization, and storage (CCUS) is considered as an essential strategy. Carbon capture storage and utilization are recognized methods of reducing or avoiding greenhouse gas emissions (IEA, 2019a, 2020). However, the uncertainty regarding costs, financial incentives, and pricing is impeding adoption. Further information is needed for CCUS concepts both in respect to cost estimates and required market prices for CCUS, this to provide guidance for decision makers and market actors. In this report a study has investigated the economic feasibility of three CCUS concepts for a biogas facility. One CCS concept where CO2 was captured and liquefied on-site to be transported to a terminal for shipping and end storage injection. The CCS concept annual capacity was ~16 500 ton net stored CO2. Two CCU concepts were considered, where synthetic natural gas (SNG) was produced via biologic methanation with on-site produced hydrogen, both with annual production of ~88 GWh SNG. A techno-economic assessment (TEA) was carried out where the key cost-drivers were identified, and the economic feasibility assessed. With performance and cost estimates for each process step in the different considered concepts a model was built where a cash flow was created and a net present value (NPV) could be calculated. The study found transportation to be the most prominent cost driver for CCS where shipping and storage represented 57 % of the total cost of CO2 removal. The cost driver for CCU concepts was found to be hydrogen production, where the electricity for the electrolyser constituted 65 % of the total cost of produced SNG. None of the concepts were found economic feasible when the Swedish market was considered. The break-even price for CO2 removal in the CCS concept was found to be 151 €/ton, just above the assumed base value used in this study. As the voluntary market is still undeveloped it is difficult to know what price that could be expected, however, in discussion with market experts a range between 150-200 €/ton would not be unthinkable for the concept studied. For the CCU concepts to be economically feasible, the estimated minimum price levels for SNG were 184 and 193 €/MWh respectively. Comparing to the benchmark price of diesel of 125 €/MWh, both CCU concepts were concluded to be unfeasible. The sensitivity analysis showed that the CCU concepts were very sensitive to variations in electricity price. When the German fuel market was considered, all studied concepts yielded a positive business case. CCS was the only concept showing economic feasibility, while the CCU concepts remained unfeasible. In the German market a GHG reduction quota credit was accounted for which was valued higher than the carbon removal credits in the voluntary market. / Många länder stärker sina åtaganden att minska utsläppen av växthusgaser för att begränsa klimatförändringen och uppfylla Parisavtalet (Masson-Delmotte et al., 2019). I åtagandena ingår att uppnå nettonollutsläpp eller i vissa fall till och med negativa utsläpp (Regeringskansliet, 2020a; FN, 2021a). För att uppnå dessa mål anses avskiljning, nyttjande och lagring av koldioxid (CCUS) vara en viktig strategi. Avskiljning, lagring och utnyttjande av koldioxid är erkända metoder för att minska eller undvika utsläpp av växthusgaser (IEA, 2019a, 2020). Osäkerheten kring kostnader, ekonomiska incitament och prissättning hindrar dock införandet. Ytterligare information behövs för CCUS-koncept både när det gäller kostnadsberäkningar och nödvändiga marknadspriser för CCUS, detta för att ge vägledning för beslutsfattare och marknadsaktörer. I den här rapporten undersöks den ekonomiska genomförbarheten av tre CCUS-koncept för en biogasanläggning. Ett CCS-koncept där koldioxid avskiljs och kondenseras på plats för att sedan transporteras till en terminal för slutlig sjöfrakt och injektion i geologiskt lager. Den årliga kapaciteten för CCS-konceptet var ~16 500 ton nettolagrad koldioxid. Två CCU-koncept övervägdes, där syntetisk natur gas (SNG) producerades genom biologisk metanisering med vätgas producerad på plats, där båda koncepten hade en årlig produktion av ~88 GWh SNG. En tekno-ekonomisk undersökning genomfördes där de viktigaste kostnadsdrivande faktorerna identifierades och den ekonomiska genomförbarheten bedömdes. Med hjälp av prestanda- och kostnadsberäkningar för varje processteg i de olika tänkta koncepten byggdes en modell där ett kassaflöde skapades och ett netto-nuvärde kunde beräknas. I studien konstaterades att transport var den mest framträdande kostnadsdrivande faktorn för CCS, där sjöfrakt och lagring stod för 57 % av den totala kostnaden för koldioxidavskiljning. Kostnadsdrivande för CCU-konceptet var vätgasproduktionen, där el till elektrolysen utgjorde 65 % av den totala kostnaden för producerad SNG. Inget av koncepten befanns vara ekonomiskt genomförbart när den svenska marknaden beaktades. Nollpunktspriset för koldioxidavskiljning i CCS-konceptet fanns vara 151 euro/ton, vilket är strax över det antagna basvärde som används i denna studie. Eftersom den frivilliga marknaden fortfarande är outvecklad är det svårt att veta vilket pris som kan förväntas, men i diskussioner med marknadsexperter skulle ett prisintervall på 150-200 €/ton inte vara otänkbart för det studerade konceptet. För att CCU-koncepten ska vara ekonomiskt genomförbara var de uppskattade minimipriserna för SNG 184 respektive 193 €/MWh. Jämfört med referenspriset för diesel på 125 €/MWh, ansågs båda CCU-koncepten vara ekonomiskt ogenomförbara. Känslighetsanalysen visade att CCU-koncepten var mycket känsliga för variationer i elpriset. När den tyska bränslemarknaden beaktades gav alla studerade koncept ett positivt netto-nuvärde. CCS konceptet var det enda konceptet som ansågs vara ekonomiskt genomförbart, medan CCU-koncepten förblev ogenomförbara. På den tyska marknaden räknades en kvot för minskning av växthusgasutsläpp in, som värderades högre än de krediter för avskiljning av koldioxid som fanns på den frivilliga marknaden.

Over recent years, political, technological, environmental and economic factors have combined to increase interest in distributed energy resources (DER), and flexibility in the power system. As a resource which is both distributed and flexible, flexible demand (FD) can be considered to be particularly of interest. However, due to many facets of its nature, understanding the available flexibility, and potential value of that flexibility, is difficult. Further, understanding the effects of FD exploitation on other multi-energy system actors, given the complex nature of modern liberalised energy systems, complicates the picture further. These factors form material obstructions to the assessment of FD, for example, for the construction of business cases. To address these gaps this thesis first assesses the nature and value of various applicable current and potential markets and charging/incentive regimes, before detailing a novel multi-energy domestic demand simulation model, capable of modelling, in detail, domestic FD resources. Subsequently, a multi-commodity stochastic energy/reserve optimisation model, capable of modelling various DERs and taking into account price signals related to various energy-related commodities and services (including user utility) is specified. The separation of price components for application at different aggregation levels, which is applied in the optimisation model, also informs the described value mapping methodology, which illustrates the impacts of any, particularly demand-side, intervention on the wider multi-energy system. The power of the above detailed contributions are demonstrated through various studies, which show the physical and economic impact of various demand side interventions and of greater market participation by FD resources.

Global carbon emissions are higher than ever before and in the last decade of 21st century, focus has shifted on reducing these emissions in various ways possible. Carbon capture, utilization and storage (CCUS) has been identified as one of the important ways to reduce carbon emissions and meet climate targets. For a long time, Sweden has promoted the use of biomass as fuel for heat and power generation which has enabled it to meet its climate targets earlier than projected. Now, major Swedish energy companies are looking into coupling exiting biomass fired heat and power plants with CCUS. This opens up the possibility of attaining negative emissions, also known as Bio Energy Carbon Capture and Storage (BECCS). With the right policy framework in place, BECCS can be a major boon and help Sweden attaining net zero carbon emissions. As a contribution in meeting net zero targets, this thesis is aimed to evaluate the installation of a carbon capture plant to abate flue gas emissions from District heating facility in Jordbro which is a ~70 MW (fuel) CHP plant running on biomass.  Among the available carbon capture technologies, Calcium oxide-based carbon capture has been expected to show great promise due to its lower environmental impacts and possibility to extract high quality energy when installed. Hence a concept system for integration calcium looping at Jordbro has been developed through the use of modeling tools like ASPEN. A techno economic assessment was needed to be performed to give conclusive results on the overall viability of the process. Further, key process indicators like energy penalty, plant footprint and cost of capture per tonne of CO2 were identified for making the final evaluation. Finally, through a strategic collaboration with SaltX, major process improvements were introduced and applied to the modeled process.  It was concluded that with the current average flowrates at Jordbro it was possible to capture 154,000 tonnes of CO2 annually. The required amount of energy input to the calciner is 48MW (7.29 MW/kg-CO2 captured) which is one of the major findings of this study. Even though a significant amount of heat is recovered, the main boiler is not capable of producing heat over 900 οC and additional biomass needs to be combusted, leading to an additional CO2 emission of about 125 000 tonnes annually. Considering an optimal integration, the energy penalties became 6.25 %.  However, the plant footprint increased substantially due to requirement for burning additional biomass in the regeneration reactor and addition of several auxiliary units that come along with calcium-based carbon capture. Further, the total capital investment for this project is 1,219 MSEK with reactor costs being most capital intensive. Assuming a plant life of 25 years, the cost of capture per tonne of CO2 (excluding the costs for carbon transport and storage) was evaluated at 988 SEK, which is 58% higher than the reference Mono-ethanol amine based chemical absorption case. The innovative improvements from SaltX substantially reduced the plant footprint but capture costs did not reduce since material transport costs proved to be the major bottleneck.  Upon comparison of this technology with the amine-based technology it was found that Calcium oxide-based carbon capture would need further research and improvements to be more viable than amine-based carbon capture. Integration of thermal energy storage and process intensification can be the possible paths for further improvement.

The Paris Agreement has ambitious targets to limit the global warming below 1.5 °Cin the 21st century. This goal is reflected in the national climate targets, for example, Sweden aims to achieve net zero greenhouse gas emissions by 2045, and thereafter achieve negative emissions. One of the pivotal ways to achieve these goals is by applying the mature bioenergy with carbon capture and storage (BECCS) technology to large-scale industries that emit CO2. Around 6% of the global emissions arise from the pulp and paper industry making them one of the largest localized emitters of biogenic CO2. This makes them suitable for retrofitting BECCS technologies and post-combustion capture (PCC) is one among them. This study presents a techno-economic assessment of an absorption-based PCC unit in SCA Östrand pulp mill. Chemical absorption using MEA and chilled ammonia process (CAP) using NH3 as the solvent are considered in this study. For both the processes, mass and energy balances using Aspen HYSYS were done and validated against published data in literature. Heat integration by applying excess or waste heat from the mill is also considered in this work. CO2 capture from flue gas originating from various emission sources in the mill (recovery boiler, lime kiln and multi-fuel boiler) are considered in different combinations in the analysis. The main key performance indicator (KPI) evaluated in this work is the cost of CO2capture for all the different cases for both the MEA- and chilled NH3-based absorption processes. The minimum cost of CO2 capture for MEA-based absorption process was found to be in the range 37-41 €/tCO2 and for CAP, it was found to be in the range 73-81 €/tCO2. For MEA-based absorption process, the excess low pressure steam from the mill satisfies the steam demand in all the cases, except the one where CO2 is captured from all the three emission sources. For CAP, sufficient excess low pressure steam is present in the mill for all the capture cases due to a lower reboiler duty compared to MEA-based absorption process. An optimal process configuration and capture scenario for the existing design conditions in the mill are derived and justified. A sensitivity analysis was carried out to find the associated bottlenecks from the breakdown of the cost of CO2 capture for each process. The overall BECCS cost is also sensitive to CO2 transport & storage costs. However, it is also clear that incentives for negative emissions will make BECCS an attractive solution for the pulp and paper industry.

No description available.

Hydrogen can be produced from biomass; this hydrogen is called biohydrogen. Biohydrogen produced in Western Canada can partially contribute to meeting the demand for hydrogen needed for bitumen upgrading. Gasification and pyrolysis are two promising pathways for producing biohydrogen in a large-scale plant. Syngas, produced from the gasification of biomass, and bio-oil, produced from fast pyrolysis of biomass, can be steam reformed to produce biohydrogen. The cost of biohydrogen delivered by pipeline to a distance of 500 km is $2.20 per kg of H2, assuming that a plant utilizes 2000 dry tonnes of whole-tree biomass per day processing it in a Battelle Columbus Laboratory (BCL) gasifier. For forest residue- and straw-based biohydrogen plants the values are similar: $2.19 and $2.31 per kg of H2, respectively. Maximum economy of scale benefits are realized for biohydrogen production plants capable of processing 2000 and 3000 dry tonnes per day using BCL and GTI (Gas Technology Institute) gasification technology, respectively. The cost of biohydrogen from fast pyrolysis ($2.47 per kg of H2 from a 2000 dry tonne per day plant), using forest residue as the feedstock, is higher than the cost of biohydrogen produced by gasification. Carbon credits of about $120-$140 per tonne of CO2 are required to make biohydrogen competitive with natural-gas-based hydrogen.